Safety Evaluation Report

With Open Items Related to the License Renewal of 

Seabrook Station

Docket Number 50-443

NextEra Energy Seabook, LLC

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

June 2012

iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Seabrook Station 

(Seabrook) license renewal application (LRA) by the U.S. Nuclear Regulatory Commission 

(NRC) staff (the staff). By letter dated May 25, 2010, NextEra Energy Seabook, LLC (the 

applicant), submitted the LRA in accordance with Title 10, Part 54, of the Code of Federal 

Regulations, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants.” 

NextEra Energy Seabrook, LLC requests renewal of the operating license (Facility Operating 

License Number NPF-86) for a period of 20 years beyond the current license period of

March 15, 2030. Seabrook is located in the Town of Seabrook, Rockingham County, New 

Hampshire, on the western shore of Hampton Harbor, 2 miles west of the Atlantic Ocean. The 

station is approximately 2 miles north of the Massachusetts state line and approximately 

15 miles south of the Maine state line.

A zero-power license was granted to the facility in October 1986, and a full-power operating 

license was subsequently granted on March 15, 1990. Seabrook previously sought and 

received a modification to the expiration of the facility operating license to recapture the time 

licensed at zero-percent power. The unit is a 4-loop pressurized-water reactor (PWR) design. 

General Electric Company supplied the nuclear steam supply system. Westinghouse

constructed the plant. The licensed power output of the unit is 3,648 megawatts thermal, with a 

gross electrical output of approximately 1,245 megawatts electric. This SER presents the status 

of the staff’s review of information submitted through May 16, 2012. The staff identified seven

open items that must be resolved before any final determination can be made on the LRA. SER 

Section 1.5 summarizes the open items. The staff will present its final conclusion on the LRA 

review in an update to this SER.

v

TABLE OF CONTENTS

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

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

TABLE OF TABLES................................................................................................................. xiv

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

1.6 Summary of Confirmatory Items........................................................................1-6

1.7 Summary of Proposed License Conditions........................................................1-6

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 ...........................................2-2

2.1.3.1 Implementing Procedures and Documentation Sources Used 

for Scoping and Screening .................................................2-3

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

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

2.1.3.4 Scoping and Screening Program Review Conclusion .........2-7

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) ..2-10

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ..2-21

2.1.4.4 Plant Level Scoping of Systems and Structures ...............2-25

2.1.4.5 Mechanical Scoping .........................................................2-27

2.1.4.6 Structural Scoping ............................................................2-29

2.1.4.7 Electrical Component Scoping..........................................2-30

2.1.4.8 Scoping Methodology Conclusion.....................................2-31

2.1.5 Screening Methodology....................................................................2-31

2.1.5.1 General Screening Methodology ......................................2-31

2.1.5.2 Mechanical Component Screening...................................2-33

2.1.5.3 Structural Component Screening......................................2-34

2.1.5.4 Electrical Component Screening.......................................2-35

2.1.5.5 Screening Methodology Conclusion .................................2-36

2.1.6 Summary of Evaluation Findings ......................................................2-37

2.2 Plant Level Scoping Results ...........................................................................2-37

2.2.1 Introduction ......................................................................................2-37

2.2.2 Summary of Technical Information in the Application .......................2-37

2.2.3 Staff Evaluation ................................................................................2-37
2.2.4 Conclusion .......................................................................................2-38

2.3 Scoping and Screening Results: Mechanical Systems....................................2-38

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ..................2-39

2.3.1.1 Reactor Coolant System...................................................2-39

2.3.1.2 Reactor Vessel.................................................................2-41

2.3.1.3 Reactor Vessel Internals ..................................................2-42

2.3.1.4 Steam Generator..............................................................2-42

2.3.2 Engineered Safety Features.............................................................2-43

2.3.2.1 Combustible Gas Control System.....................................2-44

2.3.2.2 Containment Building Spray System ................................2-44

2.3.2.3 Residual Heat Removal System .......................................2-45

2.3.2.4 Safety Injection System ....................................................2-46

2.3.3 Auxiliary Systems .............................................................................2-47

2.3.3.1 Auxiliary Boiler..................................................................2-48

2.3.3.2 Boron Recovery System...................................................2-49

2.3.3.3 Chemical and Volume Control System .............................2-50

2.3.3.4 Chlorination System .........................................................2-52

2.3.3.5 Containment Air Handling System....................................2-52

2.3.3.6 Containment Air Purge System.........................................2-53

2.3.3.7 Containment Enclosure Air Handling System ...................2-54

2.3.3.8 Containment Online Purge System...................................2-55

2.3.3.9 Control Building Air Handling System ...............................2-55

2.3.3.10 Demineralized Water System ...........................................2-56

2.3.3.11 Dewatering System ..........................................................2-57

2.3.3.12 Diesel Generator ..............................................................2-58

2.3.3.13 Diesel Generator Air Handling System .............................2-59

2.3.3.14 Emergency Feedwater Pump House Air Handling System2-59

2.3.3.15 Fire Protection System .....................................................2-60

2.3.3.16 Fuel Handling System ......................................................2-69

2.3.3.17 Fuel Oil System................................................................2-69

2.3.3.18 Fuel Storage Building Air Handling System ......................2-70

2.3.3.19 Hot Water Heating System ...............................................2-71

2.3.3.20 Instrument Air System ......................................................2-73

2.3.3.21 Leak Detection System.....................................................2-75

2.3.3.22 Mechanical Seal Supply System.......................................2-76

2.3.3.23 Miscellaneous Equipment.................................................2-77

2.3.3.24 Nitrogen Gas System .......................................................2-77

2.3.3.25 Oil Collection for Reactor Coolant Pumps System............2-78

2.3.3.26 Plant Floor Drain System..................................................2-78

2.3.3.27 Potable Water System......................................................2-80

2.3.3.28 Primary Auxiliary Building Air Handling System ................2-81

2.3.3.29 Primary Component Cooling Water System .....................2-82

2.3.3.30 Radiation Monitoring System............................................2-85

2.3.3.31 Reactor Makeup Water System........................................2-86

2.3.3.32 Release Recovery System ...............................................2-86

2.3.3.33 Resin Sluicing System......................................................2-87

2.3.3.34 Roof Drains System..........................................................2-87

2.3.3.35 Sample System ................................................................2-88

2.3.3.36 Screen Wash System.......................................................2-89

2.3.3.37 Service Water System......................................................2-90

2.3.3.38 Service Water Pump House Air Handling System ............2-92
vii

2.3.3.39 Spent Fuel Pool Cooling System ......................................2-93

2.3.3.40 Switchyard........................................................................2-95

2.3.3.41 Valve Stem Leak off System.............................................2-96

2.3.3.42 Vent Gas System .............................................................2-98

2.3.3.43 Waste Gas System...........................................................2-99

2.3.3.44 Waste Processing Liquid System ...................................2-100

2.3.3.45 Waste Processing Liquid Drains System ........................2-101

2.3.4 Steam and Power Conversion Systems .........................................2-102

2.3.4.1 Auxiliary Steam System..................................................2-103

2.3.4.2 Auxiliary Steam Condensate System..............................2-104

2.3.4.3 Auxiliary Steam Heating System.....................................2-105

2.3.4.4 Circulating Water System ...............................................2-105

2.3.4.5 Condensate System .......................................................2-106

2.3.4.6 Feedwater System..........................................................2-107

2.3.4.7 Main Steam System (Includes Main Steam 

Drain System).................................................................2-109

2.3.4.8 Steam Generator Blowdown System ..............................2-110

2.4 Scoping and Screening Results: Structures ..................................................2-111

2.4.1 Buildings, Structures within License Renewal.................................2-112

2.4.1.1 Summary of Technical Information in the Application .....2-112

2.4.1.2 Staff Evaluation ..............................................................2-112

2.4.1.3 Conclusion .....................................................................2-115

2.4.2 Containment Structures..................................................................2-115

2.4.2.1 Summary of Technical Information in the Application .....2-115

2.4.2.2 Conclusion .....................................................................2-115

2.4.3 Fuel Handling and Overhead Cranes .............................................2-116

2.4.3.1 Summary of Technical Information in the Application .....2-116

2.4.3.2 Conclusion .....................................................................2-116

2.4.4 Miscellaneous Yard Structures.......................................................2-116

2.4.4.1 Summary of Technical Information in the Application .....2-116

2.4.4.2 Conclusion .....................................................................2-117

2.4.5 Primary Structures..........................................................................2-117

2.4.5.1 Summary of Technical Information in the Application .....2-117

2.4.5.2 Conclusion .....................................................................2-118

2.4.6 Supports.........................................................................................2-118

2.4.6.1 Summary of Technical Information in the Application .....2-118

2.4.6.2 Staff Evaluation ..............................................................2-118

2.4.6.3 Conclusion .....................................................................2-120

2.4.7 Turbine Building .............................................................................2-120

2.4.7.1 Summary of Technical Information in the Application .....2-120

2.4.7.2 Conclusion .....................................................................2-120

2.4.8 Water Control Structures ................................................................2-120

2.4.8.1 Summary of Technical Information in the Application .....2-120

2.4.8.2 Conclusion .....................................................................2-121

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems........................................................................................................2-121

2.5.1 Electrical Component Groups.........................................................2-122

2.5.1.1 Summary of Technical Information in the Application .....2-122

2.5.1.2 Staff Evaluation ..............................................................2-122

2.5.1.3 Conclusion .....................................................................2-123

2.6 Conclusion for Scoping and Screening .........................................................2-123
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 Aging Management Programs............................3-5

3.0.2.2 Review of Aging Management Review Results...................3-6

3.0.2.3 Updated Final Safety Analysis Report Supplement.............3-7

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

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

3.0.3.1 Aging Management Programs Consistent with the Generic 

Aging Lessons Learned Report ........................................3-11

3.0.3.2 Aging Management Programs Consistent with the GALL 

Report with Exceptions or Enhancements ........................3-48

3.0.3.3 Aging Management Programs Not Consistent with or Not 

Addressed in the GALL Report.......................................3-149

3.0.4 Quality Assurance Program Attributes Integral to Aging Management 

Programs........................................................................................3-181

3.0.4.1 Summary of Technical Information in the Application .....3-181

3.0.4.2 Staff Evaluation ..............................................................3-181

3.0.4.3 Conclusion .....................................................................3-182

3.0.5 Operating Experience.....................................................................3-182

3.0.5.1 Summary of Technical Information in the Application .....3-182

3.0.5.2 Staff Evaluation ..............................................................3-183

3.0.5.3 UFSAR Supplement .......................................................3-184

3.0.5.4 Conclusion .....................................................................3-185

3.1 Aging Management of Reactor Coolant System............................................3-185

3.1.1 Summary of Technical Information in the Application .....................3-185

3.1.2 Staff Evaluation ..............................................................................3-186

3.1.2.1 Aging Management Review Results That Are Consistent with 

the GALL Report ............................................................3-203

3.1.2.2 Aging Management Review Results That Are Consistent with 

the GALL Report for Which Further Evaluation is 

Recommended...............................................................3-213

3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed 

in the GALL Report.........................................................3-231

3.1.3 Conclusion .....................................................................................3-235

3.2 Aging Management of Engineered Safety Features ......................................3-235

3.2.1 Summary of Technical Information in the Application .....................3-235

3.2.2 Staff Evaluation ..............................................................................3-235

3.2.2.1 Aging Management Review Results Consistent with the 

GALL Report ..................................................................3-245

3.2.2.2 Aging Management Review Results Consistent with the 

GALL Report for Which Further Evaluation 

is Recommended ...........................................................3-251

3.2.2.3 Aging Management Review Results Not Consistent with or 

Not Addressed in the GALL Report ................................3-263

3.2.3 Conclusion .....................................................................................3-266

3.3 Aging Management of Auxiliary Systems ......................................................3-267

3.3.1 Summary of Technical Information in the Application .....................3-268
ix

3.3.2 Staff Evaluation ..............................................................................3-268

3.3.2.1 Aging Management Review Results Consistent with the 

GALL Report ..................................................................3-285

3.3.2.2 Aging Management Review Results Consistent with the 

GALL Report for Which Further Evaluation 

is Recommended ...........................................................3-306

3.3.2.3 Aging Management Review Results Not Consistent with or 

Not Addressed in the GALL Report ................................3-333

3.3.3 Conclusion .....................................................................................3-387

3.4 Aging Management of Steam and Power Conversion Systems.....................3-387

3.4.1 Summary of Technical Information in the Application .....................3-387

3.4.2 Staff Evaluation ..............................................................................3-387

3.4.2.1 Aging Management Review Results Consistent with the 

GALL Report ..................................................................3-395

3.4.2.2 Aging Management Review Results Consistent with the 

GALL Report for Which Further Evaluation 

is Recommended ...........................................................3-409

3.4.2.3 Aging Management Review Results Not Consistent with or 

Not Addressed in the GALL Report ................................3-421

3.4.3 Conclusion .....................................................................................3-432

3.5 Aging Management of Containments, Structures, and Component Supports 3-433

3.5.1 Summary of Technical Information in the Application .....................3-433

3.5.2 Staff Evaluation ..............................................................................3-433

3.5.2.1 Aging Management Review Results Consistent with the 

GALL Report ..................................................................3-447

3.5.2.2 Aging Management Review Results Consistent with the 

GALL Report for Which Further Evaluation 

is Recommended ...........................................................3-457

3.5.2.3 Aging Management Review Results Not Consistent with or 

Not Addressed in the GALL Report ................................3-474

3.6 Aging Management of Electrical and Instrumentation and Controls ..............3-479

3.6.1 Summary of Technical Information in the Application .....................3-479

3.6.2 Staff Evaluation ..............................................................................3-479

3.6.2.1 Aging Management Review Results Consistent with the 

GALL Report ..................................................................3-483

3.6.2.2 Aging Management Review Results Consistent with the 

GALL Report for which Further Evaluation 

is Recommended ...........................................................3-484

3.6.2.3 Aging Management Review Results Not Consistent with or 

Not Addressed in the GALL Report ................................3-486

3.6.3 Conclusion .....................................................................................3-488

3.7 Conclusion for AMR Results .........................................................................3-488

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 .........................4-1

4.1.2 Staff Evaluation ..................................................................................4-1

4.1.2.1 Evaluation of the Applicant’s Identification of TLAAs ..........4-2

4.1.2.2 Evaluation of the Applicant’s Identification of those 

Exemptions in the CLB that are based on TLAAs ...............4-3

4.1.3 Conclusion .........................................................................................4-4
4.2 RPV Neutron Embrittlement..............................................................................4-5

4.2.1 RPV Fluence ......................................................................................4-5

4.2.1.1 Summary of Technical Information in the Application .........4-5

4.2.1.2 Staff Evaluation ..................................................................4-6

4.2.1.3 FSAR Supplement..............................................................4-9

4.2.1.4 Conclusion .........................................................................4-9

4.2.2 USE Analyses ..................................................................................4-10

4.2.2.1 Summary of Technical Information in the Application .......4-10

4.2.2.2 Staff Evaluation ................................................................4-10

4.2.2.3 UFSAR Supplement .........................................................4-11

4.2.2.4 Conclusion .......................................................................4-11

4.2.3 PTS Analyses...................................................................................4-11

4.2.3.1 Summary of Technical Information in the Application .......4-11

4.2.3.2 Staff Evaluation ................................................................4-12

4.2.3.3 UFSAR Supplement .........................................................4-13

4.2.3.4 Conclusion .......................................................................4-13

4.2.4 Reactor Vessel P-T Limit and LTOP Analyses .................................4-13

4.2.4.1 Summary of Technical Information in the Application .......4-13

4.2.4.2 Staff Evaluation ................................................................4-14

4.2.4.3 UFSAR Supplement .........................................................4-14

4.2.4.4 Conclusion .......................................................................4-14

4.3 Metal Fatigue Analysis of Piping and Components .........................................4-14

4.3.1 NSSS Pressure Vessel and Component Fatigue Analyses (RPV and 

RPV Component Fatigue Analyses) .................................................4-15

4.3.1.1 Summary of Technical Information in the Application .......4-15

4.3.1.2 Staff Evaluation ................................................................4-15

4.3.1.3 UFSAR Supplement .........................................................4-20

4.3.1.4 Conclusion .......................................................................4-21

4.3.2 Supplementary ASME Section III, Class 1 Piping and Component 

Fatigue Analysis ...............................................................................4-21

4.3.2.1 Absence of a TLAA for Thermal Stresses in Piping 

Connected to RCSs: NRC Bulletin 88 08..........................4-21

4.3.2.2 NRC Bulletin 88 11, PSL Thermal Stratification................4-23

4.3.3 RVIs Aging Management..................................................................4-25

4.3.3.1 Summary of Technical Information in the Application .......4-25

4.3.3.2 Staff Evaluation ................................................................4-25

4.3.3.3 UFSAR Supplement .........................................................4-31

4.3.3.4 Conclusion .......................................................................4-31

4.3.4 Environmentally Assisted Fatigue Analysis.......................................4-31

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

4.3.4.2 Staff Evaluation ................................................................4-32

4.3.4.3 UFSAR Supplement .........................................................4-36

4.3.4.4 Conclusion .......................................................................4-37

4.3.5 Steam Generator Tube, Loss of Material and Fatigue 

Usage from FIV................................................................................4-37

4.3.5.1 Summary of Technical Information in the Application .......4-37

4.3.5.2 Staff Evaluation ................................................................4-38

4.3.5.3 UFSAR Supplement .........................................................4-40

4.3.5.4 Conclusion .......................................................................4-40
xi

4.3.6 Absence of TLAAs for Fatigue Crack Growth, Fracture Mechanics 

Stability, or Corrosion Analysis Supporting Repair of 

Alloy 600 Materials ...........................................................................4-41

4.3.6.1 Summary of Technical Information in the Application .......4-41

4.3.6.2 Staff Evaluation ................................................................4-41

4.3.6.3 UFSAR Supplement .........................................................4-42

4.3.6.4 Conclusion .......................................................................4-42

4.3.7 Non Class 1 Component Fatigue Analyses ......................................4-42

4.3.7.1 Summary of Technical Information in the Application .......4-42

4.3.7.2 Staff Evaluation ................................................................4-43

4.3.7.3 UFSAR Supplement .........................................................4-44

4.3.7.4 Conclusion .......................................................................4-44

4.4 Environmental Qualification (EQ) of Electrical Equipment...............................4-45

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

4.4.2 Staff Evaluation ................................................................................4-45

4.4.3 UFSAR Supplement. ........................................................................4-46

4.4.4 Conclusion. ......................................................................................4-47

4.5 Concrete Containment Tendon Pre stress ......................................................4-47

4.5.1 Summary of Technical Information in the Application .......................4-47

4.5.2 Staff Evaluation ................................................................................4-47

4.5.3 UFSAR Supplement .........................................................................4-47

4.5.4 Conclusion .......................................................................................4-47

4.6 Containment Liner Plate Fatigue Usage and Containment Penetration 

Pressurization Cycles .....................................................................................4-47

4.6.1 Containment Liner Plate Fatigue Usage ...........................................4-47

4.6.1.1 Summary of Technical Information in the Application .......4-47

4.6.1.2 Staff Evaluation ................................................................4-48

4.6.1.3 UFSAR Supplement .........................................................4-49

4.6.1.4 Conclusion .......................................................................4-49

4.6.2 Pressurization Cycles: Personnel Airlock, Equipment Hatch, and Fuel 

Transfer Tube Assembly Absence of TLAA for Containment 

Penetrations .....................................................................................4-50

4.6.2.1 Summary of Technical Information in the Application .......4-50

4.6.2.2 Staff Evaluation ................................................................4-50

4.6.2.3 UFSAR Supplement .........................................................4-52

4.6.2.4 Conclusion .......................................................................4-52

4.7 Other Plant Specific TLAA ..............................................................................4-53

4.7.1 Absence of a TLAA for RPV Underclad Cracking Analyzes..............4-53

4.7.1.1 Summary of Technical Information in the Application .......4-53

4.7.1.2 Staff Evaluation ................................................................4-53

4.7.1.3 Conclusion .......................................................................4-54

4.7.2 RCP Flywheel Fatigue Crack Growth Analyses ................................4-54

4.7.2.1 Summary of Technical Information in the Application .......4-54

4.7.2.2 Staff Evaluation ................................................................4-54

4.7.2.3 UFSAR Supplement .........................................................4-56

4.7.2.4 Conclusion .......................................................................4-56

4.7.3 Leak-Before-Break Analyses ............................................................4-56

4.7.3.1 Summary of Technical Information in the Application .......4-56

4.7.3.2 Staff Evaluation ................................................................4-57

4.7.3.3 UFSAR Supplement .........................................................4-59

4.7.3.4 Conclusion .......................................................................4-60
4.7.4 High-Energy Line Break Postulation Based on CUF.........................4-60

4.7.4.1 Summary of Technical Information in the Application .......4-60

4.7.4.2 Staff Evaluation ................................................................4-60

4.7.4.3 UFSAR Supplement .........................................................4-62

4.7.4.4 Conclusion .......................................................................4-63

4.7.5 Fuel Transfer Tube Bellows Design Cycles ......................................4-63

4.7.5.1 Summary of Technical Information in the Application .......4-63

4.7.5.2 Staff Evaluation ................................................................4-63

4.7.5.3 UFSAR Supplement .........................................................4-64

4.7.5.4 Conclusion .......................................................................4-64

4.7.6 Crane Load Cycle Limits ..................................................................4-65

4.7.6.1 Polar Gantry Crane...........................................................4-65

4.7.6.2 Cask Handling Crane .......................................................4-66

4.7.7 Service Level I Coatings Qualification ..............................................4-67

4.7.7.1 Summary of Technical Information in the Application .......4-67

4.7.7.2 Staff Evaluation ................................................................4-68

4.7.7.3 FSAR Supplement............................................................4-68

4.7.7.4 Conclusion .......................................................................4-69

4.7.8 Absence of a TLAA for RCP: Code Case N 481...............................4-69

4.7.8.1 Summary of Technical Information in the Application .......4-69

4.7.8.2 Staff Evaluation ................................................................4-69

4.7.8.3 UFSAR Supplement .........................................................4-70

4.7.8.4 Conclusion .......................................................................4-70

4.7.9 Canopy Seal Clamp Assemblies ......................................................4-70

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

4.7.9.2 Staff Evaluation ................................................................4-70

4.7.9.3 UFSAR Supplement .........................................................4-72

4.7.9.4 Conclusion .......................................................................4-73

4.7.10 Hydrogen Analyzer...........................................................................4-73

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

4.7.10.2 Staff Evaluation ................................................................4-73

4.7.10.3 UFSAR Supplement .........................................................4-74

4.7.10.4 Conclusion .......................................................................4-74

4.7.11 Mechanical Equipment Qualification.................................................4-75

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

4.7.11.2 Staff Evaluation ................................................................4-75

4.7.11.3 UFSAR Supplement .........................................................4-78

4.7.11.4 Conclusion .......................................................................4-78

4.7.12 Absence of a TLAA for Metal Corrosion Allowances and Corrosion 

Effects ..............................................................................................4-78

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

4.7.12.2 Staff Evaluation ................................................................4-78

4.7.12.3 UFSAR Supplement .........................................................4-79

4.7.12.4 Conclusion .......................................................................4-80

4.7.13 Absence of a TLAA for Inservice Flaw Growth Analyses that 

Demonstrate Structural Stability for 40 Years ...................................4-80

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

4.7.13.2 Staff Evaluation ................................................................4-80

4.7.13.3 Conclusion .......................................................................4-82

4.7.14 Diesel Generator Thermal Cycle Evaluation .....................................4-82

4.7.14.1 Summary of Technical Information in the Application .......4-82
xiii

4.7.14.2 Staff Evaluation ................................................................4-82

4.7.14.3 UFSAR Supplement .........................................................4-84

4.7.14.4 Conclusion .......................................................................4-84

4.7.15 Steam Generator Tube Wall Wear from FIV.....................................4-84

4.7.15.1 Summary of Technical Information in the Application .......4-84

4.7.15.2 Staff Evaluation ................................................................4-84

4.7.15.3 UFSAR Supplement .........................................................4-86

4.7.15.4 Conclusion .......................................................................4-86

4.8 Overall Conclusion..........................................................................................4-86

SECTION 5 Review by the Advisory Committee on Reactor Safeguards.................................5-1

SECTION 6 Conclusion ...........................................................................................................6-1

Appendix A Seabrook Station License Renewal Commitments...............................................A-1

Appendix B Chronology ..........................................................................................................B-1

Appendix C Principal Contributors...........................................................................................C-1

Appendix D References ..........................................................................................................D-1
xiv

LIST OF TABLES

Table 1.4 1. Current interim staff guidance..............................................................................1-6

Table 3.0 1. Aging management programs .............................................................................3-7

Table 3.0.3.3.1-1 Buried Piping Inspections ........................................................................3-162

Table 3.1 1. Staff evaluation for reactor vessel, reactor vessel internals, and reactor coolant 

system components in the GALL Report..............................................................................3-186

Table 3.2 1. Staff evaluation for engineered safety features systems components 

in the GALL Report ..............................................................................................................3-236

Table 3.3 1. Staff evaluation for auxiliary system components in the GALL Report .............3-269

Table 3.4 1. Staff evaluation for steam and power conversion systems components 

in the GALL Report ..............................................................................................................3-388

Table 3.5 1. Staff evaluation for structures and component supports components 

in the GALL Report ..............................................................................................................3-434

Table 3.6 1. Staff evaluation for electrical and instrumentation and controls 

in the GALL Report ..............................................................................................................3-480
xv

ABBREVIATIONS

AC alternating current

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ADAMS Agencywide Document Access and Management System

AERM aging effect requiring management

AFW auxiliary feedwater

AMP aging management program

AMR aging management review

AMS ATWS mitigation system

ANS American Nuclear Society

ANSI American National Standards Institute

APCSB Auxiliary and Power Conversion Systems Branch

AR action request

ART adjusted reference temperature

ASCE American Society of Civil Engineers

ASFPC alternate spent fuel pool cooling

ASM American Society for Metals

ASME American Society of Mechanical Engineers

ASR alkali-silica reaction

AST alternate source term

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

AWS American Welding Society

AWWA American Water Works Association

B&PV boiler and pressure vessel

B&W Babcock & Wilcox Company

B10 boron-10

BTP Branch Technical Position

BWR boiling-water reactor

C Celsius

CASS cast austenitic stainless steel

CC primary component cooling water system

CEA control element assembly

cfm cubic feet per minute

CFR Code of Federal Regulations
Abbreviations

xvi

CL chlorination system

CLB current licensing basis

cm2 squared centimeter

CMTR certified material test record

CO2 carbon dioxide

CR condition report

CRD control rod drive

CRDM control rod drive mechanism

CSR cable spreading room

CSS containment spray system

CST condensate storage tank

Cu copper

CUF cumulative fatigue usage

CUFEN environmentally-correct CUF

CuNi copper nickel

CVCS chemical and volume control system

DBA design-basis accident

DBD design-basis document

DBE design-basis event

DCI division of component integrity

EAF environmentally-assisted fatigue

ECCS emergency core cooling system

EDB equipment database

EDG emergency diesel generator

EFPH emergency feedwater pump house

EFPD effective full power days 

EFPY effective full power years

EFW emergency feedwater

EOL end-of-life

EPA Environmental Protection Agency

EPRI Electrical Power Research Institute

EQ environmental qualification

ER environmental report

ESF engineered safety feature

ESFAS engineered safety features actuation system

F Fahrenheit

FA fire area

FEN environmental life correction factor
Abbreviations

xvii

FERC Federal Energy Regulatory Commission

FIV flow-induced vibration

FPL Florida Power and Light Company

FR Federal Register

FRN Federal Register Notice

FSAR final safety analysis report

ft foot

gal. gallon

GALL Generic Aging Lessons Learned

GDC general design criterion

GEIS generic environmental impact statement

GL generic Letter

gpm gallons per minute

GSI generic safety issue

GSU generator step-up

H2 hydrogen

HELB high-energy line break

HLSN hot leg surge line nozzle

HPSI high-pressure safety injection

HVAC heating, ventilation, and air conditioning

I&C instrumentation and control

IASCC irradiation-assisted stress corrosion cracking

IEEE Institute of Electronic and Electrical Engineers

IGSCC intergranular stress corrosion cracking

IN information notice

INPO Institute of Nuclear Plant Operation

IPA integrated plant assessment 

ISA independent safety analysis

ISG interim staff guidance

ISI inservice inspection

ksi kips per square inch

kV kilovolt

L liter

lb pound

LBB leak-before-break

LOCA loss-of-coolant accident 
Abbreviations

xviii

LOOP loss of offsite power

LRA license renewal application

LTOP low temperature overpressure protection

MC metal containment

MEAP material, environment, aging effects, and aging management program

MEB metal enclosed bus

MEQ mechanical equipment qualification

MeV million electron-volts

mg milligram

MIC microbiologically-influenced corrosion

MRP Materials Reliability Program

MRule Maintenance Rule

MSIP mechanical stress improvement process

MSL mean sea level

MWt megawatt thermal

n/cm2 neutrons per square centimeter

NACE National Association of Corrosion Engineers

NaOH sodium hydroxide

NEI Nuclear Energy Institute

NextEra NextEra Energy Seabrook, LLC

NFPA National Fire Protection Association

NNS non-nuclear safety

NPS nominal pipe size

NRC U.S. Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

NSAS non-safety affecting safety

NSSS nuclear steam supply system

OBE operating basis earthquake

ODSCC outside-diameter stress corrosion cracking

OEM original equipment manufactorer

OTSG once-through steam generator

P&ID piping and instrumentation diagram

PAH primary auxiliary building air handling

ppb parts per billion

ppm parts per million

PRT penetration resistance test

psi pounds per square inch
Abbreviations

xix

psig pounds per square inch gauge

PSL pressurizer surge line

PSN pressurizer surge nozzle

P-T pressure-temperature

PTS pressurized thermal shock

PVC polyvinyl chloride

PVDF polyvinylidene flouride

PWR pressurized-water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance

QAP Quality Assurance Program

RAI request for additional information

RAT reserve auxiliary transformer

RCCA rod cluster control assembly

RCIC reactor core isolation cooling

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG regulatory guide

RHR residual heat removal

RIS regulatory issue summary

RM radiation monitoring system

RPS reactor protection system

RPV reactor pressure vessel

RS resin sluicing system

RTD resistance temperature detectors

RTNDT nil-ductility reference temperature

RTPTS PTS reference temperature

RV reactor vessel

RVI reactor vessel internals

RVID Reactor Vessel Integrity Database

RWST refueling water storage tank

SBO station blackout

SC structure and component

SCC stress corrosion cracking

SCFM standard cubic feet per minute

Seabrook Seabrook Station Unit 1

SER safety evaluation report
Abbreviations

xx

SF6 sulfur hexaflouride

SFP spent fuel pool 

SG steam generator

SI safety injection

SO2 sulfur dioxide

SOC Statement of Consideration

SRP-LR Standard Review Plan–License Renewal 

SSC system, structure, and component

SSE safe shutdown earthquake

SSPS solid state protection system

The Rule Requirements for Renewal of Operating Licenses for Nuclear Power Plants

TLAA time-limited aging analysis

TS technical specification

TSTF technical specification task force

UAT unit auxiliary transformers

UFSAR updated final safety analysis report

USE upper-shelf energy

UT ultrasonic testing

V volt

WCAP Westinghouse Commercial Atomic Power

WG waste gas system

WL waste processing liquid system

WLD waste processing liquid drains system

WOG Westinghouse Owners Group

Zn zinc
1

SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1

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

Seabrook Station Unit 1 (Seabrook), as filed by NextEra Energy Seabrook, LLC (the applicant). 

By letter dated May 25, 2010, the applicant submitted its application to the U.S. Nuclear 

Regulatory Commission (NRC) for renewal of the Seabrook Station Unit 1 operating license for 

an additional 20 years. The NRC staff (the staff) prepared this report to summarize the results 

of its safety review of the LRA for compliance with Title 10, Part 54, “Requirements for Renewal 

of Operating Licenses for Nuclear Power Plants,” of the Code of Federal Regulations

(10 CFR Part 54). The NRC project manager for the license renewal review is Arthur Cunanan. 

Mr. Cunanan may be contacted by telephone at 301-415-3897, or by electronic mail at 

Introduction

arthur.cunanan@nrc.gov

Division of License Renewal

US Nuclear Regulatory Commission

Washington, D.C. 20555-0001

Attention: Arthur Cunanan, Mail Stop O11-F1

. Alternatively, written correspondence may be sent to the following 

address:

In its letter dated May 25, 2010, submission letter, the applicant requested renewal of the 

operating license issued under Section 103 (Operating License No. NPF-86) of the Atomic 

Energy Act of 1954, as amended, for Seabrook Station Unit 1 for a period of 20 years beyond 

the current expiration at midnight on March 15, 2030. Seabrook Station is located in Seabrook, 

New Hampshire on the western shore of Hampton Harbor, two miles west of the Atlantic Ocean. 

The NRC issued a zero power license in October 1986 and a full power operating license was 

subsequently granted on March 15, 1990. Seabrook Station employs a pressurized water 

reactor housed in a steel lined reinforced concrete containment structure which is enclosed by a 

reinforced concrete containment enclosure structure. The licensed power output was 

3,411MWt; however, after implementing two power uprates, the rated thermal power has been 

increased to 3,648 MWt. The updated final safety analysis report (UFSAR) contains 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 Seabrook Station license renewal is based on the applicant’s LRA and on its 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 and other docketed 

correspondence. Unless otherwise noted, the staff reviewed and considered information 

submitted through May 16, 2012. The staff reviewed information received after that 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 (301-415-4737/800-397-4209). The LRA may also 

be viewed at Seabrook Library located at 25 Liberty Lane, Seabrook, New Hampshire 03874 or 
2

the Amesbury Public Library located at 149 Main Street, Amesbury, MA 01913. In addition, the 

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

web site at http://www.nrc.gov.

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

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

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

LRA in accordance with NRC regulations and the guidance in NUREG-1800, Revision 1, 

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

(SRP-LR), dated September 2005.

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

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

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

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

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

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

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

In accordance with 10 CFR Part 51, the staff will prepare a 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 Seabrook Station. The staff issued a draft, plant-specific GEIS Supplement in 

August 2011. The publication date of the final plant-specific GEIS Supplement is to be 

determined.

1.2

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.

License Renewal Background

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 (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 period of initial license 

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

particularly the implementation of 10 CFR 50.65, “Requirements for Monitoring the 
3

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, in 60 FR 22461, amended 10 CFR Part 54 establishes a regulatory 

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

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

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

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

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

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

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

components (SCs).

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

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

impacts of license renewal in order 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.

Pursuant to 10 CFR 54.21(d), the LRA is required to include an 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.
4

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 used the process defined in NUREG-1801, Revision 1, “Generic Aging 

Lessons Learned (GALL) Report,” dated September 2005. The GALL Report summarizes 

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

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

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

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

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

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

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

1.2.2 Environmental Review

Part 51 of 10 CFR contains regulations on environmental protection. 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 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 

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

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

the staff held public meetings on August 19, 2010 in Hampton, NH to identify plant-specific 

environmental issues. The staff issued the draft site-specific GEIS supplement on 

August 2011.The staff held another public meeting to discuss the draft, plant-specific 

supplement to the GEIS on September 15, 2011 in Hampton, NH. After considering comments 

on the draft, the staff will prepare and publish a final plant-specific GEIS supplement separately.

1.3

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

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

Principal Review Matters
5

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

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

the staff’s safety review.

Pursuant to 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.

Pursuant to 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 the following in the 

LRA:

The current indemnity agreement No. B-106 for Seabrook Station states that the 

agreement shall terminate at the time of expiration of the license. The indemnity 

agreement lists NPF-86 as the applicable license number. Should the license 

number be changed upon issuance of the renewed license, NextEra Energy 

Seabrook requests that conforming changes be made to the indemnity 

agreement to include the extended period.

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.

Pursuant to 10 CFR 54.21, “Contents of Application - Technical Information,” the NRC requires 

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

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

Pursuant to 10 CFR 54.21(b), the NRC requires that, each year following submission of the LRA 

and at least three months before the scheduled completion of the NRC 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. 

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) that are 

necessary to manage aging effects during the period of extended operation. The applicant did 

not use Appendix D, thus indicating that no changes to the Seabrook Station TS are required to 

support the LRA. 

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 through 4 document 

the staff’s evaluation of the LRA technical information.

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

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

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

findings required by 10 CFR 54.29.
6

1.4

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 GALL Report.

Interim Staff Guidance 

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

addresses them.

Table 1.4-1. Current Interim Staff Guidance

ISG Issue (Approved ISG 

Number)

Purpose SER 

Section

“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

“Aging Management of Stainless Steel 

Structures and Components in Treated 

Borated Water”

(LR-ISG-2011-01)

This final LR-ISG clarifies the staff’s existing position 

on aging management in treated borated water.

SER 

Section 3.2.2.1

1.5

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

May 16, 2012, the staff identified the following open items. 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 open item.

Summary of Open Items

OI 3.0.3.1.9-1

Due to the applicant's previous failure to maintain the annular space between the containment 

and containment enclosure buildings in a dewatered state, the staff is concerned that the 

applicant has not, until now, implemented procedures and inspection requirements to keep this 

area dewatered in the future. Accumulation of water in the annular space can potentially 

degrade the containment liner plate. The staff's concern is tracked as Open Item OI 3.0.3.1.9-1.

SER Section 3.0.3.1.9 — ASME Code Section XI, Subsection IWE Program

OI 3.0.3.2.18-1

Based on the operating experience related to concrete degradation due to alkali-silica reaction

(ASR), the staff is concerned that the applicant has not enhanced the Structures Monitoring 

Program to manage the effects of ASR. Until resolved, this issue is identified as 

OI 3.0.3.2.18-1.

SER Section 3.0.3.2.18 — Structures Monitoring Program
7

OI B.1.4-2

The applicant did not fully describe how it will use future operating experience to ensure that the 

AMPs will remain effective for managing the aging effects during the period of extended 

operation. In addition, some program descriptions contain no such statements and, for these 

AMPs, it is not clear whether the applicant intends to implement actions to monitor operating 

experience on an ongoing basis and use it to ensure the continued effectiveness of these 

AMPs. Further, the LRA does not state whether new AMPs will be developed, as necessary. 

Until resolved, this issue is identified as OI B.1.4-2.

SER Section 3.0.5 — Operating Experience

OI 3.0.3.1.7-1

In recent reviews of license renewal applications and operating experience, the NRC staff noted 

that seal cap enclosures can contain water leakage and therefore use of such enclosures 

should be accounted for in license renewal applications to ensure proper aging management. 

The applicant may have used, or currently uses, seal cap enclosures to contain water leakage. 

The staff noted that the use of such enclosures may not be accounted for in the LRA. For 

example, the environment within seal cap enclosures may be submerged, rather than the air 

environment of the original component design. Also, enclosures may prevent the direct 

inspections of bolting and component external surfaces within the Bolting Integrity and External 

Surfaces Monitoring Programs, respectively. 

SER Section 3.0.3.1.7 — Bolting Integrity Program

The staff lacks sufficient information to complete its evaluation of pressure-retaining bolting and 

component external surfaces surrounded by seal cap enclosures. Specifically, the LRA does 

not contain AMR items that address bolting and external surfaces in seal cap enclosure 

environments, which may be submerged due to ongoing leakage within the enclosure. It is also 

unclear how components within seal cap enclosures will be age-managed, since direct 

inspection is not possible. Furthermore, it is unclear to the staff whether seal cap enclosure 

configurations will be used in the period of extended operation. Until resolved, this issue is 

identified as OI 3.0.3.1.7-1.

OI 3.2.2.1-1

The LRA contains several AMR items that manage stainless steel components exposed to 

treated borated water for loss of material, cracking, and reduction of heat transfer with the Water 

Chemistry Program. However, the staff noted that the associated treated borated water 

environments may not be controlled to less than 5 parts per billion (ppb) dissolved oxygen, and 

thus, the staff lacks sufficient information to conclude that these components will be adequately 

managed. Until resolved, this issue is identified as OI 3.2.2.1-1.

SER Section 3.2.2.1 — Treated Borated Water

OI 4.2.4-1

As a part of a separate licensing action on P-T limits, the applicant requested approval of P-T 

limits that would, based on an updated neutron fluence evaluation, extend the operating time of 

the current curves from 20 EFPY to 23.7 EFPY. The staff had concerns related to whether the 

methodology used to develop the P-T limits is consistent with the requirements in 10 CFR 50, 

Appendix G. Because the methodology used to develop the P-T limits during the initial 

SER Section 4.2.4 — Pressure-Temperature Limit
8

operating period is the same as that to be used during the period of extended operation, this 

additional information is also pertinent to the review of LRA. Until resolved, this issue is 

identified as OI 4.2.4-1.

OI 3.0.3.2.2-1

The staff is concerned with the management of cracking due to primary water stress corrosion 

cracking (PWSCC) on the primary coolant side of steam generator tube-to-tubesheet welds that 

are made or cladded with nickel alloy. Also, the staff requested that the applicant provide 

information regarding its one-time inspection of the steam generator divider plate assembly in its 

UFSAR Supplement. Until resolved, this issue is identified as OI 3.0.3.2.2-1.

SER Section 3.0.3.2 — Steam Generator Tube Integrity Program

1.6

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

May 16, 2012, the staff identified no confirmatory items (CI).

Summary of Confirmatory Items

1.7

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

the applicant, the staff identified 3 proposed license conditions.

Summary of 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 

pursuant to 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 prior to the period of extended operation. The applicant shall complete these 

activities no later than six months prior to the PEO, and shall notify the NRC in writing when 

implementation of these activities is complete.

The third license condition requires that all capsules in the reactor vessel that are removed and 

tested meet the requirements of American Society for Testing and Materials (ASTM) E 185-82 

to the extent practicable for the configuration of the specimens in the capsule. Any changes to 

the capsule withdrawal schedule, including spare capsules, must be approved by the staff prior 

to implementation. All capsules placed in storage must be maintained for future insertion. Any 

changes to storage requirements must be approved by the staff, as required by 10 CFR Part 50, 

Appendix H.
2-1

SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW

2.1

2.1.1 Introduction

Scoping and Screening Methodology

Title 10, Section 54.21, “Contents of Application—Technical Information,” of the Code of Federal 

Regulations (10 CFR 54.21) requires each license renewal application (LRA) to include an 

integrated plant assessment (IPA). The IPA must list and identify all of the structures, systems, 

and components (SSCs) within the scope of license renewal and all structures and components 

(SCs) subject to an aging management review (AMR) in accordance with 10 CFR 54.4.

LRA Section 2.1, “Scoping and Screening Methodology,” describes the scoping and screening 

methodology used to identify the SSCs at the Seabrook Station Unit 1 (Seabrook) within the 

scope of license renewal and the SCs subject to an AMR. The staff reviewed the scoping and 

screening methodology of NextEra Energy Seabrook, LLC (NextEra or the applicant), to 

determine if it meets the scoping requirements of 10 CFR 54.4(a) and the screening 

requirements of 10 CFR 54.21.

In developing the scoping and screening methodology for the LRA, the applicant stated that it 

considered the following:

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

Plants” (the Rule)

• statements of consideration for the Rule (60 FR 222461)

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

Implementing the Requirements of 10 CFR Part 54—The License Renewal Rule,” dated 

June 2005 (NEI 95-10)

• correspondence between the U.S. Nuclear Regulatory Commission (NRC), other 

applicants, and NEI

2.1.2 Summary of Technical Information in the Application

In LRA Sections 2 and 3, the applicant provided the technical information required by 

10 CFR 54.4, “Scope,” and 10 CFR 54.21(a). This safety evaluation report (SER) with open 

items, contains sections entitled “Summary of Technical Information in the Application,” which 

provide information taken directly from the LRA.

In LRA Section 2.1, the applicant described the process used to identify the SSCs that meet the 

license renewal scoping criteria under 10 CFR 54.4(a) and the process used to identify the SCs 

that are subject to an AMR, as required by 10 CFR 54.21(a)(1). The applicant provided the 

results of the process used for identifying the SCs subject to an AMR in the following LRA 

sections:
Structures and Components Subject to Aging Management Review

2-2

• Section 2.2, “Plant Level Scoping Results”

• Section 2.3, “Scoping and Screening Results: Mechanical”

• Section 2.4, “Scoping and Screening Results: Structures and Structural Components”

• Section 2.5, “Scoping and Screening Results: Electrical and Instrumentation and 

Controls (I&C) Systems/Commodity Groups”

In LRA Section 3, “Aging Management Review Results,” the applicant described its aging 

management results as follows:

• Section 3.1, “Aging Management of Reactor Vessel, Internals, and Reactor Coolant 

System”

• Section 3.2, “Aging Management of Engineered Safety Features”

• Section 3.3, “Aging Management of Auxiliary Systems”

• Section 3.4, “Aging Management of Steam and Power Conversion Systems”

• Section 3.5, “Aging Management of Systems, Structures and Component Supports”

• Section 3.6, “Aging Management of Electrical and Instrumentation and Controls”

In LRA Section 4, “Time-Limited Aging Analyses,” the applicant provided its evaluation of 

time-limited aging analyses (TLAAs).

2.1.3 Scoping and Screening Program Review

The staff evaluated the LRA scoping and screening methodology in accordance with the 

guidance contained in NUREG-1800, Revision 1, “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 form the basis for the acceptance criteria for 

the scoping and screening methodology review:

• 10 CFR 54.4(a), as it relates to the identification of plant 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)(1) and 10 CFR 54.21(a)(2), as they relate to the methods used by the 

applicant to identify plant SCs subject to an AMR

As part of the review of the applicant’s scoping and screening methodology, the staff reviewed 

the activities described in the following sections of the LRA using the guidance contained in the 

SRP-LR:

• 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)

• Section 2.2, to ensure that the applicant described a process for determining the SSCs 

that are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) 

and 10 CFR 54.21(a)(2)
Structures and Components Subject to Aging Management Review

2-3

In addition, the staff conducted a scoping and screening methodology audit at Seabrook—

located in the Town of Seabrook, Rockingham County, NH, on the western shore of Hampton 

Harbor, 2 miles (mi) west of the Atlantic Ocean—during the week of September 20–23, 2010. 

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 methodologies 

described in the LRA and the requirements of the Rule. The staff reviewed implementation of 

the project-level guidelines and topical reports describing the applicant’s scoping and screening 

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

implementation and control of the license renewal program and reviewed the administrative 

control documentation used by the applicant during the scoping and screening process, the 

quality practices used by the applicant to develop the LRA, and the training and qualification of 

the LRA development team.

The staff evaluated the quality attributes of the applicant’s aging management program (AMP) 

activities described in Appendix A, “Final Safety Analysis Report Supplement,” and Appendix B, 

“Aging Management Programs,” of the LRA. On a sampling basis, the staff performed a system 

review of the diesel generator, plant floor drain system (DF), roof drain system, service water 

system, spent fuel pool system, and feedwater system, including a review of the scoping and 

screening results reports and supporting design documentation used to develop the reports. 

The purpose of the staff’s review was to ensure that the applicant had appropriately 

implemented the methodology outlined in the administrative controls and to verify that the 

results are consistent with the current licensing basis (CLB) documentation.

2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and 

Screening

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

documented in the Scoping and Screening Methodology Trip Report, dated February 4, 2011, to 

verify that the process used to identify SCs subject to an AMR was consistent with the SRP-LR. 

Additionally, the staff reviewed the scope of CLB documentation sources and the process used 

by the applicant to ensure that applicant’s commitments, as documented in the CLB and relative 

to the requirements of 10 CFR 54.4 and 10 CFR 54.21, were appropriately considered and 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)

• harsh environment equipment list

• maintenance rule (MRule) database

• design basis documents (DBDs)

• piping and instrumentation diagrams (P&IDs)

• electrical schematics

• station blackout (SBO) evaluation

• component database

• license renewal technical reports
Structures and Components Subject to Aging Management Review

2-4

2.1.3.1.2 Staff Evaluation

Scoping and Screening Implementing Procedures

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

the scope of the Rule and for determining which SCs within the scope of license renewal 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 in the LRA, including the 

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

applicant’s February 3, 2011, response to the staff’s January 5, 2011, requests for additional 

information (RAIs).

. The staff reviewed the applicant’s scoping 

and screening methodology implementing procedures, including license renewal guidelines, 

documents, and reports, as documented in the audit report, to ensure the guidance is consistent 

with the requirements of the Rule, 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 industry guidance.

After reviewing the LRA, supporting documentation and the applicant's RAI responses, 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 to provide concise guidance on the scoping and screening implementation 

process to be followed during the LRA activities.

Sources of CLB Information

During the audit, the staff reviewed pertinent information sources used by the applicant,

including the UFSAR, design basis information, and license renewal drawings. In addition, the 

applicant’s license renewal process identified additional sources of plant information pertinent to 

the scoping and screening process, including the license renewal database, controlled 

drawings, and technical correspondence, analyses, and reports. In addition, the applicant had 

collected UFSAR, design basis information, drawings and other controlled information, appliable 

to specific systems, in documents refered to as "Design Basis Documents." 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 the scope and depth of the applicant's CLB 

review to verify that the methodology is sufficiently comprehensive to identify SSCs within the 

scope of license renewal, as well as SCs requiring an AMR. Pursuant to 10 CFR 54.3(a), the 

CLB is the set of NRC requirements applicable to a specific plant and a licensee's written 

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

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

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

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

licensee commitments remaining in effect that were made in docketed licensing 

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

actions, as well as licensee commitments documented in NRC safety evaluations or licensee 

event reports.

The license renewal database, UFSAR, design basis information, and plant drawings were the 

applicant’s primary repository for system identification and component safety classification 

information. During the audit, the staff reviewed the applicant’s administrative controls for the 
Structures and Components Subject to Aging Management Review

2-5

license renewal database, design basis information, and other information sources used to 

verify system information. These controls are described, and implementation is governed, by 

plant administrative procedures. Based on a review of the administrative controls, and a sample 

of the system classification information contained in the applicable Seabrook documentation, 

the NRC staff concludes that the applicant has established adequate measures to control the 

integrity and reliability of Seabrook system identification and safety classification data. 

Therefore, the staff concludes that the information sources used by the applicant during the 

scoping and screening process provided a sufficiently controlled source of system and 

component data to support scoping and screening evaluations.

During the staff’s review of the applicant’s CLB evaluation process, the applicant explained the 

incorporation of updates to the CLB and the process used to ensure those updates are 

adequately incorporated into the license renewal database and license renewal documents. 

The staff determined that LRA Section 2.1 provided a description of the CLB and related 

documents used during the scoping and screening process that is consistent with the guidance 

contained in the SRP-LR.

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 

safety-related criteria, nonsafety-related criteria, and the regulated events criteria pursuant to 

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

documents used to support scoping and screening evaluations. The staff finds these design 

documentation sources to be useful for ensuring that the initial scope of SSCs identified by the 

applicant was consistent with the plant's CLB.

2.1.3.1.3 Conclusion

On the basis of its review of the detailed scoping and screening implementing procedures, and 

the results from the scoping and screening audit, the staff concludes that the applicant's scoping 

and screening methodology considers CLB information in a manner consistent with the Rule, 

the SRP-LR, and NEI 95-10 guidance and, therefore, is acceptable.

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

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

applicant's scoping and screening methodology considers CLB information in a manner 

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 used by the applicant to ensure that scoping and 

screening methodologies used to develop the LRA were adequately implemented. The 

applicant used the following quality control processes during the LRA development:

• using corporate and industry license renewal experience to guide the LRA development

• developing the LRA and performing associated activities using qualified and experienced 

personnel and assigning document reviewers based on subject matter expertise

• developing the LRA following NRC endorsed guidance, applicable industry standards, 

and Seabrook instructions and guidelines
Structures and Components Subject to Aging Management Review

2-6

• validating the LRA content with source documents by license renewal project leads

• reviewing the LRA using selected industry peers, the Seabrook Operations Review 

Committee, and site licensing department

• using a controlled and validated license renewal database for scoping and screening

• performing formal surveillance of LRA development activities by the Seabrook Nuclear

Oversight Department

• using the Corrective Actions Program to report discrepancies in the plant equipment 

database and drawings

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

procedures and quality control records and determined that the applicant had developed 

adequate procedures to control the LRA development and assess the results of the activities.

2.1.3.2.2 Conclusion

On the basis of its review of pertinent LRA development procedures and 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 process to ensure the guidelines and methodology for 

the scoping and screening activities were applied in a consistent and appropriate manner. As 

outlined in their implementing procedures, the applicant requires training for personnel 

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

the following:

• training and qualification of personnel preparing, verifying, and approving license 

renewal documents in accordance with documented instructions

• assigning experienced plant personnel augmented with contracted personnel with 

license renewal experience to the License Renewal Project Team

• using orientation, computer based training, activity performance, and observation to 

accomplish training

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

procedures and, on a sampling basis, reviewed completed qualification and training records and 

completed checklists for a sample of the applicant’s license renewal personnel. The staff 

determined that the applicant developed and implemented adequate procedures to control the 

training of personnel performing LRA activities.

2.1.3.3.2 Conclusion

On the basis of discussions with the applicant’s license renewal project personnel responsible 

for the scoping and screening process and its review of selected documentation in support of 
Structures and Components Subject to Aging Management Review

2-7

the process, the staff concludes that the applicant’s personnel were adequately trained and 

qualified to implement the scoping and screening methodology described in the applicant’s 

implementing procedures and the LRA.

2.1.3.4 Scoping and Screening Program Review Conclusion

On the basis of a review of information provided in LRA Section 2.1, a review of the applicant’s 

scoping and screening implementing procedures, discussions with the applicant’s license 

renewal personnel, review of the quality controls applied to the LRA development, training of 

personel participating in the LRA development, and the results from the scoping and screening 

methodology audit, the staff concludes that the applicant’s Scoping And Screening Program is 

consistent with the SRP-LR and the requirements of 10 CFR Part 54 and, therefore, is 

acceptable.

2.1.4 Plant Systems, Structures, and Components Scoping Methodology

LRA Section 2.1 described the applicant’s methodology used to scope SSCs pursuant to the 

requirements of 10 CFR 54.4(a). The LRA states that the scoping process examined all SSCs 

with respect to license renewal. According to the LRA, SSCs were evaluated against criteria 

provided in 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3) to determine if the 

item should be considered within the scope of license renewal. The LRA states that the scoping 

process identified the following SSCs:

• SSCs that are safety-related and perform or support an intended function for responding 

to a design basis event (DBE)

• SSCs that are nonsafety-related but their failure could prevent accomplishment of a 

safety-related function

• SSCs that support a specific requirement for one of the five regulated events applicable 

to license renewal

LRA 2.1 “Scoping and Screening Methodology,” stated that the scoping methodology used by 

Seabrook 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

LRA Section 2.1.2.1, “10 CFR 54.4(a)(1)—Safety-Related SSCs,” states, in part:

Systems, structures and components that perform safety functions as defined in 

10 CFR 54.4(a)(1) are within the scope of license renewal. Safety-related SSCs 

are uniquely identified at Seabrook Station. The definition of Safety Related is 

consistent with the definition in 10 CFR 54.4, as follows:

SSCs and related activities relied upon to remain functional during and following 

DBEs to ensure:

• The integrity of the reactor coolant boundary,
Structures and Components Subject to Aging Management Review

2-8

• The capability to shut down the reactor and maintain it in a safe shutdown 

condition,

• The capability to prevent or mitigate the consequences of accidents that 

could result in potential offsite exposures comparable to §50.34(a)(1), 

§50.67, or §100.11 of 10 CFR 50, as applicable. Seabrook Station has 

implemented Alternate Source Term (AST) with NRC approval. 

Therefore, §50.67 guidelines are applicable to Seabrook Station. (AST 

was not adopted for the [environmental qualification] EQ, however, the 

existing conditions are bounding.)

Components are classified as Safety Class 1, Safety Class 2, Safety Class 3, 

and non-nuclear safety (NNS) in accordance with their importance to nuclear 

safety. This importance, as established by the assigned safety class, is applied 

in the design, materials, manufacture or fabrication, assembly, erection, 

construction, and operation. A single system may have components in more 

than one safety class. The definitions of safety classes listed apply to fluid 

pressure boundary components and the reactor containment. Supports that 

have a nuclear safety function are of the same safety class as the components 

that they support. All Class 1E safety-related electrical, instrumentation and 

controls systems are Safety Class 3.

The Equipment Database (EDB) was initially used to identify the safety 

classification of systems, structures and components for license renewal per 

10 CFR 54.4(a)(1).

Seabrook Station piping and instrumentation diagrams (P&IDs), Electrical One 

Line diagrams, Civil/Architectural drawings and the UFSAR were used to identify 

components required to support in-scope system-level and structure-level 

functions. As described in UFSAR section 3.2.2.2, safety class designation 

boundaries of safety-related systems are shown on the P&IDs and described in 

the respective sections of the UFSAR. Fluid system component safety class 

designations are listed in UFSAR Table 3.2-2. The Heating, Ventilation and Air 

Conditioning (HVAC) system component safety class designations are listed in 

UFSAR Table 3.2-4.

Seabrook Station structures, systems and components important to safety, as 

well as their foundations and supports, have been designed to withstand the 

effects of an Operating Basis Earthquake (OBE) and a Safe Shutdown 

Earthquake (SSE), and are thus designated as seismic Category I.

2.1.4.1.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs relied upon 

to remain functional during and following a DBE to ensure the following functions: 

• the integrity of the reactor coolant pressure boundary

• the ability to shut down the reactor and maintain it in a safe shutdown condition

• the capability to prevent or mitigate the consequences of accidents that could result in 

potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 

10 CFR 50.67(b)(2), or 10 CFR 100.11
Structures and Components Subject to Aging Management Review

2-9

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

states, in part:

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 include external events, such as floods, storms, earthquakes, tornadoes, 

or hurricanes, and internal events, such as a high energy line break. Information 

regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter of 

the facility UFSAR, the Commission's regulations, NRC orders, exemptions, or 

license conditions within the CLB. These sources should also be reviewed to 

identify SSCs 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 

(i.e., anticipated operational occurrences, design basis accidents (DBAs), external events, and 

natural phenomena) that were applicable to Seabrook. The staff reviewed the applicant’s basis 

documents, which described all design basis conditions in the CLB and addressed all events 

defined by 10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The Seabrook UFSAR and basis 

documents discussed 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 applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) criterion in accordance with 

the license renewal implementing procedures, which provide guidance for the preparation, 

review, verification, and approval of the scoping evaluations to ensure the adequacy of the 

results of the scoping process. The staff reviewed the implementing procedures governing the 

applicant’s evaluation of safety-related SSCs and sampled the applicant’s reports of the scoping 

results to ensure that the applicant applied the methodology in accordance with the 

implementing procedures. In addition, the staff discussed the methodology and results with the 

applicant's personnel who were responsible for these evaluations.

The staff reviewed the applicant’s evaluation of the Rule and CLB definitions pertaining to 

10 CFR 54.4(a)(1), and it determined that the Seabrook 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 diesel generator, plant floor drain, roof drain system, service 

water system, spent fuel pool system, feedwater system, and turbine building to provide 

additional assurance that the applicant adequately implemented their scoping methodology with 

respect to 10 CFR 54.4(a)(1). The staff verified 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 notes that Seismic Category I SSCs are designed to remain functional if the 

safe-shutdown earthquake (SSE) ground motion occurs.

2.1.4.1.3 Conclusion

On the basis of its review of systems (on a sampling basis), discussions with the applicant, and 

review of the applicant's scoping process, the staff concludes that the applicant's methodology 
Structures and Components Subject to Aging Management Review

2-10

for identifying systems and structures 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

LRA Section 2.1.2.2, “10 CFR 54.4(a)(2)—Non-Safety Related Affecting Safety-Related SSCs,” 

states, in part:

10 CFR 54.4(a)(2) requires that all non-safety related systems, structures and 

components whose failure could prevent satisfactory accomplishment of any of 

the functions identified in §54.4(a)(1) be included within the scope of license 

renewal. These SSCs are classified non-nuclear safety (NNS) in the Seabrook 

Station UFSAR and NNS is used interchangeably with the term Non-safety 

related.

The process used at Seabrook Station for identification of Non-Safety Affecting 

Safety (NSAS) related SSCs is consistent with the NEI 95-10 “Industry Guideline 

for Implementing the Requirements of 10CFR54 – The License Renewal Rule,” 

Rev. 6, June 2005.

SSCs required by §54.4(a)(2) for Seabrook Station are included in one of the 

following four categories:

• Current Licensing Basis (CLB) Topics. The Seabrook Station CLB 

includes a number of topics that identify non-safety related SSCs credited 

for preventive or mitigative functions in support of safe shutdown for 

special events (e.g., external floods) or whose failure could prevent 

satisfactory accomplishment of a safety related function (e.g., seismic 

interactions). The CLB Topics are discussed in subsection 2.1.2.2.1.

• Non-safety related SSCs directly connected to safety related SSCs are 

discussed in sub-section 2.1.2.2.2.

• Non-safety related SSCs that are not directly connected to safety related 

SSCs but whose failure could prevent the satisfactory accomplishment of 

a safety related function due to spatial proximity. Non-Safety Related 

SSCs in spatial proximity of Safety Related SSCs are discussed in 

sub-section 2.1.2.2.3.

• A non-safety related SSC could provide functional support for a safety 

related intended function. The non-safety related SSC is required to 

function so that a safety related SSC performs its intended function (e.g., 

a non-safety related system provides cooling to a safety related pump). 

Non-Safety Related SSCs providing functional support for safety related 

SSCs are discussed in sub-section 2.1.2.2.4.

SSCs required by §54.4(a)(2) were identified by review of the Seabrook Station 

UFSAR and other CLB documentation. Plant drawings, DBDs, piping analyses, 

and the plant equipment database were also used. Plant walk downs were 

performed, as necessary, to confirm the spatial interaction boundaries.
Structures and Components Subject to Aging Management Review

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LRA Section 2.1.2.2.1 states that the Seabrook CLB includes many topics that identify 

nonsafety-related SSCs credited for preventive or mitigative functions in support of safe 

shutdown for special events. Those topics include the following:

High Energy Line Break (HELB)

At Seabrook Station, the high energy piping systems were identified using the 

criteria if the service temperature is greater than 200° [Fahrenheit] F or the 

design pressure is greater than 275 [pounds per square inch gauge] psig. A 

HELB could affect EQ Equipment in the area of the break by increasing the local 

temperature and humidity.

All high-energy lines identified in UFSAR section 3, Appendix 3I are included as 

in-scope for license renewal. High energy lines of one-inch diameter or smaller 

pipe size were excluded from the HELB analysis but still remain as a potential 

source of spray and/or leakage. All of the HELB Analysis pipe segments are 

located in buildings with Safety Related equipment and are therefore in the scope 

of license renewal.

Protection from a high energy line break inside of buildings is provided primarily 

by separation and redundancy. High energy lines are routed to provide 

maximum protection by using plant structural elements, such as walls, columns, 

doors, and pipe whip restraints to prevent uncontrolled whipping of the high 

energy piping. Outside of buildings, protection from a high energy line break 

(postulated breaks in, or whip loads) is provided by seismic Category I reinforced 

concrete walls. These components are in-scope for license renewal.

Internal and External Flooding Events

Flooding from various internal sources (e.g., pipe breaks) and external sources 

were evaluated during the design of the plant. Protection against possible 

internal flooding from liquid carrying systems, due to pipe rupture or fire 

protection activities are discussed in Sections 3.6, 9.33, 9.5.1 and 10.4.5.3 of the 

UFSAR.

Internal Flooding features are associated with the Equipment and Floor Drainage 

System, including sumps, sump pumps, tanks, drains, and piping to remove 

water from potential internal flooding events, and fire protection activities for 

areas containing safety-related equipment. These design features are in-scope 

for license renewal. Protection against possible internal flooding is discussed in 

UFSAR Section 3.4 “Water Level (Flood) Design.” Internal flood protection 

components are reinforced concrete walls, and concrete and steel curbs. These 

components are in-scope for license renewal.

Protection against possible external flooding is discussed in UFSAR 

Sections 2.4.5.5 “Protective Structures,” and Section 2.5.5 “Stability of Slopes.” 

External flood protection components are stone revetment, sheet pile retaining 

wall, and vertical seawall. These components are in-scope for license renewal.

Internal and External Missile Hazards
Structures and Components Subject to Aging Management Review

2-12

Missiles that could be generated from internal sources or external sources such 

as rotating equipment and tornados were considered in the design of the plant. 

Both preventive (e.g., over speed controls, seismic restraints) and mitigative 

(e.g., missile barriers) features were installed to ensure safe shutdown as 

required by the CLB for postulated missile hazards. These design features are 

in-scope for license renewal.

Missiles that could be generated from internal or external sources as described in 

UFSAR Section 3.5 for various building and structures are summarized in 

UFSAR Table 3.5-1. The missile protection feature (missile barriers) are typically 

included as part of the building structure (reinforced concrete wall, floor or 

ceiling). All structures and their missile shields and barriers listed on UFSAR 

Table 3.5-12 are designed to resist internal and external missiles in accordance 

with the CLB, and are in-scope for license renewal.

LRA Section 2.1.2.2.2 states, in part, in relation to nonsafety-related directly connected to 

safety-related SSCs, the following:

For NNS SSCs directly connected to safety related SSCs, the in-scope boundary 

for license renewal extends into the NNS portion of the piping and supports up to 

and including the first seismic anchor or an equivalent anchor beyond the 

safety/non-safety interface. An equivalent seismic anchor is a combination of 

pipe restraints as described in UFSAR Section 3.7 (B) and Figure 3.7 (B) – 37.

An alternative used to specifically identify a seismic anchor or an equivalent 

anchor is to:

• Include the NNS piping run to the next large piece of plant equipment 

(e.g., pump, heat exchanger, tank, etc). The large piece of equipment 

must also be included in-scope and is subject to aging management for 

the intended function of being an anchor point for the piping run.

• Include the NNS piping run to a flexible connection – a flexible connection 

is considered a pipe stress analysis model end point when the flexible 

connection effectively decouples the piping system (i.e. does not support 

loads or transfer loads across it to connecting piping).

• For NNS piping runs such as vent or drain piping that end at open floor 

drains, include the entire piping in the scope of LR.

• For NNS piping runs that are connected to Safety Related (SR) piping at 

both ends, include the entire run of NNS piping between the SR piping.

• Include the buried portion of the piping in the scope of license renewal up 

to the point where the buried pipe exits the ground.

NNS structures attached to or next to Scoping Criteria 1 structures are in-scope 

for license renewal if their failure could prevent a Scoping Criteria 1 SSC from 

performing its intended function.

LRA Section 2.1.2.2.3 states, in part, in relation to nonsafety-related SSCs with the potential for 

spatial interaction with safety-related SSCs, the following:
Structures and Components Subject to Aging Management Review

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For non-safety related NNS SSCs that are not directly connected to safety 

related SSCs, or are connected downstream of the first equivalent anchor, the 

non-safety SSCs may be in-scope if their failure could prevent the performance 

of the system safety function for which the safety related SSC is required.

Two approaches were used to determine if a non-safety related SSC in proximity 

to a safety related SSC is in scope for license renewal: the mitigative and 

preventive approach. Where it could be demonstrated that safety related SSCs 

are separated from non-safety related SSCs by physical barriers, the mitigative 

option was used (e.g., Tank Farm rooms TF101 and TF102). The preventive 

option was used in evaluating the vast majority of structures or systems at 

Seabrook Station for potential adverse structural or spatial interactions with 

Scoping Criterion 1 SSCs.

If a safety related component was determined to exist within that building, then all 

the NNS components within that building were included in the scope of LR. In 

other words, if a building contained a safety related component, then the entire 

building, not just the room, was included in the scope for NSAS.

There is one exception to the application of above methodology. NEI-95-10 

Section 3.1.1 recognizes that...“a system, structure or component may not meet 

the requirements of §54.4(a)(1) although it is designated as safety related for 

plant specific reasons. However, the systems, structures and components would 

still need to be evaluated for inclusion into the scope of the Rule using the criteria 

in §54.4(a)(2) and §54.4(a)(3).”

The Turbine Building contains components associated with the reactor protection 

and engineered safety features actuation system which have been classified as 

safety related in the plant equipment database. There are no other safety related 

SSCs in the Turbine Building. These components do not perform a safety 

function, as defined in 10 CFR 54.4(a)(1), and are not credited in the Seabrook 

Station accident analysis. The CLB does not credit operation of these 

components during or after a seismic event and thus seismic design or 

qualification is not required. Therefore, there are no components in the Turbine 

Building that are considered to be in scope for license renewal as defined in 

10 CFR 54.4(a)(2).

The Turbine Building is a non-seismic Category I structure (UFSAR 1.2.2.9). The 

entire Turbine Building is designed against failure due to Tornado Wind and SSE 

Loads that could affect any seismic Category I structures in the proximity and 

therefore considered to be in-scope for license renewal as defined in 

10 CFR 54.4(a)(2) (UFSAR Tables 3.3-4 and 3.7(B)-22).

NNS Conduits, Trays, Junction Boxes, and Lighting Fixtures

NNS conduits, cable trays, junction boxes, lighting fixtures may contain or be 

routed near Scoping Criterion 1 cables or other components. To determine 

which of these commodities to consider in-scope for license renewal, a 

conservative simplified approach is used. All NNS conduits, trays, junction boxes 

and lighting fixtures and their supports located within structures housing safety 

related equipment are in-scope for license renewal.
Structures and Components Subject to Aging Management Review

2-14

NNS HVAC Ducts and Supports

At Seabrook Station, the non-nuclear safety (NNS) HVAC ducting was evaluated 

similar to air/gas piping systems utilizing the guidance provided in NEI 95-10 

Appendix F. All HVAC duct supports located within structures housing Scoping 

Criterion 1 components are in-scope for license renewal similar to Air/Gas 

Systems.

LRA Section 2.1.2.2.4 states, in part, in relation to nonsafety SSCs providing functional support 

for safety-related SSCs, the following:

The review of the CLB identified a diesel driven pump as a component that 

supports a safety related intended function. The portable Cooling Tower makeup 

pump is maintained on the site. It is capable of providing makeup water to the 

Service Water System (Section 2.3.3.37) Cooling Tower basin from the nearby 

Browns River or Hampton Harbor with several locations accessible by road. This 

pump is stored in a Seismic Category 1 building, and is used to ensure a 30 day 

supply of water in the cooling tower basin in the event of design bases event and 

subsequent seismic event, the Safe Shutdown Earthquake. This diesel driven 

pump (1-SW-P-329) has been included in the scope of license renewal.

2.1.4.2.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs, whose 

failure could prevent the satisfactory accomplishment of safety-related functions, for SSCs relied 

on to remain functional during and following a DBE to ensure the following:

• the integrity of the reactor coolant pressure boundary

• the ability to shut down the reactor and maintain it in a safe shutdown condition

• the capability to prevent or mitigate the consequences of accidents that could result in 

potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1), 

10 CFR 50.67(b)(2), or 10 CFR 100.11

RG 1.188, Revision 1, endorses the use of NEI 95-10, Revision 6. NEI 95-10 discusses 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 functions as follows: 

consideration of missiles, cranes, flooding, and HELBs; 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.

In addition, the staff’s position (as discussed in the SRP-LR Section 2.1.3.1.2) is that applicants 

need not consider hypothetical failures but, rather, should base their evaluation on the plant’s 

CLB, engineering judgment and analyses and relevant operating experience. NEI 95-10 further 

describes operating experience as all documented plant-specific and industry-wide experience 

that can be used to determine the plausibility of a failure. Documentation would include NRC 

generic communications and event reports, plant-specific condition reports, industry reports 

such as safety operational event reports, and engineering evaluations. The staff reviewed LRA 

Section 2.1.2.2 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 document and results report, which documented the guidance and corresponding 
Structures and Components Subject to Aging Management Review

2-15

results of the applicant’s scoping review pursuant to 10 CFR 54.4(a)(2). The applicant stated 

that it performed the review in accordance with the guidance contained in NEI 95-10, 

Revision 6, Appendix F.

Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSCs 

The staff determined that nonsafety-related SSCs required to remain functional to support a 

safety-related function had been reviewed by the applicant for inclusion within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating 

criteria discussed in LRA Section 2.1.2.2.4 and the applicant’s 10 CFR 54.4(a)(2) implementing 

document. The staff confirmed that the applicant had reviewed the UFSAR, plant drawings, the 

plant equipment database, and other CLB documents to identify the nonsafety-related systems 

and structures that function to support a safety-related system whose failure could prevent the 

performance of a safety-related intended function. The applicant also considered missiles, 

overhead handling systems, internal and external flooding, and HELBs. Accordingly, the staff 

finds that the applicant implemented an acceptable method for including nonsafety-related 

systems that perform functions that support safety-related intended functions within the scope of 

license renewal, as required by 10 CFR 54.4(a)(2).

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs

The staff determined that in order to identify the nonsafety-related SSCs connected to 

safety-related SSCs and required to be structurally sound to maintain the integrity of the 

safety-related SSCs, the applicant used a combination of the following to identify the portion of 

nonsafety-related piping systems to include within the scope of license renewal:

. The staff confirmed that 

nonsafety-related SSCs, directly connected to SSCs, had been reviewed by the applicant for 

inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff 

reviewed the evaluating criteria discussed in LRA Section 2.1.2.2 and the applicant’s 

10 CFR 54.4(a)(2) implementing document. The applicant reviewed the safety-related to 

nonsafety-related interfaces for each mechanical system in order to identify the 

nonsafety-related components located between the safety to nonsafety-related interface and 

license renewal structural boundary.

• seismic anchors

• equivalent anchors, as defined in the Seabrook UFSAR

• bounding conditions described in NEI 95-10 Revision 6, Appendix F (base-mounted 

component, flexible connection, inclusion to the free end of nonsafety-related piping, or 

inclusion of the entire piping run)

Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. 

The staff confirmed that nonsafety-related SSCs with the potential for spatial interaction with 

safety-related SSCs had been reviewed by the applicant for inclusion within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating criteria 

discussed in the LRA Section 2.1.2.2.3 and the applicant’s 10 CFR 54.4(a)(2) implementing 

procedure. The applicant considered physical impacts (pipe whip, jet impingement) harsh 

environments, flooding, spray, and leakage when evaluating the potential for spatial interactions 

between nonsafety-related systems and safety-related SSCs. The staff further confirmed that 

the applicant used a preventative, 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 
Structures and Components Subject to Aging Management Review

2-16

are located in the same space, which was defined for the purposes of the review as a structure 

containing active or passive safety-related SSCs.

LRA Section 2.1.2.2.3 and the applicant’s implementing document state that the applicant 

included mitigative features when considering the impact of nonsafety-related SSCs on 

safety-related SSCs for occurrences discussed in the CLB. The staff reviewed the applicant’s 

CLB information—primarily contained in the UFSAR—related to missiles, crane load drops, 

flooding, and HELBs. The staff determined that the applicant also considered the features 

designed to protect safety-related SSCs from the effects of these occurrences through the use 

of mitigating features such as floor drains and curbs. The staff confirmed that the applicant 

included the mitigating features within the scope of license renewal, in accordance with 

10 CFR 54.4(a)(2).

LRA Section 2.1.2.2.3 and the applicant’s implementing document state that the applicant used 

a preventive approach, which considered the impact of nonsafety-related SSCs contained in the 

same space as safety-related SSCs. The staff determined that the applicant evaluated all 

nonsafety-related SSCs containing liquid or steam and located in spaces containing 

safety-related SSCs. The applicant used a spaces approach to identify the nonsafety-related 

SSCs that were located within the same space as safety-related SSCs. As described in the 

LRA, and for the purpose of the scoping review, a space was defined as a structure containing 

active or passive safety-related SSCs. In addition, the staff determined that, following the 

identification of the applicable mechanical systems, the applicant identified its corresponding 

structures for potential spatial interaction, based on a review of the CLB and plant walkdowns. 

Nonsafety-related systems and components that contain liquid or steam and are located inside 

structures that contain safety-related SSCs were included within the scope of license renewal, 

unless it was evaluated and determined not to contain safety-related SSCs. 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 scope of license renewal, with the 

exception of portions that are attached to safety-related SSCs and required for structural 

support. The staff determined that additional information would be required to complete the 

review of the applicant’s scoping methodology. RAI 2.1-1, dated January 5, 2011, states that 

during the scoping and screening methodology audit performed onsite September 20–23, 2010, 

the staff reviewed the LRA and the applicant’s 10 CFR 54.4(a) implementing documents. The 

staff determined that the applicant identified and evaluated safety-related components located in 

the turbine building and that the applicant concluded that the nonsafety-related SSCs in the 

proximity of, or attached to, the safety-related SSCs were not required to be included within the 

scope of license renewal. The staff requested that the applicant do the following:

• identify SSCs located in the turbine building that are classified as safety-related in the 

plant EDB that were not included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1)

• provide the details of the evaluation and the basis for the conclusion that SSCs, located 

in the turbine building that are classified as safety-related in plant EDB, do not have an 

intended function that requires the SSCs to be included within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(1)

• provide the details of the evaluation and basis for the conclusion that nonsafety-related 

SSCs, in the proximity of or attached to SSCs located in the turbine building and 

classified as safety-related in plant EDB, are not required to be included within the scope 

of license in accordance with 10 CFR 54.4(a)(2)
Structures and Components Subject to Aging Management Review

2-17

The applicant responded to RAI 2.1-1 by letter dated February 3, 2011, which states, in part:

The following components are classified as being safety-related and Class IE, 

are located in the non-seismic turbine building and are not included in the scope 

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

Turbine Impulse Chamber Pressure Transmitters

Turbine Steam Stop Valve Position Switches

Turbine Steam Stop Valve Fluid Pressure Switches

Turbine Steam Dump Valve Air Supply Solenoid Valves

Feedwater Flow Control and Bypass Valve Position Switches

Feedwater Flow Control and Bypass Valve Solenoid Valves

The applicant further stated in the February 3, 2011, letter, that the above components were 

evaluated and the basis for the conclusion that SSCs located in the turbine building that are 

classified as safety-related in the plant equipment database, do not have an intended function 

that requires these SSCs to be included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1) is documented below.

The Turbine Impulse Chamber Pressure Transmitters inputs to the [Solid State 

Protection System] SSPS at Seabrook Station are designed such that the failure 

of these transmitters will not prevent actuation of the SSPS. They are designed 

as safety related so that they cannot prevent the SSPS from functioning. They 

are inputs to the Reactor Protection System and to the [anticipated transient 

without scram] ATWS Mitigating system and are not credited in the Seabrook 

Station accident analysis. 

The Turbine Impulse Pressure transmitters cannot prevent satisfactory 

accomplishment of any of the safety related functions discussed in 

10 CFR 54.4(a)(1). Therefore the requirements of 10 CFR 54.4(a) (2) are not 

applicable.

Turbine Steam Stop Valve Position Switches are classified as safety related, 

[however] their functioning is strictly anticipatory. Since these turbine steam stop 

valve limit and fluid pressure switches perform no safety function, are not 

credited in the accident analysis and meet Seabrook Station CLB for preventing 

interactions from propagating back into the [reactor protection system] RPS, they 

cannot prevent satisfactory accomplishment of any of the safety related functions 

discussed in 10 CFR 54.4(a)(1). Therefore the requirements of 10 CFR 54.4(a) 

(2) are not applicable.

The Steam Dump System dump valve solenoids are classified as Class IE and 

safety related. The design criteria applied to the turbine stop valve limit switches 

and turbine hydraulic pressure sensors was also applied to the steam dump 

valve solenoids. While these solenoid valves are classified as safety related, 

UFSAR section 10.4.4.3, Safety Evaluation states: “The Steam Dump System is 

not essential to the safe operation of the plant. It is provided for flexibility of 
Structures and Components Subject to Aging Management Review

2-18

operation.” Since these Steam Dump system solenoids perform no safety 

function, are not credited in the accident analysis and meet Seabrook Station 

CLB for preventing interactions from propagating back into the RPS, they cannot 

prevent satisfactory accomplishment of any of the safety related functions 

discussed in 10 CFR 54.4(a)(1). Therefore the requirements of 10 CFR 54.4(a) 

(2) are not applicable.

Feedwater Flow Control and Bypass Valve Position Switches and circuits do not 

interface with either the RPS or the [engineered safety features actuation system] 

ESFAS. The position switches do not perform a safety function, are not credited 

for Accident Monitoring, and cannot prevent satisfactory accomplishment of any 

of the safety-related functions discussed in 10 CFR 54.4(a)(1). Therefore the 

requirements of 10 CFR 54.4(a) (2) are not applicable.

The Feedwater Regulating and Bypass Valves provide backup to the safety 

related feedwater isolation valves. Although the solenoids for the feedwater 

Regulating and Bypass valves are classified as safety related and Class IE, the 

valves themselves are classified as non-safety components. These valves are 

not credited for containment isolation but perform a non-safety related backup to 

the safety related feedwater water isolation function. Since these feedwater 

regulating and bypass valve solenoids are not credited for containment isolation, 

are not safety related per NUREG 0138 criteria and meet the Seabrook Station 

CLB for preventing interactions from propagating back into the ESFAS, they 

cannot prevent satisfactory accomplishment of any of the safety related functions 

discussed in 10 CFR 54.4(a) (1). However, since these feedwater regulating and 

bypass valve solenoids are credited as supporting a non-safety related backup 

isolation function for the feedwater isolation valves (closure of the non-safety 

feedwater regulating and bypass valves), the requirements of 10 CFR 54.4(a) (2) 

are applicable, i.e., the feedwater regulating and bypass valves must operate to 

support the feedwater isolation function. Additionally, the feedwater regulating 

and bypass valve solenoids are in scope of license renewal as being required to 

support 10 CFR 54.4(a) (3), Fire Protection (the intended function for Fire 

Protection is pressure boundary).

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

described the process used to evaluate systems that contained components that were identified 

as safety-related in the plant equipment database but that were not included within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(1). The staff determined that, during the 

scoping process, the applicant identified components identified as safety-related in the plant 

equipment database that were contained in systems that, when evaluated by the applicant, 

were determined to not have safety-related intended functions that meet the criteria of 

10 CFR 54.4(a)(1). The staff considered this information, along with information contained in 

the LRA and scoping implementing procedures, and determined that some components had 

been conservatively identified as safety-related in the plant equipment database although CLB 

information did not indicate that the plant system was required to perform an intended function 

meeting the criteria in 10 CFR 54.4(a)(1).

In addition, the staff determined that, during its review, the applicant had included the 

nonsafety-related feedwater and bypass solenoid valves, even though the valves are not 

credited for containment isolation, do perform a nonsafety-related backup to the safety-related 

feedwater water isolation function. The applicant also determined that the feedwater regulating 
Structures and Components Subject to Aging Management Review

2-19

and bypass valves support a 10 CFR 54.4(a)(3) function for fire protection (pressure boundary). 

The applicant revised the LRA to include the feedwater and bypass solenoids within the scope 

of license renewal, in accordance with 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3).

The staff concludes—based on a review of the applicant’s assessment of components identified 

as safety-related in the plant equipment database but whose parent system was not included 

within the scope of license renewal in accordance with 10 CFR 54.4(a)(1)—that the applicant 

provided an acceptable basis for not including the systems within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(1). RAI 2.1-1 is resolved.

The staff determined that additional information would be required to complete the review of the 

applicant’s scoping methodology. RAI 2.1-2, dated January 5, 2011, states that during the 

scoping and screening methodology audit, performed onsite September 20–23, 2010, the staff 

determined that the applicant reviewed nonsafety-related drain lines in the proximity of 

safety-related SSCs and that the applicant concluded that the drain lines were not required to 

be included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff 

determined that license renewal drawings included a note applicable to drain lines from relief 

valves that stated, “Lines are not liquid filled so they have no license renewal-intended function 

and are not in scope.” The staff requested that the applicant provide the details of its evaluation 

and basis for its conclusion that nonsafety-related drain lines near safety-related SSCs will not 

be fluid-filled during a DBE, the failure of which could not prevent satisfactory accomplishment 

of the function of safety-related SSCs and, therefore, are not required to be included within the 

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

The applicant responded to RAI 2.1-2 by letter dated February 3, 2011, which states, in part, the 

following:

The tailpipes for the non-safety related DF and [hot water heating system] HW 

relief valves shown in the above listed locations are not liquid filled during normal 

plant operation and were evaluated in accordance with the guidance provided in 

NEI 95-10, Rev 6, Section 5.2.2.1, “Systems and Components Containing 

Air/Gas.”

Additionally, the above listed non-safety related DF and HW system relief valves 

are not designed to operate nor lift during a design basis event. Furthermore, as 

stated in NUREG 1800, Section A.1 (Branch Technical Position RLSP-1), the 

applicable aging effects to be considered for license renewal include those that 

could result from normal plant operation, including plant/system operating 

transients and plant shutdown. Specific aging effects from abnormal events 

need not be postulated for license renewal.

As stated above, as part of the integrated plant evaluation for license renewal, 

Seabrook Station determined that the normal internal environment for the 

downstream piping or tailpipes from the non-safety related relief valves is 

air-indoor uncontrolled. This decision was based on the conclusion that the 

subject relief valves were designed to limit potential over pressurization of the 

piping system, which is an extremely rare occurrence, if any at all. The valve 

set-points are rarely challenged, and therefore, it is a rare occurrence for a relief 

valve to lift. If a relief valve was to relieve and the downstream pipe become 

wetted, the pipe would dry over time and return to the air-indoor uncontrolled 

normal environment. Additionally, none of these relief valves are being utilized 
Structures and Components Subject to Aging Management Review

2-20

as a pressure control valve and therefore, the normal internal environment for the 

subject tail pipes is air-indoor uncontrolled (non-liquid).

The staff reviewed the applicant’s response to RAI 2.1-2. The staff’s review determined that the 

function of a drain line is to contain and pass fluid when required, and the pipe should be 

included within the scope of license renewal and subject to AMR in accordance with 

10 CFR 54.4 (a)(2) for spatial interaction. The staff further determined that following inclusion of 

the drain lines within the scope of license renewal, the applicant’s AMR will allow for the 

evaluation of material and environment combinations to identify aging effects and the suitability 

of AMPs. Subsequent to the initial response, the staff held a conference call with the applicant 

on April 8, 2011, to explain its concerns. By letter dated April 22, 2011, the applicant provided a 

revised response that states, in part, that “[b]ased on the teleconference held with the NRC on 

April 8, 2011, the tail pipes for the non-safety related relief valves have been added to the scope 

of license renewal under 10 CFR 54.4(a)(2) for spatial interaction.”

The staff reviewed the applicant’s response to RAI 2.1-2. The staff determined that the 

applicant appropriately amended the information in the LRA to include the nonsafety-related 

drain lines within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). The 

staff’s concern described in RAI 2.1-2 is resolved.

The staff determined that additional information would be required to complete the review of the 

applicant’s scoping methodology. RAI 2.1-3, dated January 5, 2011, states that during the 

scoping and screening methodology audit performed onsite September 20–23, 2010, the staff 

reviewed the LRA and the applicant’s 10 CFR 54.4(a) implementing documents, relative to 

nonsafety-related sump pumps. The staff noted that the license renewal implementing 

documents state that nonsafety-related sump pumps that are located in a sump are not included 

within the scope of license renewal if there is a cover over the sump preventing the pump from 

spatially interacting with safety-related equipment. The staff requested that the applicant 

provide the details of its evaluation and basis for the conclusion that the failure of 

nonsafety-related sump pumps, in the proximity safety-related SSCs, could not prevent 

satisfactory accomplishment of the function of safety-related SSCs and, therefore, are not 

required to be included 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 February 3, 2011, which states, in part, the 

following:

The sump pumps that are located in sumps that have a bolted down solid sump 

cover are not within the scope of license renewal for 10 CFR 54.4(a)(2). In these 

cases, the mitigative approach was utilized as the bolted down solid plate would 

prevent liquid spray from components inside the sump. Steel or stainless steel 

sump cover plates that are fixed in place are considered part of the building 

structure and age managed under the Structures Monitoring Program, B.2.1.31, 

as part of the carbon steel or stainless steel commodity grouping.

All sump locations were reviewed to ensure that this approach was applied 

consistently. This review identified that four sumps did not have a solid sump 

cover. Therefore, the sump pumps and piping inside these sumps were brought 

into the scope for license renewal. These sumps are located in the East and 

West Main Steam and Feedwater Pipe Chases and Intake and Discharge 

Transition Structures. On LRA drawing PID-1-DFLR20200, sump pumps P-51A, 
Structures and Components Subject to Aging Management Review

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P-51B, P-267A, P-267B, P-268A, and P-268B and associated piping in the 

sumps should have been colored Green instead of Black.

The above listed four pumps are not utilized to mitigate internal flooding events. 

The nonsafety related sump pumps, piping, and valves that are necessary to 

mitigate the effects of internal flooding events and fire protection activities in 

areas containing safety related equipment are in scope of license renewal for 

10 CFR.54(a)(2) or 10 CFR.54(a)(3) regardless of the type of sump covers they 

have.

The staff reviewed the applicant’s response to RAI 2.1-3. The staff’s review determined that for 

nonsafety-related sump pumps with permanently attached covers, the applicant had 

appropriately included the permanently attached sump pump covers as a mitigating feature to 

prevent spatial interaction, in accordance with 10 CFR 54.4(a)(2). In addition, during its review,

the applicant identified four nonsafety-related sump pumps that did not have permanently 

attached covers. In these cases, the applicant revised the LRA to include the sump pump and 

associated piping within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

RAI 2.1-3 is resolved.

Based on its review of the LRA, the results of the scoping and screening methodology audit and 

the applicant's reponses to RAIs 2.1-1, 2.1-2, and 2.1-3, the staff confirmed that fluid-filled 

nonsafety-related SSCs, in proximity to safety-related SSCs and whose failure could potentially

prevent accomplishement of a safety function, were included within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(2).

2.1.4.2.3 Conclusion

On the basis of its review of the applicant's scoping process, discussions with the applicant, and 

review of the information provided in the response to RAIs 2.1-1, 2.1-2, and 2.1-3, the staff 

concludes that the applicant's methodology for identifying and including nonsafety-related 

SSCs, that could affect the performance of safety-related SSCs, within the scope of license 

renewal, is consistent with the scoping criteria of 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

LRA Section 2.1.2.3, “10 CFR 54.4(a)(3)—Regulated Events,” states, in part:

The third scoping category in 10 CFR 54.4 involves SSCs relied upon by 

licensees to address five regulated events. Specifically, §54.4(a)(3) defines 

SSCs as in-scope for license renewal, if relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with one or more 

of the regulated events:

• Fire Protection (10 CFR 50.48)

• Environmental Qualification (EQ) (10 CFR 50.49)

• Anticipated Transient Without Scram (10 CFR 50.62)

• Station Blackout (10 CFR 50.63)

• Pressurized Thermal Shock (10 CFR 50.61)
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Any SSC that is required to function in order to meet compliance requirements of 

one or more of these regulations was identified as required by §54.4(a)(3). 

Fire Protection Scoping

All systems, structures and components relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the 

Commission’s regulations for Fire Protection (10 CFR 50.48) were included in the 

scope of License Renewal in accordance with 10 CFR 54.4(a)(3) requirements.

The scope of systems and structures required for compliance with 10 CFR 50.48 

are described in UFSAR Appendix A and Appendix R. They include:

• Systems and structures required to demonstrate safe shutdown 

capabilities.

• Systems and structures required for fire detection and suppression 

needed to support safe shutdown.

• Systems and structures required to meet commitments made to 

Appendix A of Branch Technical Position [Auxiliary and Power 

Conversion Systems Branch] APCSB 9.5-1 with respect to the protection 

of systems important to safety and prevention of radioactive releases to 

the environment.

The License Renewal fire protection technical report documents the results of a 

detailed review of Seabrook Station’s fire protection program documents that 

demonstrate compliance with the requirements of 10 CFR 50.48. This document 

provides a list of systems and structures credited in the plant’s fire protection and 

safe shutdown evaluations. The identified systems and structures are in the 

scope of License Renewal under 10 CFR 54.4(a)(3) scoping criteria.

Environmental Qualification Scoping

The CLB for Seabrook Station’s EQ Program is Title 10, Part 50, Section 49 of 

the Code of Federal Regulations (10 CFR 50.49). This is achieved via 

conformance to the requirements of NUREG-0588, “Interim Staff Position on 

Environmental Qualification of Safety-Related Electrical Equipment” Category I 

criteria. Category I criteria incorporates and supplements [Institute of Electrical 

and Electronics Engineers] IEEE 323-1974, "IEEE Standard for Qualifying 

Class 1E Equipment for Nuclear Power Generating Stations."

The EQ portion of the license renewal scoping was performed utilizing the Harsh 

Environment Equipment list. Systems and structures containing equipment 

within the scope of the EQ Program were identified. The buildings serve to 

provide shelter, support and protection of EQ equipment. Components in the EQ 

program are evaluated in the EQ TLAA, Section 4.4.

Anticipated Transients Without Scram Scoping

10 CFR 54.4(a)(3) requires that all systems, components and structures relied on 

in safety analyses or plant evaluations to perform a function that demonstrates 
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compliance with the Commission’s regulations for Anticipated Transients Without 

Scram (ATWS) (10 CFR 50.62) be included in the scope of license renewal.

An ATWS Mitigation System (AMS) is installed at Seabrook Station which 

provides an alternative means for automatically tripping the turbine and actuating 

Emergency Feedwater (EFW) flow that is independent of the protection system 

actuations. 

Seabrook Station SSCs used to mitigate an ATWS event have been included in 

the scope of License Renewal.

Station Blackout Scoping

10 CFR 54.4(a)(3) requires that all systems, structures and components relied 

upon in safety analyses or plant evaluations to perform a function that is credited 

in demonstrating compliance with the Commission’s regulations for Station 

Blackout (10 CFR 50.63) be included in the scope of License Renewal.

Seabrook Station complies with the requirements of 10 CFR 50.63 as a coping 

plant. This means that safe shutdown can be maintained using battery backed 

electrical buses for the four hour coping period. Offsite power and or onsite 

power will be restored at or before the end of the four hour coping period.

The SBO Offsite Recovery Path License Renewal Drawing, Figure 2.5-1, was 

created to depict the in-scope portion of the off-site power system for Station 

Blackout (SBO). Seabrook Station has chosen two paths for the recovery of 

off-site power in the event of a Station Blackout (SBO). Path 1 is colored green. 

Path 2 is colored red.

Pressurized Thermal Shock

Criterion 10 CFR 54.4(a)(3) requires that all SSCs relied on in safety analyses or 

plant evaluations to perform a function that demonstrates compliance with the 

commission’s regulations for [pressurized thermal shock] PTS be included in the 

scope of License Renewal.

Pressurized Thermal Shock (PTS) is a condition that could challenge the integrity 

of the reactor pressure vessel (RPV). Pressurized Thermal Shock (PTS) may 

occur during a severe transient such as a Loss of Coolant Accident (LOCA) or a 

steam line break. 

The steel reactor vessel beltline shell, including plates, forgings, and welds, were 

determined to meet the scoping criteria of 10 CFR 54.4 with respect to 

pressurized thermal shock.

2.1.4.3.2 Staff Evaluation

The staff reviewed the applicant’s approach to identifying SSCs, in accordance with 

10 CFR 54.4(a)(3), which are relied on to perform functions meeting the requirements of the 

NRC regulations regarding fire protection, EQ, ATWS, PTS, and SBO. As part of this review,

the staff did the following:
Structures and Components Subject to Aging Management Review

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• discussed the applicant’s methodology

• reviewed the boundary drawings

• reviewed license renewal technical reports associated with the five regulated events

• reviewed the LRA for the development and approach taken to complete the scoping 

process for these regulated safety systems 

• evaluated SSCs (on a sampling basis) included within the scope of license renewal 

pursuant to 10 CFR 54.4(a)(3)

The staff confirmed that the applicant’s implementing procedures were used for identifying 

Seabrook SSCs within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). The 

applicant evaluated the Seabrook CLB and other source documents to identify SSCs that 

perform functions addressed in 10 CFR 54.4(a)(3), “Regulated Events,” and included these 

SSCs within the scope of license renewal, as documented in the specific Seabrook regulated 

event(s) license renewal technical reports. The staff determined that these technical report 

results appropriately reference the information sources used for determining the SSCs credited 

for compliance with the events listed in the specified regulations for the applicable license 

renewal regulated events.

Fire Protection. The staff determined that the applicant’s fire protection scoping document 

identified SSCs in the scope of license renewal required for fire protection. Seabrook used CLB 

documents to identify the SSCs within the scope of license renewal for fire protection, primarily 

the UFSAR, Section 9.5.1, “Fire Protection Systems.” The staff reviewed the source documents 

used by the applicant including the UFSAR and the Seabrook fire protection-related design 

basis documents. The staff reviewed the fire protection scoping and screening report in 

conjunction with the LRA and the CLB information to validate the methodology for including the 

appropriate SSCs within the scope of license renewal. The staff determined that the applicants 

scoping included SSCs that perform intended functions to meet the requirements of 

10 CFR 50.48. Based on its reviews, the staff determined that the applicant’s scoping 

methodology was adequate for including SSCs credited in performing fire protection functions 

within the scope of license renewal.

EQ. The staff confirmed that the applicant’s EQ scoping and screening report required the 

inclusion of safety-related electrical equipment; nonsafety-related electrical equipment whose 

failure under postulated environmental conditions could prevent satisfactory accomplishments of 

safety functions of the safety-related equipment; and certain post-accident monitoring 

equipment, as defined in 10 CFR 50.49(b)(1), 10 CFR 50.49(b)(2), and 10 CFR 50.49(b)(3). 

The staff determined that the applicant used the CLB, as described in the Seabrook UFSAR 

Section 3.11, as well as its EQ DBD to identify SSCs necessary to meet the requirements of 

10 CFR 50.49. The Seabrook Harsh Environment Equipment List contains the EQ 

identifications for specific components. The staff reviewed the LRA, implementing procedures, 

and the EQ scoping and screening report to verify that the applicant identified SSCs within the 

scope of license renewal that meet EQ requirements. Based on that review, the staff 

determined that the applicant’s scoping methodology was adequate for identifying EQ SSCs 

within the scope of license renewal.

PTS. The staff confirmed that the applicant’s PTS scoping and screening report included the 

applicant’s scoping methodology that used Seabrook CLB information to develop the LRA to 

comply with 10 CFR 50.61, “PTS Rule,” which resulted in the Seabrook reactor vessel beltline 

components to be within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). The staff 

reviewed the “Seabrook Station Reactor Pressure Vessel Fluence Evaluation at 55 [Effective 

Full Power Years] EFPY,” which provides the basis for identifying the specific components 
Structures and Components Subject to Aging Management Review

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in-scope for license renewal. The staff determined that the methodology applied was 

appropriate for identifying SSCs with functions credited for complying with the PTS regulation 

and within the scope of license renewal. The staff finds that the scoping results included the 

systems and structures that perform intended functions to meet the requirements of 

10 CFR 50.61. The staff determined that the applicant’s scoping methodology was adequate for 

including SSCs credited in meeting PTS requirements within the scope of license renewal

ATWS. The staff determined that the applicant’s ATWS scoping and screening report included 

the plant systems credited for ATWS mitigation based on review of the Seabrook CLB and the 

UFSAR, Section 7.6.12, “ATWS Mitigation System,” and Section 15.8, “Anticipated Transients 

Without Scram.” The staff reviewed these documents and the LRA in conjunction with the 

scoping results to confirm the methodology for identifying ATWS systems and structures that 

are within the scope of license renewal. The staff determined that the scoping results included 

systems and structures that perform intended functions meeting 10 CFR 50.62 requirements. 

The staff determined that the applicant’s scoping methodology was adequate for identifying 

SSCs with functions credited for complying with the ATWS regulation.

SBO

2.1.4.3.3 Conclusion

. The staff determined that the applicant’s SBO scoping and screening report included 

SSCs from the Seabrook CLB that the applicant identified were associated with coping and safe 

shutdown of the plant following an SBO event by reviewing UFSAR Section 8.4, “Compliance 

With 10 CFR 50.63, Loss of All Alternating Current Power (Station Blackout),” and plant 

procedures. The staff reviewed a sample of these documents and the LRA, in conjunction with 

the scoping results, to confirm the applicant’s methodology. The staff finds that the scoping 

results included systems and structures that perform intended functions meeting 10 CFR 50.63 

requirements. The staff determined that the applicant’s scoping methodology was adequate for 

identifying SSCs credited in complying with the SBO regulations within the scope of license 

renewal.

On the basis of the sample reviews, discussions with the applicant, review of the LRA, and 

review of the implementing procedures and reports, the staff concludes that the applicant’s 

methodology for identifying systems and structures meets the scoping criteria pursuant to

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

System and Structure Level Scoping

“Scoping” was performed to identify the plant systems and structures which 

perform intended functions as defined in 10 CFR 54.4(a)(1), (a)(2) or (a)(3). 

Initially, all Seabrook Station SSCs were examined. If any portion of a system or 

structure met the scoping criteria of 10 CFR 54.4, the system and/or structure 

was included in-scope for License Renewal. For systems and structures 

determined to be in scope, the intended functions were identified. All electrical 

and Instrumentation and Control systems and components are considered in 

scope.

. LRA Section 2.1, “Scoping and Screening Methodology,” 

states, in part:
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“Screening” was performed to identify the components associated with the 

in-scope systems and structures that are subject to aging management review as 

defined in 10 CFR 54.21. The screening process examined in-scope 

components and structures to determine those that are passive and long-lived. 

These components and structures were subject to aging management review. 

Scoping and screening has been performed consistent with the requirements of 

10 CFR 54, the Statements of Consideration related to the license renewal rule, 

and the guidance provided in NEI 95-10, “Industry Guidelines for Implementing 

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

LRA Section 2.1.2, “Scoping Methodology,” states, in part:

The scoping methodology utilized by Seabrook Station is consistent with the 

guidance provided by NEI 95-10, Revision 6. Existing plant documentation was 

used for this review including the Updated Final Safety Analysis Report 

(UFSAR), Technical Specifications and licensing correspondence that collectively 

form the Seabrook Station Current Licensing Basis (CLB). Additional information 

sources included Design Basis Documents (DBD’s), controlled drawings, 

Equipment Database and the Maintenance Rule Database.

All Seabrook Station plant systems and structures were reviewed and evaluated 

against the scoping criteria to determine which met the requirements for inclusion 

in the scope of license renewal.

Scoping was initially performed at the system or structure level in accordance 

with the criteria identified in 10 CFR 54.4(a). System level and structure intended 

functions were then identified from a review of CLB documentation. Starting at 

the system level intended functions, scoping boundaries for each system were 

determined. The results of this effort form the basis for identification of the 

in-scope components.

Component information was initially transferred from the Seabrook Station 

Equipment Database (EDB) to the License Renewal Database. The EDB is used 

to maintain configuration control of component level information at Seabrook 

Station. As such, quality assurance applied to the EDB software ensures 

compliance with requirements and/or commitments that are necessary to support 

both safety related and non-nuclear safety component level information.

Equipment that is stored on site for use in response to design basis events is 

considered to be within the scope of License Renewal. At Seabrook Station, 

Station Blackout and Appendix R fire scenarios utilize stored equipment to 

facilitate contingency actions following the event. The stored equipment is 

confirmed available and in good operating condition by periodic inspection. 

Tools and supplies used to place the stored equipment in service are not in the 

scope of License Renewal.

LRA Section 2.1.2 further states, in part:

Application of all three 10CRF54.4 criteria generated a listing of SSCs that were 

determined to be in-scope for license renewal. Not every component of a system 
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supports the system intended functions. Therefore, some components within an 

in-scope system are not in-scope for license renewal.

For the mechanical scoping effort, summary level boundary descriptions were 

developed and included in Section 2.3. License Renewal drawings/diagrams 

were also created from plant controlled PID’s to illustrate in-scope mechanical 

systems, structures and components subject to an aging management review 

(AMR). These AMR boundaries are depicted on color coded license renewal 

drawings (e.g. PID-1-FW-LR20686) and contain system boundary flags.

For the electrical scoping effort, boundary drawings were not necessary since 

commodity grouping was used in the scoping process. The SBO Offsite 

Recovery Path License Renewal Drawing, Figure 2.5-1, was created to depict 

the in-scope portion of the off-site power system for Station Blackout (SBO).

2.1.4.4.2 Staff Evaluation

The staff reviewed the applicant’s methodology for performing the scoping of plant systems and 

components to ensure it was consistent with 10 CFR 54.4. The methodology used to determine 

the systems and components within the scope of license renewal was documented in 

implementing procedures and scoping results reports for systems. The scoping process defined 

the plant in terms of systems and structures. Specifically, the implementing procedures 

identified the systems and structures that are subject to 10 CFR 54.4 review, described the 

processes for capturing the results of the review, and were used to determine if the system or 

structure performed intended functions consistent with the criteria of 10 CFR 54.4(a). The 

process was completed for all systems and structures to ensure that the entire plant was 

addressed.

The applicant documented the results of the plant-level scoping process in accordance with the 

implementing documents. The results were provided in the systems and structures documents 

and reports, which contained the following information:

• 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

• the basis for the classification of the system or structure intended functions

During the audit, the staff reviewed a sampling of the documents and reports and concluded 

that the applicant's scoping results contained an appropriate level of detail to document the 

scoping process.

2.1.4.4.3 Conclusion

On the basis of its review of the LRA, site guidance documents, and a sampling of system 

scoping results reviewed during the audit, the staff concludes that the applicant’s methodology 

for identifying SSCs within the scope of license renewal, and their intended functions, is 

consistent with the requirements of 10 CFR 54.4 and, therefore, is acceptable.
Structures and Components Subject to Aging Management Review

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2.1.4.5 Mechanical Scoping

2.1.4.5.1 Summary of Technical Information in the Application

LRA Section 2.1.2, “Scoping Methodology,” states, in part, the following with regard to 

mechanical scoping:

Mechanical scoping utilized existing Maintenance Rule (MRule) system functions 

during the License Renewal scoping. These functions were transferred into the 

License Renewal Database from the MRule database. In addition to the MRule 

functions, functions were created in the License Renewal Database to capture 

the non-safety affecting safety (Criterion 2) and the five regulated events 

(Criterion 3). The MRule system functions that were transferred to the License 

Renewal Database were validated for accuracy using the UFSAR, Technical 

Specifications, DBDs (including source documents), and other controlled 

documentation.

2.1.4.5.2 Staff Evaluation

The staff evaluated LRA Section 2.1.2, “Scoping Methodology,” and the guidance in the 

implementing procedures and reports to perform the review of the mechanical scoping process. 

The project documents and reports provided instructions for identifying the evaluation 

boundaries. The staff reviewed the implementing documents and the CLB documents 

associated with mechanical system scoping, and it finds that the guidance and CLB source 

information noted above were acceptable to identify mechanical components and support 

structures in mechanical systems that are within the scope of license renewal. The staff 

conducted 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 appropriately applied the scoping methodology 

outlined in the LRA and implementing procedures and whether the scoping results were 

consistent with CLB requirements. The staff determined that the applicant's procedure was 

consistent with the description provided in the LRA Section 2.1.2 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 and screening reports for the 

diesel generator, plant floor drains, roof drain system, service water system, spent fuel pool 

system, feedwater system, and mechanical component types that met the scoping criteria of 

10 CFR 54.4. The staff also reviewed the implementing procedures and discussed the 

methodology and results with the applicant. The staff verified that the applicant identified and 

used pertinent engineering and licensing information in order to determine that the mechanical 

component types are required to be within the scope of license renewal. As part of the review 

process, the staff evaluated each system’s intended function, the basis for inclusion of the 

intended function, and the process used to identify each of the system component types. The 

staff verified that the applicant identified and highlighted system P&IDs to develop the license 

renewal boundaries in accordance with the procedural guidance. Additionally, the staff 

determined that the applicant independently verified the results in accordance with the 

governing procedures. The staff confirmed that the applicant had license renewal personnel 

knowledgeable about the system, and these personnel performed independent reviews of the 

marked-up drawings to ensure accurate identification of system-intended functions. The staff 

also confirmed that the applicant performed additional cross-discipline verification and 
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independent reviews of the resultant highlighted drawings before final approval of the scoping 

effort.

2.1.4.5.3 Conclusion

On the basis of 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, is acceptable.

2.1.4.6 Structural Scoping

2.1.4.6.1 Summary of Technical Information in the Application

LRA Section 2.1.2, “Scoping Methodology,” states, in part, the following with regard to civil and 

structural scoping:

Civil controlled drawings and the EDB were used to identify buildings, structures 

and foundations. The buildings were input into the License Renewal Database 

as individual or grouped license renewal structures. Other information sources, 

such as CLB documentation, were electronically searched using several 

keywords (e.g., structure, new structure, building modification) to ensure all plant 

structures were evaluated for license renewal-intended functions regardless of 

their coverage in the plant equipment database.

2.1.4.6.2 Staff Evaluation

The staff evaluated LRA Section 2.1.2, “Scoping Methodology,” implementing procedures and 

guidelines, and scoping and screening reports to perform the review of the structural scoping 

process. The license renewal procedures and guidelines provided instructions for identifying 

the evaluation boundaries. The staff reviewed the applicant’s approach to identifying structures 

relied upon to perform the functions described in 10 CFR 54.4(a). As part of this review, the 

staff discussed the methodology with the applicant, reviewed the documentation developed to 

support the review, and evaluated the scoping results for a sample of structures that were 

identified within the scope of license renewal. The staff determined that the applicant identified 

and developed a list of plant structures and the structures intended functions through a review 

of plant equipment database, UFSAR, drawings, and walkdowns. Each structure the applicant 

identified was evaluated against the criteria of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 

10 CFR 54.4(a)(3).

The staff reviewed CLB information, drawings, and implementing procedures to verify the 

adequacy of the methodology for identifying structures meeting the scoping criteria as defined in 

the rule. The staff discussed the methodology and results with the applicant. In addition, the 

staff reviewed, on a sampling basis, the applicant’s scoping and screening reports including 

information contained in the source documentation to verify that the application of the 

methodology would provide the results documented in the LRA.

In a specific example, the staff verified that the applicant identified and used pertinent 

engineering and licensing information to determine that the nonsafety-related turbine building 

was included within the scope of license renewal based on it housing and supporting 

safety-related components. As part of the review process, the staff evaluated the intended 
Structures and Components Subject to Aging Management Review

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functions identified for the turbine building and the structural components within, the basis for 

inclusion of the intended function, and the process used to identify each of the component 

types.

2.1.4.6.3 Conclusion

On the basis of its review of information in the LRA, scoping implementation procedures, and a 

sampling review of structural scoping results, the staff concludes that the applicant’s 

methodology for identification of the structural SSCs within the scope of license renewal is in 

accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.7 Electrical Component Scoping

2.1.4.7.1 Summary of Technical Information in the Application

LRA Section 2.1.2, “Scoping Methodology” states, in part, the following with regard to electrical 

and I&C scoping:

All electrical and I&C systems were considered in-scope. Electrical and I&C 

components were organized into commodity groups. The information provided 

by NEI 95-10 Appendix B and NUREG-1800 Table 2.1-5, was used as a basis for 

categorizing electrical and I&C components into commodity groups such as 

insulated cables and connections, circuit breakers, and switches. Individual 

components were not identified.

The electrical commodity groups identified resulted from a review of plant 

documents; controlled drawings, the EDB, and interface with the parallel 

mechanical screening efforts.

2.1.4.7.2 Staff Evaluation

The staff evaluated LRA Section 2.1.2 and the guidance contained in the implementing 

procedures and reports to perform the review of the electrical scoping process. The staff 

reviewed the applicant’s approach to identifying electrical and I&C SSCs relied upon to perform 

the functions described in 10 CFR 54.4(a). The staff reviewed portions of the documentation 

used by the applicant to perform the electrical scoping process including the UFSAR, CLB 

documentation, documents, procedures, drawings, specifications, and codes and standards.

The staff noted that, after the scoping of electrical and I&C components was performed, the 

in-scope electrical components were categorized into electrical component types. Component 

types include similar electrical and I&C components with common characteristics. 

Component-level intended functions of the component types were identified—such as cable, 

connections, fuse holders, terminal blocks, high-voltage transmission conductor, connections 

and insulators, metal enclosed bus, switchyard bus, and connections.

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 that were identified within the scope of license renewal. The staff 

determined that the applicant included electrical and I&C components and also electrical and 

I&C components contained in mechanical or structural systems within the scope of license 

renewal on a commodity basis.
Structures and Components Subject to Aging Management Review

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2.1.4.7.3 Conclusion

On the basis of its review of information contained in the LRA, scoping implementing 

procedures, scoping bases documents, and a sampling review of electrical scoping results, the 

staff concludes that the applicant’s methodology for the scoping of electrical components within 

the scope of license renewal is in accordance with the requirements of 10 CFR 54.4, and 

therefore, is acceptable.

2.1.4.8 Scoping Methodology Conclusion

On the basis of 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 within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(1)–10 CFR 54.4(a)(3). The staff 

concludes 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

2.1.5.1.1 Summary of Technical Information in the Application

LRA Section 2.1.3, “Screening Methodology,” states, in part:

Structures and components (or component commodity groups) 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 process was used to identify the passive, long-lived 

structures and components in the scope of License Renewal and subject to aging 

management review. The Seabrook Station screening process determines the 

structures and components subject to aging management review by:

• Listing the in-scope structures and components by component type,

• Screening component types by using the passive and long lived criteria, 

and

• Identifying the intended functions performed by these structures and 

components by component type.

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

Applications for Nuclear Power Plants” and NEI 95-10, Appendix B were used as 

the basis for the identification of passive structures and components. Most 

passive structures and components are long-lived. In the few cases where a 

passive component is determined not to be long-lived, such determination is 

documented in the screening evaluation (e.g., solenoid valves that are 

periodically replaced).
Structures and Components Subject to Aging Management Review

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Intended functions used to define passive structures and components are 

identified in LRA Table 2.1-1. Structures and components may have multiple 

intended functions (e.g., heat exchanger with heat transfer and pressure 

boundary-intended functions). Seabrook Station has considered multiple 

intended functions where applicable, consistent with the staff guidance provided 

in Tables 2.1-4(a) and (b) of NUREG-1800, “Standard Review Plan for Review of 

License Renewal Applications for Nuclear Power Plants.” If a component did not 

have at least one component-level intended function, the component was not 

subject to an aging management review.

Detailed scoping and screening reports have been prepared which identify all 

structures and components subject to an aging management review. These 

reports have been prepared for all systems, structures, or commodity groups 

(except electrical commodities) in-scope for License Renewal.

Passive, long lived electrical commodities subject to an aging management 

review were identified using guidance in NEI 95-10.

The Seabrook Station structures and components subject to aging management 

review have been identified in accordance with the requirements of 

10 CFR 54.21(a)(1).

2.1.5.1.2 Staff Evaluation

Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies SCs within the scope 

of license renewal 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 (long-lived). In addition, the IPA must include a description and justification of the

methodology used to determine the passive and long-lived SCs and a demonstration that the 

effects of aging on those SCs will be adequately managed so that the intended function(s) will 

be maintained under all design conditions imposed by the plant-specific CLB for the period of 

extended operation.

The staff reviewed the methodology used by the applicant to identify the mechanical and 

structural components and electrical commodity groups within the scope of license renewal that 

should be 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). In LRA 

Section 2.1.3, the applicant discusses these screening activities as they related to the 

component types and commodity groups within the scope of license renewal.

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 LRA Section 2.3, “Scoping 

and Screening Results: Mechanical Systems,” LRA Section 2.4, “Scoping and Screening 

Results: Structures,” and LRA Section 2.5, “Scoping and Screening Results: Electrical and 

Instrumentation and Controls Systems (I&C) Systems/Commodity Groups.” These sections of 

the LRA provided the results of the process used to identify component types and commodity 

groups subject to an AMR. The staff also reviewed, on a sampling basis, the screening results 

reports for safety injection (SI) and shutdown cooling, diesel generator fuel oil storage and 

transfer, auxiliary feedwater, and the turbine building.
Structures and Components Subject to Aging Management Review

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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. The specific methodology for mechanical, electrical, and structural is discussed 

in SER Sections 2.1.5.2 through 2.1.5.4.

2.1.5.1.3 Conclusion

On the basis of a review of the LRA, the implementing procedures, and a sampling of screening 

results, the staff concludes that the applicant’s screening methodology is consistent with the 

guidance contained in the SRP-LR and is capable of identifying passive, long-lived components

within the scope of license renewal that are subject to an AMR. The staff concludes that the 

applicant’s process for determining which component types and commodity groups are subject 

to an AMR is consistent with the requirements of 10 CFR 54.21 and, therefore, is acceptable

2.1.5.2 Mechanical Component Screening

2.1.5.2.1 Summary of Technical Information in the Application

LRA Section 2.1.3 states, in part, the following with regard to mechanical screening:

Mechanical components have been screened with the system in which they were 

scoped. Plant components such as heat exchangers and coolers that have 

License Renewal-intended functions that are unique have been identified at the 

subcomponent level to ensure all the intended functions and material / 

environment combinations are considered in the evaluation (e.g., channel head, 

shell, tubes, and tube sheet).

2.1.5.2.2 Staff Evaluation

The staff reviewed the mechanical screening methodology discussed and documented in LRA 

Section 2.1.3, the implementing documents, the scoping and screening reports, and the license 

renewal drawings. The staff determined that the mechanical system screening process began 

with the results from the scoping process and that the applicant reviewed each system 

evaluation boundary as depicted on the P&IDs to identify passive and long-lived components. 

Additionally, the staff determined that the applicant had identified all passive and long-lived 

components that perform or support an intended function within the system evaluation 

boundaries and determined those components to be subject to an AMR. The results of the 

review were documented in the scoping and screening reports, which contain information such 

as the information sources reviewed and the component intended functions.

The staff verified that mechanical system evaluation boundaries were established for each 

system within the scope of license renewal and that the boundaries were determined by 

mapping the system-intended function boundary onto P&IDs. The staff confirmed that the 

applicant reviewed the components within the system-intended function boundary to determine 

if the component supported the system-intended function and that those components that 

supported the system-intended function were reviewed to determine if the component was 

passive and long-lived and, therefore, subject to an AMR.

During the scoping and screening methodology audit, the staff reviewed selected portions of the 

UFSAR, plant equipment database, CLB documentation, Seabrook databases and documents, 

procedures, drawings, specifications, and selected scoping and screening reports. The staff 
Structures and Components Subject to Aging Management Review

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conducted discussions with the applicant’s license renewal team and reviewed documentation 

pertinent to the screening process. The staff also performed a walkdown of portions of the 

selected systems with plant engineers to verify documentation. The staff assessed whether the 

mechanical screening methodology outlined in the LRA and procedures was appropriately 

implemented and if the scoping results were consistent with CLB requirements. In addition, 

during the scoping and screening methodology audit, the staff discussed the screening 

methodology with the applicant and, on a sampling basis, reviewed the applicant’s screening 

reports for the diesel generator, plant floor drains, roof drain system, service water system, 

spent fuel pool system, and feedwater system to verify proper implementation of the screening 

process. Based on these audit activities, the staff did not identify any discrepancies between 

the methodology documented and the implementation results.

2.1.5.2.3 Conclusion

On the basis of its review of the LRA, the screening implementation procedures, selected 

portions of the UFSAR, plant equipment database, CLB documentation, procedures, drawings, 

specifications and selected scoping and screening reports, and a sample of the SI and 

shutdown cooling system, diesel generator fuel oil storage and transfer system, and auxiliary 

feedwater system, the staff concludes that the applicant’s methodology for identification of 

mechanical components within the scope of license renewal and subject to an AMR is in 

accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.3 Structural Component Screening

2.1.5.3.1 Summary of Technical Information in the Application

LRA Section 2.1.3 states, in part, the following with regard to civil and structural screening:

The screening process was applied to in-scope buildings and civil structures to 

identify the structural elements to be evaluated in the aging management 

reviews. 

The Seabrook Station scoping and screening process used a “spaces” approach 

in establishing the evaluation boundaries. With few exceptions, the scoping and 

screening boundary for a building or structure is an entire building or buildings, 

including the doors, supports, base slabs, foundations, walls, beams, slabs, 

roofs, penetration seals and structural steel. The various types of structural 

elements, and materials that make up the buildings were identified and listed. 

The listing of structural elements is facilitated by grouping them into component 

groups. Structural components/commodities often do not have unique identifiers 

such as those given to mechanical components. Therefore, identifying structural 

components as commodities based on materials of construction, their 

environment and functional applications provided an identification system for 

aging management reviews.

A list of structural commodities (example; carbon steel with indoor air includes, 

but is not limited to: carbon steel decking, embedments, fasteners, grating, other 

miscellaneous steel such as fire walls made from carbon steel siding, doors, 

plates, platforms, rails for hoists, and shapes) was developed for each 

civil/structural evaluation boundary. Structural commodities that perform an 

intended function without moving parts and without a change in configuration or 
Structures and Components Subject to Aging Management Review

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properties, and that are not subject to replacement based on a qualified life or 

specified time period, are subject to aging management review.

2.1.5.3.2 Staff Evaluation

The staff reviewed the structural screening methodology discussed and documented in LRA 

Sections 2.1.3, implementing procedures and guidelines, scoping and screening reports, and 

the license renewal structures drawing. The staff reviewed the applicant’s commodity group 

methodology for identifying structural components that are subject to an AMR, as required in 

10 CFR 54.21(a)(1). The staff confirmed that the applicant reviewed the structures included 

within the scope of license renewal and identified the passive, long-lived components with 

component-level intended functions and determined those components to be subject to an 

AMR.

The staff reviewed selected portions of the UFSAR, structure system information, and scoping 

and screening reports the applicant used to perform the structural scoping and screening. The 

staff also reviewed screening activities, on a sampling basis, that documented the SCs within 

the scope of license renewal. The staff conducted detailed discussions with the applicant’s 

license renewal team and reviewed documentation pertinent to the screening process to assess 

if the screening methodology outlined in the LRA and implementing procedures was 

appropriately implemented and if the scoping results were consistent with CLB requirements.

2.1.5.3.3 Conclusion

On the basis of its review of information contained in the LRA, implementing procedures and 

guidelines, plant equipment database, and a sampling of the structural screening results, the 

staff concludes that the applicant’s methodology for identification of structural components 

within the scope of license renewal and subject to an AMR is in accordance with the 

requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.4 Electrical Component Screening

2.1.5.4.1 Summary of Technical Information in the Application

LRA Section 2.1.3 states the following, in part, in regard to electrical screening:

Screening of electrical and I&C components used a bounding approach as 

described in NEI 95-10. All Electrical and I&C systems were considered 

in-scope. Electrical and I&C components were assigned to a commodity 

grouping. The commodity groups subject to an aging management review were 

identified by applying the criteria of 10 CFR 54.21(a)(1). This method provided 

the most efficient means for determining the electrical commodity groups subject 

to an aging management review since many of the electrical components are 

active.

The sequence of steps used by Seabrook Station for identification of electrical 

commodity groups that require an aging management review included the 

following:

(1) The criteria of 10 CFR 54.21(a)(1)(i) was applied to identify commodity 

groups that perform their intended functions without moving parts or 

without a change in configuration or properties (referred to as “passive” 
Structures and Components Subject to Aging Management Review

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components). These electrical commodity groups were identified utilizing 

the guidance of NEI 95-10.

(2) Portions of electrical commodity groups that perform no License 

Renewal-intended functions do not require aging management review 

and were not considered further (e.g., ground conductors, switchyard 

components outside of SBO boundary).

(3) The screening criterion found in 10 CFR 54.21(a)(1)(ii) excludes those 

commodity groups that are subject to replacement based on a qualified 

life or specific time period from the requirements of an aging management 

review. The 10 CFR 54.21(a)(1)(ii) screening criterion was applied to 

those commodity groups that were not previously eliminated by

application of the 10 CFR 54.21(a)(1)(i) criteria or because they do not 

perform a License Renewal-intended function. 

(4) The electrical commodities that require an aging management review are 

passive electrical commodities. The passive commodity groups that are 

not subject to replacement based on a qualified life or specified time 

period (long-lived) are subject to an aging management review.

2.1.5.4.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for electrical component screening in LRA 

Sections 2.1.3 and 2.5, the applicant’s implementing procedures, bases documents, and 

electrical AMR 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 electrical and I&C components subject to an AMR.

The staff determined that the applicant identified 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 if they were subject to replacement based on a 

qualified life or specified time period (short-lived) or not subject to replacement based on a 

qualified life or specified time period (long-lived). The remaining passive, long-lived 

components were determined to be subject to an AMR.

The staff performed a review to determine if the screening methodology outlined in the LRA and 

implementing procedures were appropriately implemented and if the scoping results were 

consistent with CLB requirements. During the scoping and screening methodology audit, the 

staff reviewed selected screening reports and discussed the reports with the applicant to verify 

proper implementation of the screening process. Based on these onsite review activities, the 

staff did not identify any discrepancies between the methodology documented and the 

implementation results.

2.1.5.4.3 Conclusion

On the basis of its review of the LRA the screening implementation procedures, selected 

portions of the UFSAR, CLB documentation, procedures, drawings, specifications and selected 

scoping and screening reports, discussion with the applicant, and a sample of the results of the 

screening methodology, the staff concludes that the applicant’s methodology for identification of 

electrical components within the scope of license renewal and subject to an AMR is in 

accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.
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2.1.5.5 Screening Methodology Conclusion

On the basis of its review of the LRA, the screening implementing procedures, discussions with 

the applicant’s staff, and a sample review of screening results, the staff concludes that the 

applicant's screening methodology was consistent with the guidance contained in the SRP-LR 

and identified those passive, long-lived components within the scope of license renewal that are 

subject to an AMR. The staff concludes that the applicant’s methodology is consistent with the 

requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.6 Summary of Evaluation Findings

On the basis of its review of the information presented in LRA Section 2.1, the supporting 

information in the scoping and screening implementing procedures and reports, the information 

presented during the scoping and screening methodology audit, discussions with the applicant,

sample system reviews, and the applicant’s responses dated February 3, 2011, to the staff’s 

RAIs, 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

2.2.1 Introduction

Plant-Level Scoping Results

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 if the applicant has properly identified the 

following:

• all systems and structures relied upon to mitigate DBEs, as required by 

10 CFR 54.4(a)(1)

• systems and structures whose failure could prevent satisfactory accomplishment of any 

safety-related functions, as required by 10 CFR 54.4(a)(2)

• 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, electrical and I&C systems, and 

structures 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.
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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 its evaluation is provided in SER Section 2.1. To 

verify that the applicant properly implemented its methodology, the staff’s review focused on the 

implementation results shown in LRA Tables 2.2-1, “Systems and Structures within the Scope of 

License Renewal,” and 2.2-2, “Systems and Structures Not in the Scope of License Renewal” to 

confirm that there were no omissions of plant-level systems and structures within the scope of 

license renewal.

The staff determined whether the applicant properly identified the systems and structures within 

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected 

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 

within the scope of license renewal. The staff’s review of the applicant’s implementation was 

conducted in accordance with the guidance in SRP-LR Section 2.2, “Plant-Level Scoping 

Results.”

The staff noted that, in LRA Section 2.3.3.45, the waste process building is indicated as being 

not in-scope for license renewal. However, in LRA Section 2.4.5, the applicant states that the 

waste process building is in-scope for 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 

10 CFR 54.4(a)(3) and is included in Table 2.2-1. By letter dated January 5, 2011, the staff 

issued RAI 2.2-01 and requested that the applicant clarify if the waste process building is within 

the scope of license renewal.

In its response dated February 3, 2011, the applicant stated that the waste process building is 

within scope of license renewal and provided a revised LRA Section 2.3.3.45 to indicate that the 

waste process building is in-scope.

Based on its review, the staff finds the applicant’s response to RAI 2.2-01 acceptable because 

the applicant revised LRA Section 2.3.3.45 to specify that the waste process building is within 

scope of license renewal. Therefore, the staff’s concern described in RAI 2.2-01 is resolved

2.2.4 Conclusion

On the basis of its review of the LRA Section 2.2, the RAI response, and the UFSAR supporting 

information to determine whether the applicant failed to identify any systems and structures 

within the scope of license renewal, the staff concludes that the applicant has appropriately 

identified the systems and structures within the scope of license renewal, in accordance with 

10 CFR 54.4.

2.3

This section documents the staff’s review of the applicant’s scoping and screening results for

mechanical systems. Specifically, this section describes the following mechanical systems:

Scoping and Screening Results: Mechanical Systems

• reactor vessel, internals, and reactor coolant system (RCS)

• engineered safety features systems

• auxiliary systems

• steam and power conversion systems
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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 verify that the applicant identified the

mechanical system SCs that met the scoping criteria and were subject to an AMR and that there

were no omissions. The staff’s evaluation of mechanical systems was performed using the

evaluation methodology described in this SER and in the guidance of SRP-LR Section 2.3, and

it took into account, where applicable, the system functions described in the UFSAR. The

objective was to determine if the applicant identified, in accordance with 10 CFR 54.4, 

components and supporting structures for mechanical systems that meet the license renewal 

scoping criteria. Similarly, the staff evaluated the applicant’s screening results to verify that all 

passive, long-lived components are subject to an AMR, as required by 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the LRA, applicable sections of the UFSAR, license

renewal boundary drawings, and other licensing basis documents, as appropriate, for each

mechanical system within the scope of license renewal. The staff reviewed relevant licensing

basis documents for each mechanical system to confirm that the LRA specified all intended

functions defined by 10 CFR 54.4(a). The review then focused on identifying any components

with intended functions defined by 10 CFR 54.4(a) that the applicant may have omitted from the

scope of license renewal.

After reviewing the scoping results, the staff evaluated the applicant’s screening results. For

those SCs with intended functions required by 10 CFR 54.4(a), the staff verified the applicant

properly screened out SCs that have functions performed with moving parts or a change in 

configuration or properties or SCs that are subject to replacement after a qualified life or 

specified time period, as described in 10 CFR 54.21(a)(1). For SCs not meeting either of these 

criteria, the staff confirmed the remaining SCs received an AMR, as required by

10 CFR 54.21(a)(1).

The staff evaluation of the mechanical system scoping and screening results applies to all

mechanical systems reviewed. Those systems that required RAIs to be generated include an

additional staff evaluation, which specifically addresses the applicant’s responses to the RAIs.

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

LRA Section 2.3.1 identifies the reactor vessel, internals, and reactor coolant system SCs 

subject to an AMR for license renewal.

The applicant described the supporting SCs of the reactor vessel, internals, and RCS in the 

following LRA sections:

• Section 2.3.1.1, “Reactor Coolant (RC) System”

• Section 2.3.1.2, “Reactor Vessel (RV)”

• Section 2.3.1.3, “Reactor Vessel Internals (RVI)”

• Section 2.3.1.4, “Steam Generators (SG)”

The staff’s findings on review of LRA Sections 2.3.1.1–2.3.1.4 are provided in SER 

Sections 2.3.1.1–2.3.1.4, respectively.
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2.3.1.1 Reactor Coolant System

2.3.1.1.1 Summary of Technical Information in the Application

The reactor coolant (RC) system consists of four heat transfer loops connected in parallel to the 

reactor pressure vessel. Each loop contains a reactor coolant pump, a steam generator, and 

associated piping and valves. In addition, the RC system includes a pressurizer, pressurizer 

relief tank, pressurizer relief and safety valves, interconnecting piping, and instrumentation 

necessary for operational control.

During operation, the RC system transfers the heat generated in the core to the steam 

generators, where steam is produced to drive the turbine generator. Borated demineralized 

water is circulated in the RC system at a flow and temperature consistent with achieving the 

reactor core thermal-hydraulic performance. The water acts as a neutron moderator and as a 

neutron absorber. The RC system pressure is controlled by the use of the pressurizer, where 

water and steam are maintained in equilibrium by electrical heaters and water sprays.

The RC system pressure boundary provides a barrier against the release of radioactivity 

generated within the reactor and is designed to ensure a high degree of integrity throughout the 

life of the plant.

The intended functions of the RC system component types within the scope of license renewal 

include the following:

• serve as a pressure boundary and limit the release of fission products

• provide RC system pressure control and limit pressure transients

• provide the borated water used as a neutron moderator and as a neutron absorber

• provide a containment isolation function

The following license renewal drawings provide the details of SSCs for the scope of license 

renewal and subject to an AMR:

• PID-1-CS-LR20722

• PID-1-RH-LR20662

• PID-1-SI-LR20450

• PID-1-VSL-LR20777

• PID-1-WLD-LR20221

• PID-1-RC-LR20841–PID-1-RC-LR20846

• PID-1-RH-LR20663

• PID-1-SS-LR20518

• PID-1-WLD-LR20218

• PID-1-SI-LR20448

• PID-1-SS-LR20520

• PID-1-WLD-LR20219

LRA Table 2.3.1-1 lists the RC system components types that require AMR.

2.3.1.1.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA 

and UFSAR, the staff concluded that the applicant appropriately identified the RC system
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components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified the RC system components subject to an 

AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.2 Reactor Vessel

2.3.1.2.1 Summary of Technical Information in the Application

The reactor vessel is a vertical cylinder with a welded hemispherical bottom head and a 

removable, flanged hemispherical upper head. The vessel contains the core, core supporting 

structures, control rods, and other parts directly associated with the core. The vessel has four 

inlet and four outlet nozzles located in a horizontal plane just below the reactor vessel flange but 

above the top of the core. The coolant enters the vessel through the inlet nozzles, flows down 

the core barrel-vessel wall annulus, turns at the bottom, and flows up through the core to the 

outlet nozzles.

Both the upper and lower reactor vessel heads contain penetrations, which are used for 

instrumentation or control devices. The lower reactor vessel head has penetrations for 58 

incore nuclear instrumentation thimbles, while the reactor vessel upper head contains 79 control 

rod drive mechanism (CRDM) penetrations.

The reactor vessel is supported by steel pads on four of the coolant nozzles. The steel pads

rest on steel base plates atop a support structure that is attached to the concrete foundation 

wall. There are three lifting lugs evenly spaced around the upper head, which are used to move 

it.

The intended functions of the reactor vessel component types within the scope of license 

renewal include the following:

• serve as a pressure boundary for containing reactor coolant

• provide a barrier against the release of radioactivity

• support and contain the reactor core and core support structures

• support and guide reactor controls and instrumentation

• mitigate thermal shock

The following license renewal drawing provides the details of SSCs for the scope of license 

renewal and subject to an AMR:

• PID-1-RC-LR20845

LRA Table 2.3.1-2 lists the reactor vessel components types that require AMR.

2.3.1.2.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA 

and UFSAR, the staff concluded that the applicant appropriately identified the reactor vessel 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified the reactor vessel components subject to an 

AMR, as required by 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 internals are divided into three parts—the lower core support structure, the 

upper core support structure, and the incore instrumentation support structure.

The reactor vessel internals support the core, maintain fuel alignment, limit fuel assembly 

movement, maintain alignment between fuel assemblies and CRDM, direct coolant flow past the 

fuel elements, direct coolant flow to the pressure vessel head, provide gamma and neutron 

shielding, and provide guides for the incore instrumentation.

The lower core support structure assembly consists of the core barrel, the core baffle, the lower 

core plate and support columns, the neutron shields pads, the core support that is welded to the 

core barrel, reactor fuel, and rod cluster control assemblies. The upper core support assembly 

consists of the top support plate assembly and the upper core plate, between which are 

contained support columns and guide tube assemblies. The incore instrumentation support 

structure consists of a guide tubing system to convey and support flux thimbles penetrating the 

vessel through the bottom.

The intended functions of the reactor vessel internals components types within the scope of 

license renewal include the following:

• support the reactor core

• maintain fuel alignment between fuel assemblies and control rods

• direct coolant flow to the vessel head

• provide gamma and neutron shielding

• guide the incore instruments

LRA Table 2.3.1-3 lists the reactor vessel internals component types that require AMR.

2.3.1.3.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA 

and UFSAR, the staff concluded that the applicant appropriately identified the reactor vessel 

internals components within the scope of license renewal, as required by 10 CFR 54.4(a). The 

staff also concluded that the applicant adequately identified the reactor vessel internals 

components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.4 Steam Generators

2.3.1.4.1 Summary of Technical Information in the Application

The steam generators transfer heat from the RC system to the secondary system during normal 

plant conditions, producing steam for use in the turbine generator. Each steam generator 

includes a primary section called the tube side, which includes components such as 

hemispherical channel head with a divider plate, tube sheet, and U-tubes. The channel head 

makes up the bottom of the steam generator. The shell of the steam generator is a vertical 

cylinder. The tube sheet is welded to the bottom of the cylinder. The secondary section of the 

steam generator is referred to as the shell side. The upper shell houses the moisture

separation equipment. The steam-water mixture from the tube bundle passes through the 
Structures and Components Subject to Aging Management Review

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moisture separator equipment to ensure that high-quality steam is produced by the steam 

generators.

The intended functions of the steam generator component types within the scope of license 

renewal include the following:

• transfer heat from the RC system to the secondary systems

• provide RC system pressure boundary function

• confine radioactive material

The following license renewal drawings provide the details of the SSCs for the scope of license 

renewal and subject to an AMR:

• PID-1-FW-LR20686

• PID-1-RC-LR20841–PID-1-RC-LR20844

• PID-1-MS-LR20580

• PID-1-MS-LR20581

LRA Table 2.3.1-4 lists the steam generator components types that require AMR.

2.3.1.4.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the LRA 

and UFSAR, the staff concluded that the applicant appropriately identified the steam generator 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified the steam generator components subject to 

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2 Engineered Safety Features

LRA Section 2.3.2 identifies the engineered safety features SCs subject to an AMR for license 

renewal.

The applicant described the supporting SCs of the engineered safety features in the following 

LRA sections:

• Section 2.3.2.1, “Combustible Gas Control (CGC) System”

• Section 2.3.2.2, “Containment Building Spray (CBS)System”

• Section 2.3.2.3, “Residual Heat Removal (RH) System”

• Section 2.3.2.4, “Safety Injection (SI) System”

The staff’s findings on review of LRA Sections 2.3.2.1–2.3.2.4 are provided in SER 

Sections 2.3.2.1–2.3.2.4, respectively.

2.3.2.1 Combustible Gas Control System

2.3.2.1.1 Summary of Technical Information in the Application

LRA Section 2.3.2.1 describes the combustible gas control system, which consists of 

subsystems that monitor the combustible gas concentrations in the containment and maintain a 

mixed containment atmosphere to ensure that hydrogen (H2) concentrations remain below 
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flammable levels following a LOCA. This is achieved by monitoring containment H2 levels, 

mixing the containment atmosphere, recombining free H2 with oxygen, or purging the 

containment atmosphere.

The containment atmosphere is monitored by two completely independent H2 sampling and 

analysis systems, which are started after an accident. One means of combustible gas control in 

the containment is through the use of electric H2 recombiners. Seabrook has a pair of 

recombiners, located at the perimeter of the operating floor inside the containment. Purging is 

accomplished by venting the containment gas and replacing it with clean compressed air from 

the plant air system. Compressed air is fed into the containment.

2.3.2.1.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the combustible gas control system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the combustible gas control system components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.2.2 Containment Building Spray System

2.3.2.2.1 Summary of Technical Information in the Application

The containment building spray system is designed to remove the energy discharged to the 

containment following a LOCA or main steam line break, to prevent the containment pressure 

from exceeding design pressure, and to reduce and maintain containment temperature and 

pressure within acceptable limits. The containment building spray system provides for iodine 

removal by mixing sodium hydroxide (NaOH) with borated water from the refueling water 

storage tank (RWST) to limit the consequences of a LOCA to within the limits of 

10 CFR Part 100 by providing a rapid reduction in containment elemental iodine concentration. 

The limits on NaOH volume and concentration ensure a pH value of between 8.5–11.0 for the 

solution recirculated within containment after a LOCA. This pH band minimizes the evolution of 

iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems 

and components.

2.3.2.2.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the containment building spray system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the containment building spray system components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.2.3 Residual Heat Removal System

2.3.2.3.1 Summary of Technical Information in the Application

The residual heat removal (RH) system transfers heat from the RCS to the primary component

cooling water system to reduce the temperature of the RCS to the cold shutdown temperature, 
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at a controlled rate, during the normal plant cooldown. The RH system is provided with two 

RHR pumps and two residual heat exchangers arranged in two separate and independent flow 

paths.

The RH system also makes up the low-head SI portion of the emergency core cooling system 

(ECCS) by injecting borated water from the RWST into the RCS cold legs during injection phase 

following a LOCA. The RH system is also used to transfer water between the refueling cavity 

and the RWST at the beginning and end of the refueling operations.

The intended functions of the RH system component types within the scope of license renewal 

include the following:

• form a part of the RCS pressure boundary

• remove decay heat in post-accident and normal shutdown conditions

• provide protection against over-pressurization and rupture of ECCS low pressure piping 

that could result in a LOCA

• provide borated water for RCS makeup in LOCA conditions

The following license renewal drawings provide the details of SSCs for the scope of license 

renewal and subject to an AMR:

• PID-1-CBS-LR20233

• PID-1-RC-LR20841

• PID-1-RH-LR20663

• PID-1-VSL-LR20776

• PID-1-CS-LR20722

• PID-1-RC-LR20844

• PID-1-CS-LR20725

• PID-1-SI-LR20446–PID-1-RH-LR20662

• PID-1-WLD-LR20221

• PID-1-SI-LR20450

LRA Table 2.3.2-3 lists the RH system component types that require AMR.

2.3.2.3.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the RH system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified 

the RH system components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.4 Safety Injection System

2.3.2.4.1 Summary of Technical Information in the Application

The safety injection (SI) system provides emergency core cooling to the reactor core as a part 

of the ECCS. The ECCS consists of three separate subsystems—centrifugal charging (high 

head), SI (intermediate head), and RH (low head). Each subsystem consists of two redundant, 
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100 percent capacity trains. The ECCS also includes four accumulators (one on each RCS 

loop) and the RWST.

The SI system consists of accumulators, SI pumps, RWST, and associated piping and valves. 

Four accumulators, which are filled with borated water and pressurized with nitrogen gas, are 

connected to the four cold legs. The SI system has two phases of operation—the injection 

phase and the recirculation phase.

The injection phase provides core cooling and additional negative reactivity following actuation. 

The SI pumps take their suction from the RWST during injection phase. The recirculation phase 

provides long-term post-accident cooling by recirculating water from the containment sump.

The intended functions of the SI system component types within the scope of license renewal 

include the following:

• form part of the RCS pressure boundary

• provide source of emergency core cooling in response to a LOCA

• provide containment isolation function

• protect against over-pressurization and rupture of ECCS low pressure piping

• provide mechanical support for safety-related SSCs

The following license renewal drawings provide the details of the SSCs for the scope of license 

renewal and subject to an AMR:

• PID-1-BRS-LR20854

• PID-1-RC-LR20844

• PID-1-SI-LR20446–PID-1-SI-LR20450

• PID-1-WLD-LR20219

• PID-1-CBS-LR20233

• PID-1-RH-LR20662–PID-1-RH-LR20663

• PID-1-WLD-LR20221

• PID-1-RC-LR20841

• PID-1-WLD-LR20218

LRA Table 2.3.3-4 lists the SI component types that require AMR.

2.3.2.4.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the SI system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified 

the SI system components subject to an AMR, as required by 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:
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• Section 2.3.3.1, “Auxiliary Boiler (AB) System”

• Section 2.3.3.2, “Boron Recovery (BRS)System”

• Section 2.3.3.3, “Chemical and Volume Control (CS) System”

• Section 2.3.3.4, “Chlorination (CL) System”

• Section 2.3.3.5, “Containment Air Handling (CAH) System”

• Section 2.3.3.6, “Containment Air Purge (CAP) System”

• Section 2.3.3.7, “Containment Enclosure Air Handling (EAH) System”

• Section 2.3.3.8, “Containment Online Purge (COP) System”

• Section 2.3.3.9, “Control Building Air Handling (CBA) System”

• Section 2.3.3.10, “Demineralized Water (DM) System”

• Section 2.3.3.11, “Dewatering (DW) System”

• Section 2.3.3.12, “Diesel Generator(DG) System”

• Section 2.3.3.13, “Diesel Generator Air Handling (DAH) System”

• Section 2.3.3.14, “Emergency Feed Water Pump House Air Handling (EPA) System”

• Section 2.3.3.15, “Fire Protection (FP) System”

• Section 2.3.3.16, “Fuel Handling (FH) System”

• Section 2.3.3.17, “Fuel Oil (FO) System”

• Section 2.3.3.18, “Fuel Storage Building Air Handling (FAH) System”

• Section 2.3.3.19, “Hot Water Heating (HW) System”

• Section 2.3.3.20, “Instrument Air (IA) System”

• Section 2.3.3.21, “Leak Detection (LD) System”

• Section 2.3.3.22, “Mechanical Seal Supply (MSS) System”

• Section 2.3.3.23, “Miscellaneous Equipment (MM)”

• Section 2.3.3.24, “Nitrogen Gas (NG) System”

• Section 2.3.3.25, “Oil Collection for Reactor Coolant Pumps (OC) System”

• Section 2.3.3.26, “Plant Floor Drain (DF) System”

• Section 2.3.3.27, “Potable Water (PW) System”

• Section 2.3.3.28, “Primary Auxiliary Building Air Handling (PAH) System”

• Section 2.3.3.29, “Primary Component Cooling Water (CC) System”

• Section 2.3.3.30, “Radiation Monitoring (RM) System”

• Section 2.3.3.31, “Reactor Makeup Water (RMW) System”

• Section 2.3.3.32, “Release Recovery (RR) System”

• Section 2.3.3.33, “Resin Sluicing (RS) System”

• Section 2.3.3.34, “Roof Drains (DR) System”

• Section 2.3.3.35, “Sample (SS) System”

• Section 2.3.3.36, “Screen Wash (SCW) System”

• Section 2.3.3.37, “Service Water (SW) System”

• Section 2.3.3.38, “Service Water Pump House Air Handling (SWA) System”

• Section 2.3.3.39, “Spent Fuel Pool Cooling (SF) System”

• Section 2.3.3.40, “Switchyard (SY) System”

• Section 2.3.3.41, “Valve Stem Leak-off (VSL) System”

• Section 2.3.3.42, “Vent Gas (VG) System”

• Section 2.3.3.43, “Waste Gas (WG) System”

• Section 2.3.3.44, “Waste Processing Liquid (WL) System”

• Section 2.3.3.45, “Waste Processing Liquid Drains (WLD) System”

The staff’s findings on review of LRA Sections 2.3.3.1–2.3.3.45 are provided in SER 

Sections 2.3.3.1–2.3.3.45, respectively.
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During its review, the staff identified instances of boundary drawing errors where continuation 

notation for piping from one boundary drawing to another boundary drawing could not be 

identified or was incorrect.

By letter dated January 5, 2011, the staff issued RAI 2.3-01 and noted 13 instances where the 

staff was unable to identify the license renewal boundary because either the continuations were 

not provided or were incorrect or the continuation drawing was not provided. The applicant was 

asked to provide additional information to locate the continuations.

In its response dated February 3, 2011, the applicant provided sufficient information to locate 

the license renewal boundaries. No additional piping or component types were included in the 

scope of license renewal. The applicant also indicated that no continuation drawings were 

needed for piping that terminated at the nearby floor drains. The applicant described stated

components such as instrumentation and components found on vendor drawings were already 

included within the scope of license renewal but not depicted on the LRA drawings.

Based on its review, the staff finds the applicant’s response to RAI 2.3-01 acceptable. No

additional systems or components were required to be added to the scope of license renewal. 

Therefore, the staff’s concern described in RAI 2.3-01 is resolved.

2.3.3.1 Auxiliary Boiler

2.3.3.1.1 Summary of Technical Information in the Application

The auxiliary boiler system is a subsystem of the auxiliary steam system. The auxiliary boiler 

system provides steam to the auxiliary steam system, which in turn provides process steam for 

various plant heating loads.

There are two main purposes of the auxiliary boiler system: to provide steam to the auxiliary 

steam system and to provide fuel oil to the fire pump house boiler. The fire pump house boiler 

provides steam to heat the fire water storage tank and provides steam to the fire pump house 

unit heaters.

The auxiliary boiler system consists of two package boilers, which include a de-aerating heater 

with storage tank, boiler feed pumps, fuel oil pumps, and a blowdown tank. Also included are 

the fuel oil storage tank and the associated piping. The portion of the auxiliary boiler system 

that supplies oil to the fire pump house boiler consists of piping from the fuel oil storage tank to 

the fire pump house boiler and the fire pump house boiler oil pumps.

2.3.3.1.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the auxiliary boiler system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the auxiliary boiler system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).
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2.3.3.2 Boron Recovery System

2.3.3.2.1 Summary of Technical Information in the Application

The boron recovery system stores and processes reactor coolant effluent and reactor coolant 

grade drainage for reuse in the plant or for disposal offsite. The system maximizes recycling of 

effluent back to the plant and minimizes the release of radioactive material to the environment 

by proper cleanup and volume reduction methods. The system process is a combination of 

degasification, demineralization, filtration, and evaporation. The boron recovery system is 

designed as NNS class and non-seismic Category I.

The boron recovery system is designed to do the following:

• process the reactor coolant letdown liquid generated by normal operations under either 

base loaded or load-following conditions

• permit startup from a cold shutdown condition (For conservatism, the plant is assumed 

to be in end-of-core-life conditions (50 parts per million (ppm) boron concentration), and 

evaporator availability is considered to be 75 percent of the time.)

• produce distillate from the boron evaporator with a maximum of 5 ppm boron and 

provide, by means of the boron demineralizers (mixed bed ion exchange units), the 

capability for reducing the boron concentration further, if so desired

• provide radioactivity decontamination and chemical purification such that, for reuse 

within the station, the system effluent meets the chemical purity requirements for 

recycled reactor makeup water and, for discharge from the station, the effluent meets 

required radioactivity release limitations

• accept and process any hydrogenated liquid drains collected in the primary drain tank

Other sources of liquid that can be transferred into the recovery test tanks (1-BRS-TK-58-A and

1-BRS-TK-58-B) include effluent from a skid-mounted waste liquid processing system should 

additional storage capacity be required prior to discharge.

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2, UFSAR Section 9.3.5, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. In addition to the continuation issue identified in RAI 2.3-01,

as described in Section 2.3.3, the staff’s review identified an area in which additional information 

was required 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 2.3.3.2-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-CS-LR20724, 

at location G-11, a section of safety-related 3 in. piping connected to nonsafety-related 3 in. 

piping at valve V-633. The piping section, located between valve V-633 and the seismic anchor 

located at G-9, is within the scope of license renewal for 10 CFR 54.4(a)(2). However, there is 

a 1 in. line that connects to the 3 in. nonsafety-related piping between valve V633 and the 

seismic anchor. This line continues and connects to a 3 in. piping section, which connects into 

a 3 in. line and 3

/4 in. line at location E-9. At location D-12 of LRA drawing PID-1-CS-LR20724, 

the 3 in. line continues through valves V-634, V-635, V-636 to a piping section that continues to 

LRA drawing PID-1-BRS-LR20856. This piping section is not depicted within the scope of
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license renewal. Additionally, at location D-12 of LRA drawing PID-1-CS-LR20724, the 3

/4 in.

line continues through valve V-835 to LRA drawing PID-1-SS-LR20519. Seismic anchors could 

not be located between the start of the 1 in. line (at location G-9 on LRA drawing 

PID-1-CS-LR20724) and the 3 in. and 3

/4 in. continuations (at location D-12 on LRA drawing 

PID-1-CS-LR20724). The applicant was asked to provide the location of the first seismic 

anchors on nonsafety-related piping past the safety and nonsafety interface for the above 

locations.

In its response dated February 3, 2011, the applicant clarified why the seismic anchors were not 

depicted on the LRA drawings. The applicant described the pipe support anchors, 303-A-01 

and 302-A-20, as being located beyond the safety and nonsafety interface to ensure that failure 

of the nonsafety-related piping does not affect the safety-related piping. The applicant also 

described the 302-A-20 anchor as being located at the tee intersection of the boron recovery 

system and chemical and volume control system (CS), which equally restrains the 1 in. piping. 

The applicant further indicated that the entire nonsafety-related piping is included within scope 

of license renewal and subject to AMR until the piping exits the primary auxiliary building and 

enters the waste process building, in which no seismic anchors are needed.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.2-01 acceptable 

because the staff confirmed that the description given in the applicant’s RAI response is 

consistent with its scoping methodology in LRA Section 2.1.2.2.2 for nonsafety-related piping 

attached to safety-related piping. Therefore, the staff’s concern described in RAI 2.3.3.2-01 is 

resolved.

2.3.3.2.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the boron recovery 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 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.3 Chemical and Volume Control System

2.3.3.3.1 Summary of Technical Information in the Application

The chemical and volume control system (CS) consists of the following subsystems:

• high-head injection part of the ECCS

• charging, letdown, and seal water system

• reactor coolant purification and chemistry control system

• reactor makeup control system

The CS is a support system for the RCS during all normal modes of plant operation. The 

centrifugal charging pumps serve as the high head SI pumps in the ECCS. The charging and 

letdown functions of the CS are employed to maintain a programmed level in the RCS 

pressurizer, thus maintaining proper reactor coolant inventory during all phases of plant 

operations. A portion of the charging flow is directed to the RCPs seals via a seal water 
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injection filter. The reactor coolant purification and chemistry control system maintain reactor 

coolant chemistry within Electric Power Research Institute (EPRI) specified guidelines. The 

soluble neutron absorber (boric acid) concentration is controlled by the reactor makeup control 

system.

The CS consists of three charging pumps, a letdown heat exchanger, a regenerative heat 

exchanger, a volume control tank, and associated pumps, piping, valves, and filters. The CS

also includes demineralizer vessels and chemical tanks associated with control of water 

chemistry in the RCS. The CS includes provisions for recycling reactor grade water and boric 

acid.

The intended functions of the CS component types within the scope of license renewal include

the following:

• maintain the RCS pressure boundary

• maintain water inventory in the RCS

• vary boron concentration for reactivity control

• supply water to the RCP seals for cooling and sealing purposes

• provide containment isolation function

• provide high head SI for emergency core cooling

The following license renewal drawings provide the details of SSCs for the scope of license 

renewal and subject to an AMR:

• PID-1-BRS-LR20854

• PID-1-CS-LR20722–PID-1-CS-LR20729

• PID-1-CBS-LR20233

• PID-1-RH-LR20663

• PID-1-RC-LR20846

• PID-1-SI-LR20446–PID-1-SI-LR20449

• PID-1-RS-LR20252

• PID-1-SS-LR20519 

• PID-1-WLD-LR20218

• PID-1-WLD-LR20223

• PID-1-CC-LR20212

• PID-1-RH-LR20662

• PID-1-RC-LR20841–PID-1-RC-LR20846

• PID-1-SF-LR20483

• PID-1-SS-LR20518

• PID-1-VSL-LR20775–PID-1-VSL-LR20777

• PID-1_WLD-LR20219

• PID-1-WLD-LR20222

LRA Table 2.3.3-3 lists the CS component types that require AMR.

2.3.3.3.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the CS component within the scope of license renewal, as required by 
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10 CFR 54.4(a). The staff also concluded that the applicant adequately identified the CS 

component subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.4 Chlorination System

2.3.3.4.1 Summary of Technical Information in the Application

The chlorination (CL) system provides sodium hypochlorite solution for injection into the 

circulating water system. Provisions for continuous low-level CL and heat treatment of the 

tunnels are included for control of fouling by marine organisms.

Sodium hypochlorite is injected into a common header that receives flow from the screen wash 

system pumps. The flow from this common header flows to the following locations:

• intake tunnel

• intake transition structure

• discharge transition structure.

• circulating water pump bays

• service water pump bays

The CL system is nonsafety-related.

2.3.3.4.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the CL system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the CL system mechanical components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.5 Containment Air Handling System

2.3.3.5.1 Summary of Technical Information in the Application

The containment air handling system is composed of three subsystems—the containment 

structure cooling system, the containment recirculation and filter system, and the CRDM cooling 

system. 

The containment structure cooling system is designed to maintain the normal ambient air 

temperature in the containment structure at or below 120° F. 

The containment recirculation and filter system is normally used to filter contaminated air within 

containment prior to personnel entry and whenever it is desired to reduce airborne particulate 

contamination and radioactive iodine. The filter subsystem, when operated in conjunction with 

the pre-entry purge subsystem, reduces the airborne iodine to an acceptable level, permitting 

access to containment within 24 hours after the reactor is shutdown. The fans, ductwork, and 

dampers associated with the containment recirculation subsystem are redundant, and, as such, 

a single failure will not render the system inoperative. Failure of the filter unit of the containment 

recirculation subsystem will not affect safe operation or shutdown of the plant since the air 

cleaning unit has no safety design bases. 
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The CRDM cooling system is designed to induce supply air into the CRDM shroud at or below 

120° F.

2.3.3.5.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the containment air handling system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the containment air handling system components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.3.6 Containment Air Purge System

2.3.3.6.1 Summary of Technical Information in the Application

The containment air purge system is composed of three subsystems—the containment structure 

air purge and heating subsystem, the pre-entry purge subsystem, and the refueling purge 

subsystem. 

The containment air purge and heating subsystem employs two supply fans and two exhaust 

fans with the common supply and exhaust ductwork. Each set consists of a supply air fan and 

exhaust air fan, each with pneumatically operated dampers. A common ductwork system, 

which includes the refueling purge supply and heating subsystem and the pre-entry purge 

subsystem. 

During pre-entry purge, a single fan supplies pre-entry purge air to the containment area using 

common supply ductwork. A single exhaust fan pulls air from containment through common 

exhaust ductwork and discharges directly to the unit plant vent after first passing through the 

filter unit and the containment air purge air cleaning unit.

In the refueling purge subsystem, a single fan supplies refueling purge and heating (when 

required) air to the containment area during the refueling operation using, as described above, 

the same ductwork as the pre-entry purge system. Dampers are used to isolate the 

non-operating system, in this case, the pre-entry purge. The 40,000 cubic feet per minute (cfm)

exhaust airflow of the refueling purge subsystem first passes through a filter unit before 

discharging to the plant vent.

2.3.3.6.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the containment air purge system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the containment air purge system components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).
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2.3.3.7 Containment Enclosure Air Handling System

2.3.3.7.1 Summary of Technical Information in the Application

The containment enclosure air handling system removes heat from areas associated with the 

containment enclosure, creates a negative pressure in the containment enclosure structure to 

capture post-accident leakage from the containment and contiguous areas, and filters the 

effluent prior to release from the plant vent. The containment enclosure and adjoining areas 

cooling systems are designed to remove equipment heat from the following areas during normal 

and emergency operation:

• charging pump areas

• SI pump areas

• RHR equipment areas

• containment spray pump and heat exchanger equipment areas

• mechanical penetration area

• containment enclosure ventilation equipment area

• H2 analyzer room and electrical room areas

• RHR vault stairway area

• electrical tunnel personnel walkway (electrical) area

The containment enclosure cooling units maintain the first six areas (charging pump areas, SI 

pump areas, RHR equipment areas, containment spray pump and heat exchanger equipment 

areas, mechanical penetration area, containment enclosure ventilation equipment area, and H2

analyzer room and electrical room areas) at, or below the safety-related equipment’s maximum 

design operating temperatures during normal operation and following a LOCA, loss of offsite 

power, high and moderate pipe breaks, SSE, and tornados.

The H2 analyzer and electrical room supply fans maintain area 7 at or below the safety-related 

equipment’s maximum design operating temperatures during normal operation and following a 

LOCA, loss of offsite power, high and moderate pipe breaks, and an SSE.

The RHR vault stairway chilled water cooling units maintain area 8 at or below safety-related 

equipment’s maximum design operating temperature during normal operation. This 

temperature is 104° F, coincident with an outside temperature of 88° F. The system provides 

auxiliary cooling to maintain area temperatures below 104° F. The cooling system is 

nonsafety-related and is operated, as required, to maintain the desired area temperature.

The electrical tunnel personnel walkway chilled water cooling units maintain area 9 at or below 

safety-related equipment’s maximum design operating temperature during normal operation. 

This temperature is 104° F, coincident with an outside temperature of 88° F. The system 

provides auxiliary cooling to maintain area temperatures below 104° F. The cooling system is 

nonsafety-related and is operated, as required, to maintain the desired area temperature.

2.3.3.7.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the containment enclosure air handling system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the 
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applicant adequately identified the containment enclosure air handling system components 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.8 Containment Online Purge System

2.3.3.8.1 Summary of Technical Information in the Application

The containment online purge system provides supply air to the containment during normal 

operation and exhaust air from the containment to the plant vent filter. Valves in the exhaust 

line can be adjusted to establish containment pressure. The containment online purge 

subsystem supply air fan draws filtered, preheated air from the primary auxiliary building 

mechanical room at elevation 53 feet (ft) and distributes it through an 8 in. supply air duct into 

the containment.

The online purge subsystem exhaust equipment collects air from the containment and exhausts 

it to the normal exhaust filter unit located in the primary auxiliary building. This filtered air is 

then discharged to the plant vent. The purge exhaust valves are NNS-related, in accordance 

with ANSI B16.5.

2.3.3.8.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the containment online purge system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the containment online purge system components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.3.9 Control Building Air Handling System

2.3.3.9.1 Summary of Technical Information in the Application

Seabrook’s control room complex occupies the entire 75 ft elevation of the control building. The 

HVAC systems that service the control room complex are described below and in UFSAR 

Section 6.4, “Habitability Systems.” In addition, the redundant filter systems integral to the 

emergency makeup air and filtration subsystem are detailed in the UFSAR. The control room 

complex HVAC system consists of the following subsystems:

• control room safety-related air conditioning subsystem

• control room nonsafety-related chilled water system

• computer room air conditioning subsystem

• control room normal makeup air subsystem

• control room emergency air makeup and filtration subsystem

• control room exhaust and static pressure control subsystem

• control room air conditioning subsystem

The control room air conditioning subsystem includes both safety-related and nonsafety-related 

cooling subsystems. The safety-related and nonsafety-related cooling subsystems share a 

common recirculating air system located on elevation 75 ft within the control room complex.
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The safety-related control room air conditioning subsystem consists of two full-sized identical air 

cooling trains that are independently electrically powered. Each train consists of the following:

• a 100 percent capacity electric motor-driven water chiller

• two 100 percent capacity chilled water circulating pumps

• a 100 percent capacity chiller condenser exhaust fan

• a back draft damper

• a 100 percent capacity air handling unit located in the recirculated control room air 

cooling stream

• interconnecting piping, expansion tank, and I&Cs

2.3.3.9.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the control building air handling system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the control building air handling system components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.3.10 Demineralized Water System

2.3.3.10.1 Summary of Technical Information in the Application

The demineralized water system serves no safety-related functions. It is designed as an NNS, 

non-seismic Category I system, except for the containment penetration piping and containment 

isolation valves, which are designed in accordance with safety Class 2, seismic Category I 

requirements. Additionally, the makeup water piping connections to the primary component 

cooling water head tanks are designed in accordance with safety Class 3, seismic Category I 

requirements. In addition, the interface piping with the condensate storage tank and the thermal 

barrier loop head pipe is safety Class 3.

The system is designed to provide a sufficient supply of demineralized water at a quality 

required for operation, makeup, and maintenance of the plant.

Water from the water treatment subsystem is directed to either a 500,000-gallon (gal.) or 

200,000-gal. demineralized water storage tank. From here, the water can be transferred to the 

condensate storage tank or distributed throughout the unit by means of the demineralized water 

system. If the demineralized water storage tanks are full or not available, it is possible to 

bypass these tanks and go directly from the water treatment plant to the condensate storage 

tank. The demineralized water transfer subsystem supplies initial fill and makeup to the various 

services within the turbine, administration, containment, primary auxiliary, fuel storage, and 

waste processing buildings, as well as the condensate polishing facility. These services include 

reactor makeup, primary and secondary component cooling water, auxiliary boiler deaerator 

makeup, condensate polishing regeneration, emergency shower and eye wash stations, 

generator stator cooling, and maintenance flushing of systems and components located within 

the plant.
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2.3.3.10.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the demineralized water system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the demineralized water system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.11 Dewatering System

2.3.3.11.1 Summary of Technical Information in the Application

Seabrook was not originally designed with a dewatering system because it was believed that 

the in-leakage prevention methods described in UFSAR Section 3.4.1.1, “Flood Protection 

Measures for Seismic Category I Structures,” would be adequate to prevent water ingress. 

Over the years, it has become evident that the mitigation methods were not completely effective 

at preventing in-leakage.

A plant dewatering system has been installed, which can further mitigate in-leakage of 

groundwater in the lower elevations of the plant. The purpose is to routinely pump water from 

beneath the plant structures, to reduce the static hydraulic head outside the building concrete,

and to reduce the in-leakage. This allows the original mitigative measures to function properly. 

A pump is installed in the existing well at (+) 7 ft elevation of the primary auxiliary building. This 

pump discharges the water to the roof drains system, which then flows to the storm drain 

system and out to circulating water for discharge.

Existing pipe penetrations located in the (-) 26 ft elevation of the emergency feedwater pump 

house (EFPH) have been used as a groundwater low point. These penetrations have been 

directed to a nearby sump. This sump discharges to the existing plant storm drain system.

A pump is installed in the RHR vault “B” stairwell at (-) 61 ft elevation of the equipment vault. 

This pump discharges the water to the roof drains system, which then flows to the storm drain 

system and out to circulating water for discharge. Routine monitoring of this flow path is 

performed per station operating procedures.

A pump is installed in the containment annulus at (–) 32 ft elevation. This pump discharges the 

ground water in the containment annulus to the roof drain system. The connection to the drain 

system is installed at 240 degrees azimuth of the containment annulus. Routine monitoring of 

this flow path is performed per station operating procedures.

A ground water collection tank and pump are installed in the “B” electrical tunnel, west stairwell 

at (-) 20 ft elevation. The pump discharges the water to the turbine building roof drains system, 

which then flows to the storm drain system and out to circulating water for discharge via the 

outfall. Routine monitoring of this flow path is performed per station operating procedure.

2.3.3.11.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the dewatering system components within the scope of license renewal, 
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as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified 

the dewatering system components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.12 Diesel Generator

2.3.3.12.1 Summary of Technical Information in the Application

The standby power supply is provided by two redundant diesel engine generators of identical 

design and characteristics, which supply onsite power of sufficient capacity and capability to 

reliably shut down the reactor. The diesel generator system includes the skid mounted diesel 

generators and their auxiliaries.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12; UFSAR Section 8.3, Section 9.5, and Table 7.5-1; and 

the license renewal boundary drawings, using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review identified an area in 

which additional information was required 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 2.3.3.12-01, dated January 5, 2011, the staff noted on LRA drawings PID-1-DG-LR20460 

and PID-1-DG-LR20465, at location F-10, a pulsation damper and cooling pipe within the scope 

of license renewal under 10 CFR 54.4(a)(1). The same LRA drawings, at location B-7, depict 

upper and lower bearing gear interlock components within the scope of license renewal under 

10 CFR 54.4(a)(1). However, none of the above components were included in LRA 

Table 2.3.3-12. The applicant was asked to justify the exclusion of these components from LRA 

Table 2.3.3-12.

In its response dated February 3, 2011, the applicant indicated that the pulsation damper and 

cooling pipe components are in-scope for license renewal and were grouped under component 

type “piping and fittings” in Table 2.3.3-12. The applicant also stated that the upper and lower 

bearing gear interlock components were also in-scope for license renewal and were grouped 

under component type “valve body” in Table 2.3.3-12.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-01 acceptable 

because the staff confirmed that the component types, “piping and fittings” and “valve body,” are 

included on LRA Table 2.3.3-12. Therefore, the staff’s concern described in RAI 2.3.3.12-01 is 

resolved.

2.3.3.12.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the diesel generator system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).
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2.3.3.13 Diesel Generator Air Handling System

2.3.3.13.1 Summary of Technical Information in the Application

The diesel generator building heating and ventilating system removes heat generated in the 

building during normal and emergency conditions and maintains the design winter indoor 

building temperature. Ventilation is provided by the diesel generator air handling system. 

Electric heaters provided in each day tank room are included in the diesel generator air handling 

system. The remainder of the diesel generator building heating function is provided by the HW

and is evaluated separately.

2.3.3.13.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the diesel generator air handling system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the diesel generator air handling system components subject to an AMR, 

as required by 10 CFR 54.21(a)(1).

2.3.3.14 Emergency Feedwater Pump House Air Handling System

2.3.3.14.1 Summary of Technical Information in the Application

The function of the heating and ventilating systems is to maintain the inside temperature of the 

emergency feedwater pump house within design limits for both normal and emergency 

feedwater system operation during summer and winter.

The ventilation function is provided by the EPA system. The heating function is provided by the 

HW system and is evaluated separately.

The emergency feedwater pump house is ventilated and cooled with outside air, supplied 

through one of the two redundant supply fans and its tornado gravity intake damper with 

pneumatic test operator and exhausted through its tornado exhaust damper with pneumatic 

operator. Each fan and its exhaust damper are controlled by a separate room thermostat. 

Setpoints are staggered to avoid simultaneous operation of redundant equipment. The

emergency feedwater pump house high temperature is alarmed.

The redundant, seismic Category I, safety Class 3, pump room supply fans, supply and exhaust 

dampers, and the Class 1E fan motors, each with electrical power from a separate engineered 

safety features power source, assure continued ventilation should an SSE, loss of offsite power,

or single failure occur. Loss of air or electrical power to the pneumatically-operated supply and 

exhaust dampers will cause them to fail open.

2.3.3.14.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the EPA system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified 

the EPA system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.3.3.15 Fire Protection System

2.3.3.15.1 Summary of Technical Information in the Application

The fire protection system is a nonsafety-related system designed to detect and alarm, control, 

and extinguish fires that may occur. To accomplish this end, the concept of defense in depth is 

a criterion for design. This concept, applied to fire protection, aims at a balanced program, 

which will do the following:

• prevent fires from starting

• detect fires quickly and quickly suppress those that occur, thus limiting their damage

• design and locate plant equipment such that, if a fire occurs and burns for a long time, 

essential plant activities will still be performed

• ensure that neither inadvertent operation nor failure of a fire protection system will 

induce a failure of any safety-related system

LRA Section 2.3.3.15 describes the fire protection systems. LRA Table 2.3.3-15 identifies the 

component types within the scope of license renewal and subject to an AMR.

The fire protection system includes nonsafety-related components that are attached to or 

located near safety-related SSCs, whose failure creates a potential for spatial interaction that 

could prevent the satisfactory accomplishment of a function identified in 10 CFR 54.4(a)(1). 

Therefore, the fire protection system satisfies the scoping criteria of 10 CFR 54.4(a)(2). The fire 

protection system is relied upon to demonstrate compliance with, and satisfies the 

10 CFR 54.4(a)(3) scoping criteria for, the fire protection (10 CFR 50.48) regulated event.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15, the UFSAR, and LRA drawings using the evaluation 

methodology described in SER Section 2.3 and guidance in SRP-LR, Section 2.3. The staff 

also reviewed UFSAR Section 9.5.1, "Fire Protection System," and Fire Protection Evaluation 

and Comparison to Branch Technical Position (BTP) APCSB 9.5-1, Appendix A Report (i.e., 

approved fire protection program, a point-by-point comparison with Appendix A) to the BTP, 

APCSB 9.5-1, “Guidelines for Fire Protection for Nuclear Power Plants,” May 1, 1976. 

The staff also reviewed the following fire protection documents, cited in the CLB, listed in the 

Seabrook Operating License Condition 2.F:

• NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, 

Units 1 and 2,” dated March 1983

• NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, 

Units 1 and 2,” Supplement 4, dated May 1986

• NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, 

Units 1 and 2,” Supplement 5, dated July 1986

• NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, 

Units 1 and 2,” Supplement 6, dated October 1986

• NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, 

Units 1 and 2,” Supplement 7, dated October 1987

• NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, 

Units 1 and 2,” Supplement 8, dated May 1989
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During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant had not omitted from the scope of license renewal any components with 

intended functions pursuant to 10 CFR 54.4(a). The staff then reviewed those components that 

the applicant identified as within the scope of license renewal to verify that the applicant had not 

omitted any passive or long-lived components subject to an AMR, in accordance with 

10 CFR 54.21(a)(1).

During its review of LRA Section 2.3.3.15, the staff identified areas in which additional 

information was necessary to complete its review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAIs, as discussed below.

In RAI 2.3.3.15-1, dated November 18, 2010, the staff stated that LRA drawing 

PID-1-FP-LR20270 shows that sprinkler systems at locations C-4 to H-4 are out of scope (i.e., 

not colored in red). The staff requested that the applicant verify if these sprinkler systems,

installed in various areas of the plant, are in 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). If they are 

excluded from the scope of license renewal and not subject to an AMR, the staff asked that the 

applicant justify the exclusion.

In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-1 by stating the 

following:

The sprinkler systems located on drawing PID-1-FP-LR20270, locations C-4 to 

H-4, are not in scope of License Renewal because they do not provide a function 

credited in Appendix R safe shutdown analysis and do not provide a pressure 

boundary function needed to support the Appendix R suppression systems. All 

other sprinklers located in the turbine building are in scope because they perform 

a pressure boundary function necessary to permit the required Appendix R fire 

suppression systems to function properly.

In evaluating this response, the staff found that it was inadequate, and review of LRA 

Section 2.3.3.15 could not be completed. The applicant’s response to RAI 2.3.3.15-1 was 

inconsistent with the UFSAR Revision 13, Section 9.5.1.2(c)(7), “Manually Operated Pre-Action 

Sprinkler Systems,” which states that manually-operated sprinkler systems are provided for 

areas containing turbine bearings and lube oil piping from turbine bearings to guard. Therefore, 

by letter to the applicant dated March 30, 2011, the staff issued a followup RAI concerning the 

specific issues to determine if the applicant properly applied the scoping criteria of

10 CFR 54.4(a) and the screening criteria of 10 CFR 54.21(a)(1).

In the followup RAI, the staff stated that the fire suppression systems discussed above 

appeared to be credited in the approved Fire Protection Program (UFSAR Section 9.5.1) for fire 

suppression activities. The staff explained that the applicant’s analysis of fire protection 

regulations does not completely capture the fire protection SSCs required for compliance with 

10 CFR 50.48. The scope of fire protection SSCs, required for compliance with 10 CFR 50.48 

and General Design Criterion (GDC) 3, goes beyond preserving the ability to maintain 

safe-shutdown in the event of a fire. The staff stated that the exclusion of fire protection SSCs, 

on the basis that the intended function is not required for the protection of safe-shutdown 

equipment or safety-related equipment, is not acceptable if the fire protection SSC is required 

for compliance with 10 CFR 50.48.
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In its response, dated April 22, 2011, the applicant stated that the sprinkler systems

downstream of valves 1-FP-V-792 and 1-FP-V-800 at locations C-4 to H-4 on boundary drawing 

PID-1-FP-LR20270 have been added to the license renewal, and the LRA has been revised.

Based on its review, the staff finds the applicant’s response to the followup RAI acceptable 

because it indicated that the sprinkler system in question is within the scope of license renewal 

and subject to an AMR. The staff’s concern described in RAI 2.3.3.15-1 is resolved.

In RAI 2.3.3.15-2, dated November 18, 2010, the staff stated that LRA drawing 

PID-1-FP-LR20274 shows that several yard fire hydrants and post-indicator valves are out of 

scope (i.e., not colored in red). The staff believed that yard fire hydrants and post-indicator 

valves have the fire protection-intended functions required to be compliant with 10 CFR 50.48,

as stated in 10 CFR 54.4. The fire hydrants and post-indicator valves also serve as the 

pressure boundary for the fire protection water supply system. Further, NUREG-0896, “Safety 

Evaluation Report related to the operation of Seabrook Station, Units 1 and 2,” dated 

March 1983, Section 9.5.1.5, “Fire Detection and Suppression,” on page 9-47, states that 

“...[y]ard hydrants are provided at intervals of 250 ft along the fire protection water supply loop, 

approximately 40 ft from the buildings...Each yard hydrant is provided with an isolation valve to 

facilitate hydrant maintenance and repairs without shutting down any part of the fire water 

supply system...”

The staff requested that the applicant verify if the yard hydrants and post-indicator valves 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). If they are excluded from the scope of license 

renewal and are not subject to an AMR, the staff requested that the applicant justify the 

exclusion.

In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-2 by stating the

following:

The yard fire hydrants required to support Unit 1 compliance with 10 CFR 50.48 

and Appendix R safe shutdown are included in scope of License Renewal (See 

PID-1-FP-LR20274 demarcation line) and are subject to an AMR in accordance 

with 10 CFR 54.21 (a)(1). The yard fire hydrants supporting Unit 2 and the site 

support buildings are not required for compliance with 10 CFR 50.48 and 

Appendix R safe shutdown and do not have a License Renewal-intended 

function and are not in scope of license renewal. Construction on Seabrook 

Station Unit 2 was effectively terminated in 1984 and its construction permit was 

allowed to expire in October 1988. All of the post indicator valves located on the 

fire main ring header and any branch header isolation post indicator valves are in 

scope of License Renewal and are subject to an AMR in accordance with 

10 CFR 54.21 (a)(1). All other post indicating valves that supply support 

buildings and branch headers are not required for compliance with 10 CFR 50.48 

or Appendix R safe shutdown and do not have a License Renewal-intended 

function and are not in scope of license renewal.

The staff reviewed the applicant's response to RAI 2.3.3.15-2, which confirmed that the yard fire 

hydrants and post-indicator valves in question are associated with Seabrook Unit 2 (Seabrook 

Unit 2 construction was terminated in 1984 and its construction permit expired in October 1988). 

They are not required for Unit 1 compliance with 10 CFR 50.48 and Appendix R safe shutdown,

and they do not have a license renewal-intended function and are not within the scope of

license renewal. Therefore, the staff’s concern described in RAI 2.3.3.15-2 is resolved.
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In RAI 2.3.3.15-3, dated November 18, 2010, the staff stated that Section 9.5.1.6, “Fire 

Protection of Specific Plant Areas,” of NUREG-0896, “Safety Evaluation Report related to the 

operation of Seabrook Station, Units 1 and 2,” dated March 1983, on page 9-48, states that 

“...the applicant committed to provide oil collection systems for each RCP in accordance with 

Section III.O Appendix R...” LRA Section 2.3.3.15 did not discuss scoping and screening 

results of RCP oil collection systems and their associated components.

The staff requested that the applicant verify if the RCP oil collection systems and their 

associated components are in 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). If RCP oil collection systems 

and their associated components are excluded from the scope of license renewal and not 

subject to an AMR, the staff requested that the applicant justify the exclusion.

In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-3 by stating the

following:

The Reactor Coolant Oil collection system is in scope for fire protection 

(10 CFR 54.4 (a)(3)) and is subject to an AMR in accordance with 

10 CFR 54.21(a)(1). See LRA Section 2.3.3.25, “Oil Collection for Reactor 

Coolant Pumps System;” on page 2.3-189.

The staff reviewed the applicant’s response to RAI 2.3.3.15-3, including verification of the 

referenced discussion on LRA page 2.3-189, which confirmed that the RCP oil collection 

systems and their associated components have been included in the scope of license renewal 

and are subject to an AMR. Therefore, the staff’s concern described in RAI 2.3.3.15-3 is 

resolved.

In RAI 2.3.3.15-4, dated November 18, 2010, the staff stated that Section 9.5.1.6, “Fire 

Protection of Specific Plant Areas,” of NUREG-0896, “Safety Evaluation Report related to the 

operation of Seabrook Station, Units 1 and 2,” dated March 1983, on page 9-52, “Cable 

Spreading Room,” states that “...[a] manual smoke ventilation system has been provided to 

exhaust the cable spreading room in the event of a fire...” LRA Section 2.3.3.15 did not discuss 

scoping and screening results of the cable spreading room (CSR) manual smoke ventilation 

system and its associated components.

The staff requested that the applicant verify if the CSR manual smoke ventilation system and its 

associated components are in 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). If the CSR manual smoke 

ventilation system and its associated components are excluded from the scope of license 

renewal and not subject to an AMR, the staff requested that the applicant justify the exclusion.

In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-4 by stating the 

following:

The manual smoke removal system is not in scope of License Renewal. The 

fans (1-CBA-FN-17 and 1 -CBA-FN-18) used for smoke removal are not credited 

for safe shutdown by UFSAR...for a fire in the Cable Spreading Room or any 

other Appendix R fire. There are no manual safe shutdown actions requiring 

access to this area. The fans are not safety related, are not credited for 

Appendix R safe shutdown and therefore have no License Renewal function 

(refer to PID-1-CBA-LR20303 location G-5 and H-5).
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USFAR Section 9.4.9.1 provides a description of the cable spreading room 

ventilation.

Based on its review, the staff finds the applicant’s response acceptable because the manual 

smoke ventilation system in question is not in-scope for license renewal and is not credited with 

achieving safe-shutdown in the event of a fire. Although the CSR smoke ventilation system is 

addressed in NUREG-0896, the system in question is not required in Appendix R for achieving 

safe-shutdown in the event of a fire.

In the original SER, NUREG-0896, NRC reviewed the CSR smoke ventilation system because 

the licensee provided system description in the incoming UFSAR, but the licensee has not 

credited this system in the fire protection program. The manual smoke removal system in 

question is for loss of prevention purposes only.

The staff confirmed that the applicant correctly excluded the above smoke ventilation system 

from scope of license renewal and subject to an AMR. Therefore, the staff’s concern described 

in the RAI 2.3.3.15-4 is resolved.

In RAI 2.3.3.15-5, dated November 18, 2010, the staff stated that Section 9.5.1.6, “Fire 

Protection of Specific Plant Areas,” of the Seabrook SER (NUREG-0896), dated March 1983, on 

page 9-53, “Switchgear Rooms,” states that “...[t]he Division I and Division II switchgear rooms 

are separated from each other and from other plant areas by 3-hour-fire-rated wall and 

floor/ceiling assemblies. Automatic fire detection is provided by ionization smoke detectors. 

Manual protection is provided by standpipe and hose stations and portable extinguishers...” 

LRA Section 2.3.3.15 did not discuss scoping and screening results of Division I and Division II 

switchgear rooms’ standpipe and hose stations.

The staff requested that the applicant verify if the Division I and Division II switchgear rooms’ 

standpipe and hose stations are in 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). If the 

Division I and Division II switchgear rooms’ standpipe and hose stations are excluded from the 

scope of license renewal and not subject to an AMR, the staff requested that the applicant 

justify the exclusion.

In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-5 by stating the 

following:

The standpipes and valves for the hose stations for extinguishing a fire in the 

Division I and Division II switchgear rooms are in scope of license renewal and 

are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The switch gear 

rooms do not contain any fire protection piping. The hose stations referred to are 

located in the turbine building (see PID-1-FP-LR20270 Location 

E-12-1-FP-R-8-A) and the south stairwell of the control building (see 

PID-1-FP-LR20268 Location F-7 for 1-FP-R-30).

The hose stations reels and hoses for 1-FP-R-8-A and 1-FP-R-30 are in scope 

for license renewal. The reels are subject to an AMR in accordance with 

10 CFR 54.21(a)(1). The fire hoses are classified as consumables and are 

replaced on condition, as described on page 2.1-24 of the LRA.

Based on its review, the staff finds the applicant’s response, as clarified to include verification of 

the referenced discussion on page 2.1-24 of the LRA, acceptable because it indicated that the 
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standpipe and hose stations in question have been included in the scope of license renewal and 

are subject to an AMR. Further, the applicant indicated that the fire hoses are classified as 

consumables and are replaced on condition. Therefore, the staff’s concern described in 

RAI 2.3.3.15-5 is resolved.

In RAI 2.3.3.15-6, dated November 18, 2010, the staff stated that Section 9.5.1.6, “Fire 

Protection of Specific Plant Areas,” of the Seabrook SER (NUREG-0896), dated March 1983, on 

page 9-53, “Safety-Related Battery Rooms,” states that “...[h]ose stations and portable fire 

extinguishers are available in the areas for fire manual suppression...” LRA Section 2.3.3.15 

did not discuss scoping and screening results of safety-related battery rooms' hose stations.

The staff requested that the applicant verify if the safety-related battery rooms’ hose stations are 

in 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). If safety-related battery rooms' hose stations are 

excluded from the scope of license renewal and not subject to an AMR, the staff requested that 

the applicant justify the exclusion.

In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-6 by stating the

following:

The standpipes and valves for the hose stations for the safety related battery 

rooms are in scope of license renewal and are subject to an AMR in accordance 

with 10 CFR 54.21(a)(1). The battery rooms do not contain any fire protection 

piping. The hose stations referred to are located in the turbine building (see 

PID-1-FP-LR20270 Location E-12 1-FP-R-8-A) and the south stairwell of the 

control building (see PID-1-FP-LR20268 Location F-7 for 1-FP-R-30).

The hose stations reels and hoses for 1-FP-R-8-A and 1-FP-R-30 are in scope 

for license renewal. The reels are subject to an AMR in accordance with 

10 CFR 54.21(a)(1). The fire hoses are classified as consumables and are 

replaced on condition, as described on page 2.1-24 of the LRA.

The staff reviewed the applicant’s response to RAI 2.3.3.15-6, including verification of the 

referenced discussion on page 2.1-24, which confirmed that the standpipe and hose stations in 

question have been included in the scope of license renewal and are subject to an AMR. 

Further, the applicant indicated that the fire hoses are classified as consumables and are 

replaced on condition. Therefore, the staff’s concern described in RAI 2.3.3.15-6 is resolved.

In RAI 2.3.3.15-7, dated November 18, 2010, the staff stated that Section 9.5.1.6, “Fire 

Protection of Specific Plant Areas,” of the Seabrook SER (NUREG-0896), dated March 1983, on 

page 9-53, “Emergency Diesel Generator Rooms,” states that “...[t]he floor trench containing 

fuel oil piping in each diesel generator room is provided with an automatic deluge system to 

combat a fire in the trench.” LRA Section 2.3.3.15 did not discuss scoping and screening 

results of the automatic deluge system in the diesel generator room floor trench containing fuel 

oil piping.

The staff requested that the applicant verify if the automatic deluge system in question is in 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). If the automatic deluge system is excluded from the 

scope of license renewal and not subject to an AMR, the staff requested that the applicant 

justify the exclusion.
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In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-7 by stating the 

following:

The floor trench containing fuel oil piping in each diesel generator room with an 

automatic deluge system is in scope of license renewal and is subject to an AMR 

in accordance with 10 CFR 54.21 (a)(1). See LRA Page 2.3-148 (for the in 

scope boundary description) and PID-1-FP-LR20271 location H-10 and F-10 for 

sprinkler zones 1A-2 and 1B-2.

The staff reviewed the applicant response to RAI 2.3.3.15-7, including verification of the 

referenced discussion on page 2.3-148, which confirmed that the automatic deluge system 

associated with diesel generator rooms floor trench containing fuel oil piping has been included 

in the scope of license renewal and is subject to an AMR. Therefore, the staff’s concern 

described in RAI 2.3.3.15-7 is resolved.

In RAI 2.3.3.15-8, dated November 18, 2010, the staff stated that Tables 2.3.3-22 and 3.3.2-22 

of the LRA do not include the following fire protection components:

• fire hose stations, fire hose connections, and hose racks

• yard fire hydrants

• strainers

• tubing

• spray nozzles

• diesel fire pump engine—heat exchanger bonnet, shell, tubes, and exhaust silencer

• floor drains for fire water

• dikes and curbs for oil spill confinement

The staff requested that the applicant verify if the fire protection components listed above are in 

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). If they are excluded from the scope of license renewal 

and are not subject to an AMR, the staff requested that the applicant justify the exclusion.

In a letter dated December 3, 2010, the applicant responded to RAI 2.3.3.15-8 by stating the 

following:

License renewal drawing (PID [license renewal] Notes 1) provides a description 

of the component types and a correlation that shows the component grouping 

they are evaluated as.

Fire protection system components subject to age management review are listed 

in Table 2.3.3-15 (page 2.3-151) and a summary of the aging management 

evaluation for the fire protection system is provided in Table 3.3.2-15 

(page 3.3-300) of the LRA. Fire hose stations include the fire hose, the fire hose 

racks (evaluated as supports) and the fire hose connections.

• The fire hose racks (supports) are evaluated under supports in the LRA 

Section 2.4.6 and are in scope of License Renewal and subject to an 

AMR in accordance with 10 CFR 54.21(a)(1).

• Fire hoses are within the scope of License Renewal, but are not subject 

to aging management because they are replaced based on condition. 

These components are periodically inspected in accordance with National 
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Fire Protection Association (NFPA) standards. Fire hoses are considered 

consumables. See section 2.3.1 (page 2.1-24) in the LRA.

• Fire hose connections are in scope of license renewal and are evaluated 

as pipe and fittings and are subject to an AMR in accordance with 

10 CFR 54.21(a)(1). See Table 3.3.2-15 (page 3.3-300) in the LRA.

• Yard fire hydrants in the scope of License Renewal are designated FH on 

the license renewal prints and are evaluated as valves in Table 3.3.2-15 

on page 3.3-300 of the LRA and are subject to an AMR in accordance 

with 10 CFR 54.21(a)(1).

• Strainers in scope of License Renewal are evaluated as filter elements 

and filter housings in Table 3.3.2-15 on page 3.3-300 of the LRA and are 

subject to an AMR in accordance with 10 CFR 54.21(a)(1).

• Tubing in scope of License Renewal is evaluated as pipe in 

Table 3.3.2-15 (page 3.3-300) of the LRA and is subject to an AMR in 

accordance with 10 CFR 54.21(a)(1).

• Spray nozzles in the scope of License Renewal are evaluated as 

sprinklers in Table 3.3.2-15 (page 3.3-300) of the LRA and are subject to 

an AMR in accordance with 10 CFR 54.21(a)(1).

• The diesel fire pump engine heat exchanger including the bonnet, shell, 

and tubes, are an integral part of the diesel fire pump engine and were 

evaluated as a unit. The diesel fire pump engine is screened out as an 

active component per NEI 95-10 Appendix B.

• The diesel fire pump exhaust silencer is evaluated under pipe and fittings 

and is subject to an AMR in accordance with 10 CFR 54.21(a)(1). See 

Table 3.3.2-15 (pages 3.3-308 and 309). The summary of the aging 

management review for the internal surface is provided on page 3.3-309, 

Piping and Fittings, Pressure Boundary, Steel, Diesel Exhaust (Internal). 

The summary of the aging management review for the external surface is 

provided on page 3.3-308, Piping and Fittings.

• Floor drains for fire water are in scope of License Renewal and evaluated 

in section 2.3.3.45, “Waste Processing Liquid Drains System," 

(page 2.3-269) and section 2.3.3.26, “Plant Floor Drain System,” 

(page 2.3-191) of the LRA. These floor drains are subject to an AMR in 

accordance with 10 CFR 54.21(a)(1).

• The dikes and curbs' for oil spill confinement in scope of License Renewal 

are evaluated under structures as a commodity under Concrete in 

Tables 3.5.2-2 and 3.5.2-5. These dikes and curbs are subject to an 

AMR in accordance with 10 CFR 54.21(a)(1).

In reviewing its response to RAI 2.2.3.15-8, the staff found that the applicant had addressed and 

resolved each item in the RAI, as discussed below.

Fire hose stations, including fire hose racks and fire hose connections, are in the scope of 

license renewal and subject to an AMR. Fire hose racks are included under line item 

“Supports,” which are in the scope of license renewal, subject to an AMR, and listed in LRA 

Section 2.4.6. Fire hose connections are evaluated under line item description “Piping and 
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Fitting,” in LRA Table 3.3.2-15. Fire hoses are within the scope of license renewal, but are not 

subject to an AMR because they are consumable. The applicant stated that it considers yard 

fire hydrants in the line item “Valves,” in Table 3.3.2-15, and they are subject to an AMR. 

Tubing is also evaluated under line item description “Piping and Fitting,” in LRA Table 3.3.2-15. 

In addition, the applicant addressed strainers under line items “Filter Elements,” and “Filter 

Housings,” in LRA Table 3.3.2-15. Furthermore, in its response, the applicant confirmed that 

spray nozzles are included under line item “Sprinklers,” which are in the scope of license 

renewal, subject to an AMR, and listed in Table 3.3.2-15.

The applicant stated that fire pump exhaust silencer is evaluated under line item description 

“Piping and Fitting,” in LRA Table 3.3.2-15. Further, the applicant considered heat exchanger 

bonnet, shell, and tubes to be active components as a part diesel fire pump engine; they are not 

subject to an AMR. 

The floor drains for fire water are included under “Plant Floor Drain System” in LRA 

Section 2.3.3.26 and “Waste Processing Liquid Drains System” in Section 2.3.3.45; these are in 

the scope of license renewal and subject to an AMR. The applicant considered curbs for oil spill 

confinement under structural commodities as “Concrete,” listed in LRA Tables 3.5.2-2 and 

3.5.2-5.

2.3.3.15.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the fire protection system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.16 Fuel Handling System

2.3.3.16.1 Summary of Technical Information in the Application

The new fuel storage facilities are located within the fuel storage building and are designed to 

facilitate the safe handling, inspection, and storage of new fuel assemblies and control rods. 

Space is provided for handling and storage of 90 new fuel assemblies, which is equal to a core 

load plus 25 spare assemblies.

The fuel transfer system includes an underwater, electric-motor-driven, transfer car that runs on 

tracks extending from the containment refueling canal through the transfer tube and into the fuel 

storage building refueling canal. A hydraulically actuated lifting arm is on each end of the 

transfer tube. The fuel container in the refueling canal receives a fuel assembly in the vertical 

position from the refueling machine. The fuel assembly is then lowered to a horizontal position 

for passage through the transfer tube. After passing through the tube, the fuel assembly is 

raised to a vertical position for removal by a tool suspended from the spent fuel pool bridge and 

hoist in the fuel storage building refueling canal. A system of lifting arms and hydraulic cylinders 

is used to raise and lower the fuel containers containing the fuel assembly. The cylinders are 

powered by hydraulic pumping units and controlled by electronic consoles. The pumping units 

and consoles (one each in the containment and fuel storage building, designated 1-FH-RE-44 
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and 1-FH-RE-45, respectively) are located on the operating deck of each building. The spent 

fuel pool bridge and hoist then moves to a storage loading position and places the spent fuel 

assembly in the spent fuel storage racks.

During reactor operation, the transfer car is stored in the fuel storage building refueling canal. 

The quick closure hatch is engaged closed on the containment refueling canal end of the 

transfer tube to seal the reactor containment. The terminus of the tube in the fuel storage 

building is closed by a valve.

2.3.3.16.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the fuel handling system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the fuel handling system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.17 Fuel Oil System

2.3.3.17.1 Summary of Technical Information in the Application

The fuel oil system provides fuel to the two diesel driven fire pumps—1-FPP-20A and 

1-FPP-20B. There are two fuel tanks, each dedicated to a diesel driven fire pump.

2.3.3.17.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the fuel oil system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately identified 

the fuel oil system components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.18 Fuel Storage Building Air Handling System

2.3.3.18.1 Summary of Technical Information in the Application

The normal heating and ventilation subsystem is comprised of filters, dual purpose chilled water 

cooling and hot water heating coils for summer cooling or winter heating, supply air fans, 

chillers, and a ducted distribution system with parallel-path supply dampers, which are a part of 

the primary auxiliary building ventilation system. A hot water unit heater system, which is 

supplied with hot water from the primary auxiliary building HW system, is also provided. The 

system is designed to maintain inside design temperatures suitable for equipment and 

personnel.

The ventilation function is provided by the fuel storage building ventilation system. The heating 

function is provided by the HW system and is evaluated separately.

The normal heating and ventilation subsystem employs two slotted exhaust intake hoods 

designed to sweep the pool surface in order to capture the dilute vapors emanating from the 

spent fuel pool. The entrained air and vapor are ducted to a vane axial fan, normal ventilation 

exhaust air isolation damper and from there to the unit plant vent.
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Two basic modes of air handling are available, as discussed below. For all modes, the 

operation of the mechanical equipment is controlled and monitored from the plant unit control 

room.

Normal Once-Through Supply Exhaust Ventilation Mode. During normal operation, filtered 

outside air is circulated through the fuel storage building by the normal ventilation system, with 

the exhaust air discharged from the building via the unit plant vent. Filtering of the exhaust air is 

not normally performed.

Fuel Handling Mode

The redundant filter units and their respective components are fed from independent power 

sources so that no single failure would prevent the obtaining and maintaining of the negative 

pressure. The static pressure control for the parallel supply system dampers are provided with 

manual override provisions to allow the operator to control the damper position and the building 

pressure if required.

. The fuel handling mode is used any time irradiated fuel not in a sealed 

cask is handled. In the fuel handling mode of operation, the normal building exhaust system is 

isolated prior to initiation of fuel handling operations by closing the normal exhaust isolation 

damper and stopping the normal exhaust fan. The fuel storage building is maintained at a 

negative pressure of 0.25 in. water gauge (w.g.) or more (negative). This is achieved by 

exhausting air from the building at a higher rate than directly supplied from the primary auxiliary 

building supply air system. Maintaining the building at a negative pressure will minimize, or 

eliminate, the leakage of radioactive material to the environment in the event of an accident. 

The exhaust filter trains are redundant, with one unit required to operate in the event of an 

accident.

The fuel storage building emergency air cleaning system is a seismic Category I, safety Class 3 

system.

2.3.3.18.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the fuel storage building air handling system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the 

applicant adequately identified the fuel storage building air handling system components subject 

to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.19 Hot Water Heating System

2.3.3.19.1 Summary of Technical Information in the Application

The hot water heating (HW) system includes the station designated hot water supply and hot 

water return systems. In addition to providing heating to buildings not within the license renewal 

boundary, such as the administration building, turbine building and waste process building, the 

HW provides the functions described below.

Fuel storage building normal heating is comprised of filters, dual purpose chilled water cooling

and hot water heating coils for summer cooling or winter heating, supply air fans, chillers, and a 

ducted distribution system with parallel path supply dampers, which are a part of the primary 

auxiliary building ventilation system. A hot water unit heater system, which is supplied with hot 
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water from the primary auxiliary building HW system, is also provided. The system is designed 

to maintain inside design temperatures suitable for equipment and personnel.

Primary auxiliary building heating is maintained in the winter by heating the outside air with a 

bank of dual purpose chilled water cooling and hot water heating coils. The water temperature 

for the main hot water heating coils is controlled by thermostats mounted in the primary auxiliary 

building. The heating coils are supplied with hot water and glycol from a closed loop parallel 

pump circulating system using a common steam and hot water converter. The closed loop 

circulating system for the main heating coils is comprised of three pumps, one for each bank of 

heating coils and one reserve pump, each manually controlled locally. Each pump once started 

runs continuously. Certain rooms contain a pair, or pairs, of unit heaters connected to 

thermostats located in the room that will operate the unit heater fans to maintain the room 

temperature above minimum design requirements. The unit heaters are supplied with hot water

and glycol from a closed loop system using the same steam and hot water converter as the 

primary auxiliary building main hot water heating coils. One centrifugal pump provides 

circulating water to all of the unit heaters within each room. The pump is started manually from 

the main control panel and runs continuously.

Heating for the diesel generator building is provided by hot water unit heaters. Four unit heaters 

are located in each diesel generator area. Each of the two area heating systems is provided 

with hot water from the hot water and steam converter. Three hot water circulating pumps, one 

for each area and the third, a standby for both, are energized from the local control panel and 

will run until the operator manually stops them. Operation of the unit heaters is thermostatically 

controlled. The hot water heating piping is contained or shielded where it passes over 

safety-related electrical equipment. Cable speading room ventilation system supply air is 

reheated, when required, by a hot water heating coil in the supply ductwork to offset building 

heat losses. The cable spreading room ventilating system obtains makeup air and hot water for 

heating from the switchgear area and battery rooms heating and ventilating system.

In the winter the 4-kilovolt (kV) switchgear areas, cable spreading area, and the electrical tunnel 

area air is recirculated and mixed with preheated outside air, as necessary, for makeup and to 

maintain the inside design temperature. The 4-kV switchgear areas and battery rooms have 

two ventilation equipment rooms, one for each train. The equipment rooms serve as a return air

and makeup air mixing plenum. The heat required to offset building heat loss from the 

switchgear areas, battery rooms, and electrical tunnels is supplied by hot water unit heaters 

located in the equipment rooms. Water line breaks or hot water system failures will not affect 

the operation of the switchgear areas or battery rooms.

The emergency feedwater water pump house heating system is designed to maintain the pump 

house at or above 50° F when the outside temperature is 0° F or above. The heating system 

consists of a shared steam and hot water converter, two 100 percent capacity pumps, a piping 

system, and two 100 percent capacity unit heaters. The heating medium is a mixture of water 

and glycol in a closed loop circulating system. The glycol acts to prevent freezing should the 

steam supply, electrical power source, or a pump or driver fail. Each unit heater is controlled by 

its own room thermostat.

The pump room area of the service water pump house is maintained at 50° F or above when the 

outside temperature is 0° F or above by a HW system using unit heaters. Hot water is pumped 

through the unit heaters from a steam-to-hot-water heat exchanger located in the adjacent 

circulating water pump house. The heating system is not required to maintain operation of the 

service water pumping equipment.
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2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19, UFSAR Section 9.4, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review identified areas in which additional 

information was required 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 2.3.3.19-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-HW-LR20051 

that the applicant depicts the HW expansion tanks within the scope of license renewal under 

10 CFR 54.4(a)(2). The 1

/2 in. vent lines attached to the expansion tanks, at locations G-11 and 

G-12, are shown not within scope of license renewal. The applicant was asked to justify the 

exclusion of the 1

/2 in. vent lines from scope of license renewal.

In its response dated February 3, 2011, the applicant clarified that the 1

/2 in. vent lines are within 

the scope of license renewal for 10 CFR 54.4(a)(2). The applicant also described the 1

/2 in. vent 

lines as 1

/2 in. carbon steel piping with threaded plugs at the end.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-01 acceptable 

because the staff confirmed that the 1

/2 in. vent lines are already included within the scope of 

license renewal under 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in 

RAI 2.3.3.19-01 is resolved.

In RAI 2.3.3.19-02, dated January 5, 2011, the staff noted on LRA drawing PID-1-HW-LR20056, 

at location G-11, that the applicant depicted the make-up tank as not being within the scope of 

license renewal. However, the make-up tank is connected to nonsafety-related piping that is 

included within the scope of license renewal under 10 CFR 54.4(a)(2). The applicant was asked 

to justify its exclusion of the make-up tank from the scope of license renewal.

In its response dated February 3, 2011, the applicant stated that the make-up tank is within 

scope of license renewal under 10 CFR 54.4(a)(2). The applicant indicated that the LRA 

drawing PID-1-HW-LR20056 erroneously depicted the make-up tank excluded from scope of 

license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-02 acceptable 

because the applicant clarified that the make-up tank is within the scope of license renewal 

under 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.3.19-02 is 

resolved.

2.3.3.19.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the HW system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.3.20 Instrument Air System

2.3.3.20.1 Summary of Technical Information in the Application

The plant’s compressed air function is provided by the service air and the instrument air 

systems. The components from the service air system have been incorporated with the 

instrument air system, and the containment compressed air system was evaluated with the 

instrument air system components.

The compressed air system consists of two subsystems—the plant compressed air system and 

the containment compressed air system. Each subsystem employs redundant, oil-free 

compressors with associated filters, after coolers, moisture separators, air dryers, receivers, and 

operating controls.

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20, UFSAR Section 9.3.1, UFSAR Tables 7.5-1 and 

6.2-83, and the license renewal boundary drawings using the evaluation methodology described 

in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review identified areas 

in which additional information was required 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 2.3.3.20-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-IA-LR20637 

that the applicant depicts 1 in. piping within scope of license renewal for 10 CFR 54.4(a)(3). 

However, on the continuation LRA drawing PID-1-IA-LR20638, the applicant depicts the 1 in.

piping as not being within scope of license renewal. The applicant was asked to justify the 

exclusion of the 1 in. piping from the scope of license renewal on the LRA drawing 

PID-1-IA-LR20638.

In its response dated February 3, 2011, the applicant stated that most of the loop B piping is 

excluded from scope of license renewal due to check valves that prevent backflow into the 

loop A piping. The applicant referenced that license renewal note 4 on both LRA drawings state 

“[c]heck valve prevents back flow into other air trains.” However, the applicant indicated that 

there is also a backflow check valve on the 1 in. piping between the air filter and valve V-457, 

but it was not depicted in LRA drawing PID-1-IA-LR20638 with license renewal note 4. The 

applicant clarified that the 1 in. piping downstream (and leading into the continuation flag for 

LRA drawing PID-1-IA-LR20637) from the backflow check valve is within the scope of license 

renewal under 10 CFR 54.4(a)(3). The applicant also stated that LRA drawing 

PID-1-IA-LR20638 erroneously depicts this portion of the 1 in. piping as excluded from the

scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-01 acceptable 

because the 1 in. piping was already included within the scope of license renewal under 

10 CFR 54.4(a)(3). The staff confirmed that the applicant’s description of the scoping boundary 

of the piping on loop B is consistent with license renewal note 4 on LRA drawing 

PID-1-IA-LR20638 involving check valves for the instrument air system. Therefore, the staff’s 

concern described in RAI 2.3.3.20-01 is resolved.

In RAI 2.3.3.20-02, dated January 5, 2011, the staff identified the following issues on LRA 

drawing PID-1-IA-LR20643:
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• At locations F-8 and F-9, no continuation piping was identified between the check valve 

V-531, which is depicted within the scope of license renewal for 10 CFR 54.4(a)(1), and 

the seismic anchor.

• At locations E-8 and F-8, portions of 2 in. piping near valves (V-533 and V-535) are 

shown within the scope of license renewal for 10 CFR 54.4 (a)(3). However, the pipe 

sections upstream of these valves and to the seismic anchors are shown as not within 

the scope of license renewal.

• At locations E-8 and F-8, the piping associated with the seismic anchors could not be 

identified on the drawing.

• At location E-8, there is a line whose beginning and end are not identified.

The applicant was asked to do the following:

• provide identification of the continuation piping that is missing between the check valve 

V-531 and seismic anchor at locations F-8 and F-9

• justify excluding the continuation piping between valves V-533 and V-535 and the 

seismic anchors from scope of license renewal at locations E-8 and F-8

• identify the missing continuation piping associated with the seismic anchors at locations 

E-8 and F-8

• identify the line on the drawing at location E-8

In its response dated February 3, 2011, the applicant provided a revised portion to LRA drawing 

PID-1-IA-LR20643 to include the missing components. The components include piping 

downstream from check valve V-531, ball valves (V-540, V-532, and V-534), and piping 

downstream of ball valves V-532 and V-534 up to the seismic supports. The applicant indicated 

that the above components were included within the scope of license renewal under 

10 CFR 54.4(a)(2) and are subject to AMR. The applicant also stated that the tailpipe, which 

initially appeared in the LRA drawing at location E-8, is attached downstream from the closed 

ball valve V-540 and is excluded from scope of license renewal since it is not fluid-filled.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-02 acceptable 

because the applicant clarified the components that are within scope of license renewal. The 

staff also confirmed that the tailpipe was appropriately excluded from scope of license renewal 

since it does not serve an intended function beyond closed ball valve V-540. Therefore, the 

staff’s concern described in RAI 2.3.3.20-02 is resolved.

In RAI 2.3.3.20-03, dated January 5, 2011, the staff could not locate seismic anchors on eight 

nonsafety-related lines connected to safety-related lines in LRA drawing PID-1-IA-LR20647. 

The applicant was asked to clarify the locations of the seismic anchors.

In its response dated February 3, 2011, the applicant stated both the safety-related and 

nonsafety-related instrument air piping in the primary auxiliary building are seismically 

supported by a series of pipe supports. Six of the nonsafety-related lines, which consist of 

nonsafety-related 1

/2 in. tubing, are anchored by the associated instruments, which are rigidly 

mounted. The applicant also stated that the other two locations of nonsafety-related piping are 

located near check valves V-8032 and V-8031 and do not contain seismic anchors. The 

applicant stated that the continued nonsafety-related piping beyond the check valves provides

structural support for the safety-related piping to ensure that that the nonsafety-related piping 
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loads are not transferred through the safety and nonsafety interface, as determined by its piping 

stress analysis.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-03 acceptable 

because the applicant explained that, based on piping stress analysis, the nonsafety-related 

piping loads are not transferred through the safety and nonsafety interface. Therefore, seismic 

anchors are not required, and the staff’s concern described in RAI 2.3.3.20-03 is resolved.

2.3.3.20.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the instrument air system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.21 Leak Detection System

2.3.3.21.1 Summary of Technical Information in the Application

The leak detection system components monitor indications of leakage inside the containment 

building by the use of pressure, temperature, and level instruments.

2.3.3.21.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the leak detection system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the leak detection system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.22 Mechanical Seal Supply System

2.3.3.22.1 Summary of Technical Information in the Application

The mechanical seal supply system is designed to supply flushing water to the mechanical 

seals of the NNS class pumps of the plant. The mechanical seals are provided on these pumps 

so that no leakage of the process fluid occurs past the shaft into the environment. For their 

proper functioning, the seal faces have to be kept flushed and under a minimum pressure of 

15 psig higher than the process fluid pressure on the suction side of the pump. This ensures 

the mating of the seal faces without any particulates entrapped between them and does not 

allow any process fluid to enter the seal cavity (or the stuffing box).

2.3.3.22.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22 and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 
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The staff’s review identified an area in which additional information was required 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 2.3.3.22-01, dated January 5, 2011, the staff noted on drawing PID-1-DM-LR20353, at 

location H-3, that the applicant refers to license renewal note 1, which indicates that pump 

SF-P-272 is within the scope of license renewal for 10 CFR 54.4(a)(2). However, on LRA 

drawing PID-1-SF-LR20484, pump SF-P-272 is not depicted as being within the scope of 

license renewal. The applicant was asked to clarify the scoping classification for pump 

SF-P-272.

In its response dated February 3, 2011, the applicant indicated LRA drawing 

PID-1-DM-LR20353, license renewal note 1, refers to the mechanical seal supply system piping 

going to the pump SF-P-272. License renewal note 3, on the same drawing, labeled the 

mechanical seal as a short-lived item, excluding it from the scope of license renewal. The 

applicant also described the mechanical seal supply piping to the pump mechanical seal as 

stainless steel material in a treated water internal environment, which is why it was included 

within scope of license renewal under 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-01 acceptable 

because the applicant clarified that license renewal note 1 in LRA drawing PID-1-DM-LR20353 

addressed the mechanical seal piping, which is already included within the scope of license 

renewal under 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.3.22-01 is 

resolved.

2.3.3.22.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the mechanical seal supply system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified all the mechanical components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.23 Miscellaneous Equipment

2.3.3.23.1 Summary of Technical Information in the Application

Miscellaneous equipment contains the hydraulic piping and components that operate the 

personnel hatch doors for entry into containment. The hydraulic network equalizes air lock 

pressure, rotates the locking ring to the unlock position, and opens the outer door. On close 

demand, the network closes the door, closes the equalizing valve, rotates, and locks the locking 

ring. Similarly, a personnel air lock hydraulic reservoir inside the containment operates with a 

network of control valves, piping, interlock controls, and actuating pistons. The hydraulic 

network equalizes air lock pressure, rotates the locking ring to the unlock position, and opens 

the inner door. On close demand, the network closes the door, closes the equalizing valve,

then rotates and locks the locking ring.
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2.3.3.23.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the miscellaneous equipment mechanical components within the scope 

of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the miscellaneous equipment mechanical components subject to an AMR, 

as required by 10 CFR 54.21(a)(1).

2.3.3.24 Nitrogen Gas System

2.3.3.24.1 Summary of Technical Information in the Application

The function of the nitrogen gas system is to supply nitrogen at controlled pressures to various 

locations in the unit for the following reasons:

• pressurizing the SI accumulators

• inerting and purging systems

• use as a cover gas

• preventing corrosion during wet and dry lay-up of components

The nitrogen gas system supplies the following major systems and components:

• SI accumulators

• waste processing liquid drains system’s reactor coolant drain tank

• RCS primary relief tank

• waste gas (WG) system

• vent gas (VG) system

• release recovery system tanks

• CS’s volume control tank and letdown degasifier

• resin sluice system tanks

• reactor makeup water tank

• main steam system

• boron recovery system’s primary drain tanks and degasifier

• steam generator blowdown system

2.3.3.24.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the nitrogen gas system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the nitrogen gas system mechanical components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.3.25 Oil Collection for Reactor Coolant Pumps System

2.3.3.25.1 Summary of Technical Information in the Application

The seismically-designed lube oil collection system for the four RCPs has been designed with 

two collection tanks, with two pumps draining to each tank. Each of the two tanks has been 
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sized to contain 125 percent of the oil inventory of one pump. A seismically designed dike has 

been provided around each tank. Each tank, in combination with its associated dike, has been 

sized to contain the entire inventory of two pumps. The tanks and the dikes have been located 

so that the excess oil does not present a fire hazard to any safety-related equipment. 

Additionally, there is no ignition source near the diked area.

2.3.3.25.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the oil collection for RCPs system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the 

applicant adequately identified the oil collection for RCPs system mechanical components 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.26 Plant Floor Drain System

2.3.3.26.1 Summary of Technical Information in the Application

The floor drains in this system are located outside any area with a potential for contamination. 

The plant floor system is located in those areas where automatic sprinkler and spray systems 

are installed. These drains are sized to pass the expected flows resulting from automatic 

system actuation, as well as that produced by manual hose application if employed. In areas 

where hand hose lines are the only water sources used to combat a fire, drains are provided if 

accumulation of fire-fighting water could result in unacceptable damage to safety-related 

equipment in the area. In such areas, the operator can use the hose to control the quantity of 

drain water to avoid unacceptable damage to equipment.

Drainage within the diesel generator building is designed to prevent the spread of fire from one 

area to another. Other areas with combustible liquids have normally closed shut-off valves in 

the drain lines or drain directly to the oil and water separation vault.

The electrical tunnels contain no sources of floodwater other than the fire protection system 

piping. The fire protection system piping consists of zoned preaction dry pipe systems with the 

zone valves located outside the electrical tunnel areas. The individual fire protection system 

zones will be actuated by ionization fire detectors. Fire detectors are provided in the areas

zoned to provide local indication and an audible and visual alarm in the control room and the 

guardhouse. Water from the fire protection system will be drained from the tunnel zones to a 

sump outside the electrical tunnel areas (located in the emergency feedwater pump house). 

Redundant pumps have been installed in the sump to pump the water collected from the tunnel 

to the storm drain system (not within the scope of license renewal).

Failure of a circulating water system expansion joint in the turbine building will flood the ground 

floor pit east of the condensers in the turbine building. Assuming the worst possible failure to be 

a 2 in. gap all around, the pit would fill up in about 3 minutes, unless prompt action by the 

operator is taken. There are two level switches (1-DR-LSH-5984 and 5985) in the condenser pit 

that provide sequential alarms in the control room to warn the operator of the flooded condition. 

No loss of offsite power is induced by a failure of this equipment provided operator action is 

taken within 22.2 minutes to mitigate the consequences of the flood.
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2.3.3.26.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.26 and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

The staff’s review identified an area in which additional information was required 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 2.3.3.26-01, dated January 5, 2011, the staff noted LRA Section 2.3.3.26 provides an 

UFSAR reference of Appendix A, Section F.3, page 41. However, the reference could not be 

located in the UFSAR that was submitted to the staff with the LRA. The applicant was asked to 

provide the UFSAR reference for Appendix A, Section F.3, page 41, so that the staff can 

confirm that the components included in the plant floor drain system have been appropriately 

identified and included within the scope of license renewal.

In its response dated February 3, 2011, the applicant provided a copy of the UFSAR reference 

for Appendix A, Section F.3, page 41. UFSAR Section 9.5.1, “Fire Protection System,” 

references the supplemental report, “Evaluation and Comparison to BTP APCSB 9.5-1, 

Appendix A Report,” which describes the floor drain system components used for fire protection.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.26-01 acceptable 

because the staff reviewed the supplemental report to confirm the plant floor drain system 

components that are within the scope of license renewal. Therefore, the staff’s concern 

described in RAI 2.3.3.26-01 is resolved.

2.3.3.26.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the plant floor drain system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.27 Potable Water System

2.3.3.27.1 Summary of Technical Information in the Application

Potable water received from the Town of Seabrook water main is metered at the fire pump 

house and then piped to the fire water storage tanks and the plant distribution system. The fire 

protection tank fill line is equipped with a backflow preventer. Chlorine injection is provided for 

control of biological growths in the fire protection tanks and associated piping. The water 

treatment makeup system uses the undedicated 200,000-gal. capacity of each fire water 

storage tank as its source of makeup water. The system is not safety-related and is not relied 

upon to perform a safety-related function.

The distribution system consists of branch mains to the various personnel areas—the service 

water cooling tower fill, the demineralized water makeup system, and the fire water storage tank 

fills. Branch headers and branches lead to the various fixtures. Drinking fountains, eye and 

face wash fountains, lavatories, urinals, water closets, showers, safety showers, water coolers, 
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water heaters, and special fixtures are provided according to occupancy. Connections are 

provided to kitchen, laboratory, and similar equipment requiring potable water. The branch main 

to personnel areas is equipped with a backflow preventer and hose bib vacuum breakers to 

prevent backflow or siphoning.

2.3.3.27.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.27 and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

The staff’s review identified areas in which additional information was required 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 2.3.3.27-01, dated January 5, 2011, the staff noted on LRA drawing 

PID-1-CBA-LR20303, at locations B-11 and B-12, that the applicant depicts sections of 

safety-related 12 in. piping directly connected to nonsafety-related 11⁄2 in. piping passing through 

gate valves V-7 and V-8. The nonsafety-related 11⁄2 in. lines continue through check valve V-3 

to the storm sewer. The seismic anchors could not be located for these lines through valves 

V-7 and V-8 beyond the safety and nonsafety interface. The applicant was asked to provide the 

seismic anchor locations for the 11⁄2 in. lines.

In its response dated February 3, 2011, the applicant stated that nonsafety-related 11⁄2 in. piping 

is Seismic Category I and that the Seabrook design review indicated the smaller 11⁄2 in. nominal 

diameter piping would not impose loads on the larger safety-related piping. The applicant 

referenced UFSAR 3.7(B).3.3a, in which the branch connections are decoupled from the main 

runs when the ratio of the branch to run section is equal to or less than 0.05. The applicant 

indicated that the ratio of the branch (the nonsafety-related 11⁄2 in. piping) to run section (12 in.

safety-related piping) moduli is 0.003, which is less than 0.05. Thus, the applicant determined 

that seismic anchors were not required beyond the safety and nonsafety interface.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.27-01 acceptable 

because the staff confirmed that the applicant’s assessment of the nonsafety-related 11⁄2 in.

piping effects onto the safety-related 12 in. piping is consistent with the piping decoupling 

criteria ,as indicated in the UFSAR, which negated the purpose for establishing seismic anchors 

on the 1 1⁄2 in. piping. Therefore, the staff’s concern described in RAI 2.3.3.27-01 is resolved.

In RAI 2.3.3.27-02, dated January 5, 2011, the staff noted on LRA drawing PID-1-DF-LR20200, 

at location H-7, that the applicant depicts a section of 4 in. piping within scope of license 

renewal under 10 CFR 54.4 (a)(2). The 4 in. piping continues to LRA drawing 

PID-1-SD-LR20402, at location F-7, where it is no longer depicted within scope of license 

renewal. The applicant was asked to justify the exclusion of the portion of the 4 in. piping from 

the scope of license renewal on LRA drawing PID-1-SD-LR20402.

In its response dated February 3, 2011, the applicant stated that the 4 in. piping is within scope 

of license renewal under 10 CFR 54.4 (a)(2) up to the point where it exits the east main steam 

and feedwater pipe chase. The applicant also stated that LRA drawing PID-1-SD-LR20402 

erroneously depicted the 4 in. piping as being excluded from scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.27-02 acceptable 

because the 4 in. piping on LRA drawing PID-1-SD-LR20402 is within the scope of license 

renewal and was erroneously depicted as not within scope of license renewal under 

10 CFR 54.4 (a)(2). Therefore, the staff’s concern described in RAI 2.3.3.27-02 is resolved.
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2.3.3.27.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the potable water system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.28 Primary Auxiliary Building Air Handling System

2.3.3.28.1 Summary of Technical Information in the Application

The function of the normal heating and ventilating system for the primary auxiliary building is to 

provide sufficient circulation of filtered outside air for removal of heat generated by lighting and 

equipment in the summer and to offset building heat losses in the winter, in rooms and areas of 

the primary auxiliary building. The primary auxiliary building ventilation and heating system 

(primary auxiliary building air handling) system also supplies conditioned air to the fuel storage 

building and makeup to the containment enclosure area. Under normal operating conditions, 

the charging pump rooms are exhausted through this heating and ventilating system.

2.3.3.28.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the primary auxiliary building air handling system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concluded that the applicant adequately identified the primary auxiliary building air handling 

system mechanical components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.29 Primary Component Cooling Water System

2.3.3.29.1 Summary of Technical Information in the Application

The primary component cooling water system supplies flow to the following safety-related 

components, which are required for safe shutdown or to ameliorate the consequences of an 

accident or both:

• containment building spray pumps

• containment building spray heat exchangers

• RHR pumps

• RHR heat exchangers

• SI pumps

• centrifugal charging pumps

• containment enclosure coolers

The system serves as an intermediate fluid barrier between the reactor coolant and service 

water systems, assuring that leakage of radioactive fluid from the components being cooled is 

not released to the environment.
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The primary component cooling water system consists of loop A and loop B, which are two 

independent and redundant flow loops, and a RCP thermal barrier loop. Loops A and B each 

supply component cooling water to one of the redundant components performing engineered 

safety-related functions to the RCP thermal barrier loop and to other nonsafety-related loads.

A supply and return cross connect and a primary component cooling water head tank outlet line 

cross connect are included in the system design. Each cross connect consists of two isolation 

valves. These valves are locked closed when two independent primary component cooling 

water trains are required to be operable, in accordance with plant technical specifications.

The RCP thermal barrier loop is designed to provide 100 percent of the cooling capacity 

required to cool the RCP thermal barrier cooling coils under all normal plant operating 

conditions. The RCP thermal barrier loop has been classified as nonessential, but it 

incorporates the following special design features to provide a high degree of reliability:

• Primary component cooling water loops A and B each provide cooling to the RCP

thermal barrier loop.

• Pipe supports and pressure-retaining system components are designed in accordance 

with ASME III safety Class 3 and seismic Category I requirements.

• Flow instrumentation trains to the annunciator, pumps, pump drive motors, and 

associated controls are redundant, are qualified to 1E requirements, and are designed to 

operate with power from the diesel generators in the event of a loss of offsite power.

• Instrument sensing lines are designed in accordance with the requirements of 

independent safety analysis (ISA) Standard 67.02-1980.

Those portions of the primary component cooling water system that furnish cooling water to 

safety-related components are designated safety Class 3, seismic Category I, and are located in 

seismic Category I structures. The cross connects are designated safety Class 3, seismic 

Category I and are located in seismic Category I structure.

To provide increased reliability for cooling safety-related components, a cross connect from the 

fire protection and demineralized water systems to the primary component cooling water system 

is included in the system design. This cross connect can be used to provide cooling water to 

the charging pump lube oil coolers or provide emergency makeup water to safety-related 

portions of the primary component cooling water system. This cross connect is backed up by a 

seismic Category I service water system and booster pump makeup source.

Those portions of the primary component cooling water system that are non-seismic Category I 

portions of the system are isolated in the event of a leak. The isolation valves will close on a 

primary component cooling water head tank low-level alarm. Thus, the system safety function is 

not compromised in the event of a leak in the nonsafety portion of the system.

2.3.3.29.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.29, UFSAR Section 9.2.2, UFSAR Tables 6.2-83, 7.4-1,

and 7.5-1, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 

identified areas in which additional information was required to complete the review of the 

applicant’s scoping and screening results. The applicant responded to the staff’s RAIs as 

discussed below.
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In RAI 2.3.3.29-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-CC-LR20205, 

at locations C-5 and F-7, that the applicant depicts sections of safety-related piping connected 

to nonsafety-related piping that continue onto LRA drawing PID-1-DM-LR20350. However, the 

seismic anchors could not be located on the nonsafety-related piping beyond the safety and 

nonsafety interface on LRA drawing PID-1-DM-LR20350. The applicant was asked to provide 

the seismic anchor locations on the nonsafety-related piping, as described above, beyond the 

safety and nonsafety interface.

In its response dated February 3, 2011, the applicant stated that seismic anchors were not 

depicted on both LRA drawings since all of the demineralized water system piping in the primary 

auxiliary building was included within the scope of license renewal under 10 CFR 54.4(a)(2) for 

structural support. The applicant did indicate that a seismic anchor is physically located on 

piping approximately 6 ft from the safety-related to nonsafety-related interface in one area of 

LRA drawing PID-1-CC-LR20205. The applicant also stated that the extent of the continued 

piping and supports ensure that nonsafety-related piping loads are not transferred through the 

safety and nonsafety interface, as determined by its piping stress analysis.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.29-01 acceptable 

because all of the nonsafety-related piping in the primary auxiliary building was included within 

the scope of license renewal under 10 CFR 54.4(a)(2) for structural support. Therefore, the 

staff’s concern described in RAI 2.3.3.29-01 is resolved.

In RAI 2.3.3.29-02, dated January 5, 2011, the staff noted on an LRA drawing that the applicant 

depicts a section of 1 in. piping within scope of license renewal for 10 CFR 54.4(a)(2). 

However, the applicant depicts the 1 in. piping as excluded from scope of license renewal in the 

continuation LRA drawing. The applicant was asked to justify the exclusion of the 1 in. piping 

from scope of license renewal in LRA drawing PID-1-CS-LR20727.

In its response dated February 3, 2011, the applicant stated that the 1 in. piping shown on the 

LRA drawing PID-1-CS-LR20727 for the primary auxiliary building is excluded from scope of 

license renewal due to the chiller surge tank and its associated piping being in the state of dry 

layup (i.e., not fluid-filled). The applicant also stated that the LRA drawing erroneously depicted 

the 1 in. piping as being within scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.29-02 acceptable. The 

staff agrees with the applicant’s justification of excluding the above 1 in. piping from scope of 

license renewal due to its attachment to the chiller surge tank, which is in dry layup and not

within the scope of license renewal. Therefore, the staff’s concern described in RAI 2.3.3.29-02 

is resolved. 

In RAI 2.3.3.29-03, dated January 5, 2011, the staff made the following two observations 

involving the applicant’s usage of its methodology described in LRA Section 2.1.2.2.2.

• On LRA drawings PID-1-CC-LR20205 (loop A) and PID-1-CC-LR20211 (loop B),

respectively, the applicant depicts sections of safety-related piping connected to 

nonsafety-related piping that are within the scope of license renewal for 

10 CFR 54.4(a)(2). No seismic anchors are indicated on these LRA drawings. These 

lines continue on LRA drawing PID-1-FP-LR20268, at location B-9, where seismic 

anchors could not be located on the nonsafety-related piping beyond the safety and 

nonsafety interface.
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• On LRA drawing PI D-1-CC-LR20211, the applicant depicts a section of safety-related 

piping connected to nonsafety-related piping as being within the scope of license 

renewal. The piping continues onto LRA drawing PID-1-DM-LR20350, where a seismic 

anchor could not be located on the nonsafety-related piping beyond the safety and 

nonsafety interface.

The applicant was asked to provide the seismic anchor locations on the nonsafety-related piping 

beyond the safety and nonsafety interface as described in both of the above issues.

In its response dated February 3, 2011, the applicant addressed the first issue by stating that for 

LRA drawings PID-1-CC-LR20205 (loop A) and PID-1-CC-LR20211 (loop B), seismic anchors 

are excluded on the nonsafety-related piping beyond the safety and nonsafety interface 

because the nonsafety-related piping, which continues onto LRA drawing PID-1-CC-LR20205 

does the following:

• provides structural support for the piping beyond the safety and nonsafety interface 

• ensures that nonsafety-related piping loads are not transferred through the interface as 

determined by its piping stress analysis

For the second issue, the applicant stated that for LRA drawing PID-1-CC-LR20211, seismic 

anchors are excluded on the nonsafety-related piping beyond the safety and nonsafety interface 

because the piping, which continues onto LRA drawing PID-1-DM-LR20350, does the following:

• provides structural support for the piping beyond the safety and nonsafety interface 

• ensures that nonsafety-related piping loads are not transferred through the interface as 

determined by its piping stress analysis

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.29-03 acceptable 

because the applicant explained that no seismic anchors are required because the piping stress 

analyses determined that nonsafety-related piping loads are not transferred through the 

interface. Therefore, the staff’s concern described in RAI 2.3.3.29-03 is resolved.

2.3.3.29.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the primary component cooling water system mechanical components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the mechanical components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.30 Radiation Monitoring System

2.3.3.30.1 Summary of Technical Information in the Application

The radiation data management system (radiation monitoring (RM) system) consists of three 

subsystems:the process and effluent RM system, the area RM system, and the airborne and 

particulate radioactivity monitoring system. The functional performance requirements for the 

RM system include the following:
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• warn of leakage from process systems containing radioactivity

• monitor the amount of radioactivity released in effluents

• isolate lines containing liquid and gaseous activity when activity levels reach a preset 

limit

• record the radioactivity present in various station systems and effluent streams

• provide a means for leakage detection

• provide information on failed fuel

• monitor plant areas within the radiologically controlled area for radiation

2.3.3.30.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the RM system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the RM system mechanical components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.31 Reactor Makeup Water System

2.3.3.31.1 Summary of Technical Information in the Application

The reactor makeup water system provides the storage and distribution of reactor grade water. 

It also provides storage capacity for water recycled by the boron recovery system.

The reactor makeup water system consists of one reactor water storage tank, two redundant, 

full capacity reactor makeup water pumps, and associated piping, valves, instrumentation, and 

controls.

The intended functions of the reactor makeup water system component types within the scope 

of license renewal include the following:

• maintain system interface with the CS and the containment building spray system

• provide post-accident monitoring

• provide containment isolation function

LRA Table 2.3.3-31 lists the reactor makeup water system components types that require AMR.

2.3.3.31.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the reactor makeup water system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the reactor makeup water system components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).
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2.3.3.32 Release Recovery System

2.3.3.32.1 Summary of Technical Information in the Application

The release recovery system contains and quenches relief valve discharge from the CS and 

boron recovery system degasifiers as well as the boron recovery system, steam generator 

blowdown system, and waste processing liquid system evaporators.

Release recovery tank, 1-RR-TK-258, is in-scope for license renewal from a spatial 

consideration due to its location in the primary auxiliary building. The relief valve in the 

degasifier system opens at 60 psig to direct flow to the release recovery tank, 1-RR-TK-258, 

located in the primary auxiliary building hallway, outside the degasifier cubicle. Quench tank, 

1-RR-TK-258, and the release recovery system piping will normally be under a nitrogen blanket 

to eliminate the potential for explosive gas mixtures if H2 is present in the relieving fluid. Under 

normal conditions, 1-RR-TK-258 will be half filled with demineralized water to ensure that 

quenching of a design base release can be accomplished. The tank is designed for an 

8 second release from full open 1-RR-V-655.

2.3.3.32.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the release recovery system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the release recovery system mechanical components subject to an AMR, 

as required by 10 CFR 54.21(a)(1).

2.3.3.33 Resin Sluicing System

2.3.3.33.1 Summary of Technical Information in the Application

The spent resin sluicing (RS) system collects the spent resin from all the demineralizers and ion 

exchangers of the nuclear plant.

2.3.3.33.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the RS system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the RS system mechanical components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.34 Roof Drains System

2.3.3.34.1 Summary of Technical Information in the Application

The roof drains system is nonsafety-related. It is installed on major buildings that have relatively 

flat roofs. The system removes rainwater and water from melting snow from the roof. It 

consists of roof-mounted strainers that collect the water and transport it through connected 

ceiling mounted pipes to the storm drain system (not within the scope of license renewal). The 
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plant’s dewatering system discharges water to the roof drains system, which then flows to the 

storm drain system and out to the circulating water system for discharge.

2.3.3.34.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.34 and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

The staff’s review identified an area in which additional information was required 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 2.3.3.34-01, dated January 5, 2011, the staff noted on LRA drawing, PID-1-DR-LR20633, 

that the applicant depicts 6 in. lines that continue onto LRA drawing PID-1-SD-20402. On LRA 

drawing PID-1-DR-LR20633, the applicant depicts 6 in. piping that enters the continuation flag 

marked “B” as being included within scope of license renewal under 10 CFR 54.4(a)(2). The 

applicant depicts the other 6 in. piping that enters the continuation flag, marked “C,” as being 

excluded from scope of license renewal. However, the applicant depicts on the continuation 

LRA drawing, PID-1-SD-20402, the 6 in. piping for “B” as being excluded from scope of license 

renewal, while the other 6 in. piping for “C” is shown as being included within scope of license 

renewal. The applicant was asked to clarify the scoping classifications of both 6 in. piping 

sections on both LRA drawings.

In its response dated February 3, 2011, the applicant stated that the 6 in. piping in LRA drawing 

PID-1-SD-LR20402, which is marked with the “B” continuation flag, is within scope of license 

renewal for 10 CFR 54.4 (a)(2) up to the area where it exits the emergency feedwater 

pumphouse (EFPH). The applicant also stated that the 6 in. piping in LRA drawing 

PID-1-DR-LR20633, which is marked with the “B” continuation flag, was excluded from scope of 

license renewal from where it exits the EFPH. Lastly, the applicant stated that the 6 in. piping in 

LRA drawing PID-1-SD-LR20402, which is marked with the “C” continuation flag, was excluded 

from scope of license renewal from where it exits the EFPH. The applicant indicated that both 

6 in. roof drain lines in the EFPH are within the scope of license renewal up to the point where 

they exit the EFPH.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.34-01 acceptable 

because the applicant explained that the piping in the EFPH is within the scope of license 

renewal. The piping is not within the scope of license renewal after it leaves the EFPH. 

Therefore, the staff’s concern described in RAI 2.3.3.34-01 is resolved.

2.3.3.34.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the roof drains system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).
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2.3.3.35 Sample System

2.3.3.35.1 Summary of Technical Information in the Application

The sample subsystems from the reactor coolant, steam generators, and other auxiliary 

systems provide representative gas and liquid samples for laboratory analysis, in accordance 

with RG 1.21, Positions C.6 and C.7. Typical information obtained includes reactor coolant 

boron, sodium ion and halogen concentrations, fission product radioactivity level, H2, oxygen, 

and fission gas content, corrosion product concentration, and chemical additive concentration. 

The sample subsystem for secondary steam and water systems provides representative 

samples for measuring specific and cation conductivity, concentrations of sodium ion, dissolved 

oxygen, and hydrazine.

The system is divided into five subsystems—reactor coolant sampling, steam generator 

blowdown sampling, auxiliary system sampling, secondary steam and water sampling, and 

post-accident sampling.

2.3.3.35.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.35, UFSAR Sections 9.2.3.1 and 9.3.2.2, UFSAR 

Tables 6.2-83 and 7.5-1, and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The 

staff’s review identified an area in which additional information was required 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 2.3.3.35-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-SB-LR20626, 

at location B-12, that the applicant depicts a section of 3 in. piping within scope of license 

renewal under 10 CFR 54.4(a)(3). The 3 in. piping continues onto LRA drawing 

PID-1-SB-LR20629, in which the 3 in. piping is excluded from scope of license renewal. The 

applicant was asked to justify the exclusion of this portion of 3 in. piping from scope of license 

renewal on LRA drawing PID-1-SB-LR20629.

In its response dated February 3, 2011, the applicant stated that the in-scope portion of the 3 in.

piping on LRA drawing PID-1-SB-LR20626 should have ended before continuing onto LRA 

drawing PID-1-SB-LR20629. The applicant stated that license renewal note 3 in LRA drawing 

PID-1-SB-LR20626, which indicates that “[p]ipe exits Waste Process Building Tank Farm area 

and is not subject to aging management review,” should have been labeled near the 3 in. piping 

where it exits the tank farm on the LRA drawing.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.35-01 acceptable 

because the staff confirmed that the scoping boundary of the 3 in. piping is consistent with

license renewal note 3 in LRA drawing PID-1-SB-LR20626 regarding piping that exits the waste 

process building tank farm area. Therefore, the staff’s concern described in RAI 2.3.3.35-01 is 

resolved.

2.3.3.35.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 
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appropriately identified the sample system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified all the 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.36 Screen Wash System

2.3.3.36.1 Summary of Technical Information in the Application

The service water traveling screens form a full-channel mesh strainer that removes debris from 

the water flowing into each service water pump bay. The debris collected on the screen is 

removed by a high-pressure water spray supplied by the service water screen wash pump.

The circulating water traveling screens prevent fish and debris from entering the circulating 

water system. One traveling screen is provided for each circulating water pump bay. Debris is 

collected on the upstream side of the traveling screen and is carried upward as the screen 

rotates. As the debris nears the top of screen travel, high velocity jets of water from the screen 

wash nozzles flush it out.

The circulating water screen wash pumps are one means to supply the chlorination system with 

salt water. Flow to the chlorination system from the screen wash system pumps goes through a 

common header. The sodium hypochlorite metering pumps discharge into this common header.

During initial startup or total circulating water system shutdown, water is supplied to one of two 

circulating water lube water pumps from the service water screen wash pump.

2.3.3.36.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the screen wash system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the screen wash system mechanical components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.3.37 Service Water System

2.3.3.37.1 Summary of Technical Information in the Application

The service water system was originally designed for two units. The service water pump house 

has a pump bay for each unit. Each pump bay has two supplies one from the intake discharge 

transition structure and one from the discharge transition structure. The Unit 2 supply valves 

are locked, closed, and de-energized. Unit 2 was not completed and is non-operational. The 

Unit 2 service water return is blanked off and is not used.

The Unit 1 service water system consists of two independent and redundant flow trains. Each 

of these supplies cooling water to a primary component cooling water heat exchanger, a diesel 

generator jacket water cooler, the secondary component cooling water heat exchangers, the 

auxiliary secondary component cooling water heat exchangers, the condenser water box 

priming pump seal water heat exchangers, and—except during a LOCA—the fire protection 

system during a fire.
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Flow in each redundant train is supplied by two redundant service water pumps. Each service 

water pump is capable of supplying 100 percent of the flow required by each flow train to 

dissipate plant heat loads during normal full power operation. Thus, for full power operation,

two pumps (one pump per flow train) are required.

The four service water pumps take suction from a common bay in the service water 

pumphouse. Seawater flow is supplied to the service water pumphouse from the Atlantic Ocean 

due to the static head of the ocean above the elevation of the service water pumps.

The Atlantic Ocean serves as the normal ultimate heat sink for Seabrook. In the unlikely event 

that seawater flow to the service water pumphouse is restricted (greater than 95 percent

blockage) due to seismically induced damage to the circulating water (seawater) intake and 

discharge tunnels, a mechanical draft evaporative cooling tower is provided to dissipate 

shutdown and accident heat loads. The mechanical draft cooling tower is completely 

independent of the circulating water tunnels and the Atlantic Ocean.

The cooling tower consists of one independent cell with one fan and a center cell with two fans. 

A third cell was included for anticipated Unit 2 operation but remains nonfunctional. The cooling 

tower basin consists of a pump well and one catch basin for each of the two tower spray cells. 

The unit has an “A” and a “B” cooling tower complex flow train. The cooling tower pumps—with 

associated valves, piping, and equipment in the trains—circulate cooling water from the pump 

well basin through the primary component cooling heat exchangers, the secondary component 

cooling water heat exchangers during normal operations, the diesel generator heat exchangers 

during loss of offsite power conditions, or both during testing.

Makeup to the cooling tower can be provided by a portable tower makeup pump (in the event 

that normal makeup source is unavailable and the service water pumps are unavailable). 

RG 1.27 requires a heat sink capable of providing cooling for 30 days; the cooling tower has a 

7-day supply. The cooling tower makeup pump is tested every 18 months per technical 

specifications. After the pump is tested, it is flushed with potable water. It is capable of 

providing makeup water to the tower basin from the nearby Browns River or Hampton Harbor,

with several locations accessible by road. It consists of 3,000 ft of 5-in. rubber-lined polyester 

flexible hose and associated hose couplings and a portable diesel-driven pump that is 

self-priming within 15 ft of water level, and it is designed to deliver a minimum of 200 gallons per 

minute (gpm) from the water source to the tower basin. The 7-day period that the tower can 

operate without makeup water provides sufficient time to move the pump into position, lay the 

hose, and make the system ready for operation.

2.3.3.37.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.37, UFSAR Sections 9.2.1 and 9.2.5, UFSAR 

Tables 7.4-1 and 7.5-1, and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The 

staff’s review identified an area in which additional information was required 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 2.3.3.37-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-SW-LR20795, 

at locations B-11 and C-12, that the applicant depicts strainers within scope of license renewal 

under 10 CFR 54.4(a)(1). However, the component type “strainer” and its component intended 
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function(s) are not included in LRA Table 2.3.3-37. The applicant was asked to justify the 

exclusion of the strainer and its component intended function(s) from LRA Table 2.3.3-37.

In its response dated February 3, 2011, the applicant stated that the strainers are evaluated as 

component type “filter housing” with an intended function of “pressure boundary” in LRA 

Table 2.3.3-37. The applicant also stated that the screen portion of the strainer was evaluated 

as component type “filter element” with an intended function of “filter” in LRA Table 2.3.3-37.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.37-01 acceptable 

because the staff confirmed that both the component types, “filter housing” and “filter,” are 

included in LRA Table 2.3.3-37. Therefore, the staff’s concern described in RAI 2.3.3.37-01 is 

resolved.

2.3.3.37.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the service water system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.38 Service Water Pump House Air Handling System

2.3.3.38.1 Summary of Technical Information in the Application

The service water pump house heating and ventilation systems are comprised of the heating 

and ventilation systems for the pump room area of the service water pump house.

The ventilation function is provided by the service water pump house air handling system. The 

heating function is provided by the HW system and is evaluated separately.

The pump room area is ventilated and cooled with outside air supplied through 

pneumatically-operated dampers, and it is exhausted through exhaust fans and backdraft 

dampers. Each exhaust fan, and its associated supply air damper, is controlled by a separate 

thermostat located in the pump room area. The thermostat settings are staggered such that the 

fans will start in sequence. Each fan is powered by a separate and independent engineered 

safety features electrical train. Each supply air damper is designed to fail open on loss of air or 

electric power to its solenoid valve.

The switchgear areas of the service water pump house, one for electrical train A equipment and 

the other for electrical train B equipment, are ventilated with filtered outside air supplied by one 

of two full-sized supply fans through a seismically supported duct system. Each fan is powered 

by a separate and independent engineered safety features electrical train. Air is drawn from the 

outside through a roll-type filter, a fan, or a backdraft damper and is then distributed through 

ductwork into the two switchgear areas. Air is exhausted from each switchgear area through its 

respective relief damper. There are two thermostats per fan to control its operation, one in train 

A switchgear room and the other in train B switchgear room. Both the thermostats on the lead 

fan have identical set points.
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The service water cooling tower heating and ventilation systems are comprised of a heating 

system and a ventilation system for each redundant switchgear room and a ventilation system 

for the pump room. Each switchgear room and the pump room are ventilated by drawing air 

from, and exhausting to, the outside.

Ventilation and cooling air is drawn into the ventilation and mechanical equipment area of the 

pump room from the outside through fixed louvers and a roughing filter.

Cooling of the pump room area, when required, is accomplished by redundant exhaust fans. 

Each fan is controlled by its individual thermostat. Thermostats are set so if one thermostat, 

fan, or its power supply fails, the redundant fan, served by a separate Class 1E power supply, 

will start before overheating occurs.

Each of the two cooling tower switchgear rooms is supplied with ventilating and cooling air, 

when required, from its own independent supply fan located in the mechanical equipment area. 

The supply air fan for each switchgear room is provided electrical power for a Class 1E power 

source, which is independent of the other three. Each supply fan is cycled by a thermostat 

located in its respective switchgear room. Supply air is directed to the switchgear room via 

sheet metal ductwork. Heat-laden air from the switchgear rooms is exhausted through a relief 

damper to the outside.

2.3.3.38.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the service water pump house air handling system components within 

the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the 

applicant adequately identified the service water pump house air handling system components 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.39 Spent Fuel Pool Cooling System

2.3.3.39.1 Summary of Technical Information in the Application

The functions of the spent fuel pool cooling and cleanup system include the following:

• continuously remove decay heat generated by fuel elements stored in the pool

• continuously maintain a minimum of 13 ft of water over the spent fuel elements to shield 

personnel

• maintain the chemical parameters and optical clarity of the spent fuel pool water and the 

water in the reactor cavity and refueling canal during refueling operations

All portions of the spent fuel pool cooling loop are designated safety Class 3 and are designed 

and constructed to meet seismic Category I requirements. Those portions of the cleanup 

system not designed to these requirements are normally isolated from the cooling loop.

The spent fuel pool cooling and cleanup system is comprised of three subsystems:the spent fuel 

pool cooling subsystem, the spent fuel pool cleanup subsystem, and the reactor cavity and 

canal cleanup subsystem.
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Spent Fuel Pool Cooling Subsystem. The spent fuel cooling pumps take suction from the pool 

and circulate water through the heat exchangers, which are cooled by the primary component 

cooling water system. Pool water enters the suction line through a strainer near one wall of the 

pool at a point 13 ft higher than the return line terminations. The return lines are located at a 

sufficient distance from the suction line to assure adequate circulation and uniform pool water 

temperatures. All system connections to the fuel pool penetrate at elevations sufficiently above 

the top of the fuel to maintain adequate shielding in the event the water level drains to the 

penetration level. Piping arrangement precludes siphoning below this level. All components in 

contact with the spent fuel cooling water are stainless steel. The spent fuel pool pump motors 

are Class 1E motors. Pumps 1-SF-P-10A and 1-SF-P-10B are powered from separate 

emergency busses. Pump 1-SF-P10C can be aligned to be powered from either emergency

bus.

Spent Fuel Pool Cleanup Subsystem. Spent fuel pool water quality is maintained by a pool 

skimmer loop, which filters and demineralizes the circulated water. The pool skimmer loop 

consists of five pool surface skimmers, a skimmer pump, two filters, and a demineralizer. This 

system is used to maintain the pool surface free from floating particles and other materials and 

to remove radioactive materials in the water. The system is sized to process approximately 

120 gpm, which means that one-half of the pool volume is processed in a day. All spent fuel 

pool cooling and cleanup system equipment is located in the fuel storage building, except the 

filters and demineralizer, which are located in the demineralizer area of the primary auxiliary 

building. The skimmer pump motor is not Class 1E and is supplied from a local control center. 

The spent fuel pool cleanup subsystem can also be used to purify the RWST water, drain the 

water in the cask loading and fuel transfer canal areas (using a submersible pump), and purify 

the refueling cavity water during refueling operations. A cleanup system (1-CBS-SKD-161) is 

also used for RWST or spent fuel pool processing.

Reactor Cavity and Canal Cleanup Subsystem

2.3.3.39.2 Staff Evaluation

. The reactor cavity cleanup portion of the 

system is designed to purify the reactor cavity during refueling operations to improve the optical 

clarity of the water. The system consists of five surface skimmers at the water surface of the 

refueling cavity and canal and three drains, all piped to the suction of the reactor cavity cleanup 

skimmer pump via a lead-shielded disposable cartridge type filter unit. The lead-shielded filter 

removes radioactive particulate in the refueling water in order to prevent crud buildup in 

socket-welded piping downstream of the skimmer pump. This filter also minimizes crud buildup 

in the CS and spent fuel pool cleanup system filters and demineralizers depending on the

particular lineup. The cavity water is pumped through the CS mixed bed demineralizer and 

filters to the suction of the RHR pumps where it is returned to a cold leg through an RHR heat 

exchanger. During cavity drain down upon completion of refueling, refueling water can be 

routed via the reactor cavity cleanup system to the RWST via the spent fuel pool cleanup 

system. Also, the reactor cavity cleanup system may be used to send refueling water to the 

liquid waste system floor drain tanks. This lineup would be primarily used at the conclusion of 

drain down when the residual refueling water may not be suitable for return to the RWST. As an 

alternative to using the installed cavity cleanup pump and shielded filter, a provision exists to 

install temporary equipment between isolation valves 1-SF-V-81 and 85. The reactor cavity 

cleanup pump motor is not Class 1E, and it is supplied from a motor control center in the control 

building.

The staff reviewed LRA Section 2.3.3.39, UFSAR Sections 9.1.2 and 9.1.3, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 
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and the guidance in SRP-LR Section 2.3. The staff’s review identified areas in which additional 

information was required 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 2.3.3.39-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-SF-LR20484 

that the applicant refers to license renewal note 1, which states “[t]hese components are drained 

during operation so therefore they have an internal environment of air/gas so they have no 

license renewal (LR) intended function and not in scope.” However, on LRA drawing 

PID-1-DM-LR20353, license renewal note 1 indicates refueling canal skimmer pump SF-P-272 

is a component that is in-scope for license renewal, which contradicts license renewal note 1 on 

LRA drawing PID-1-SF-LR20484. Additionally, the portion of the line excluded from scope of 

license renewal is directly connected to the pump P-272 and continues onto the refueling pool 

and canal skimmers. LRA Table 3.3.2-39 does not provide an internal environment of air or gas 

for pump casing. The applicant was asked to clarify the scoping designation of the piping 

directly connected to the refueling canal skimmer pump.

In its response dated February 3, 2011, the applicant stated the pump SF-P-272 is a 

nonsafety-related pump and is in operation only during refueling outages when the refueling 

pool and canal are flooded. The applicant also stated that the pump and associated piping are 

drained during normal power operation and are excluded from scope of license renewal. The 

applicant described that license renewal note 1, found in LRA drawing PID-1-DM-LR20353, 

refers to only the mechanical seal supply system piping attached to the pump mechanical seal 

in containment as being included within scope of license renewal under 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.39-01 acceptable 

because the SF-P-272 pump and its piping do not have any license renewal-intended functions 

and are drained during normal power operation. Therefore, the staff’s concern described in 

RAI 2.3.3.39-01 is resolved.

In RAI 2.3.3.39-02, dated January 5, 2011, the staff identified a discrepancy between the CLB 

and LRA descriptions of the alternate spent fuel pool cooling (ASFPC) heat exchanger. The 

applicant states in the UFSAR that the ASFPC heat exchanger is available and can be placed in 

service as needed. However, the applicant also describes in the LRA that the ASFPC heat 

exchanger is blank-flanged and is in abandoned status. The applicant was asked to clarify if the 

ASFPC heat exchanger is available as part of the spent fuel pool cooling system and if the 

component is in-scope for license renewal.

In its response dated February 3, 2011, the applicant stated that an UFSAR change request has 

been issued to remove the discussion of the ASFPC from the UFSAR, excluding it from scope 

of license renewal. The applicant indicated that UFSAR Section 9.1.3.1 has been revised to 

indicate the ASFPC system is no longer required and is isolated from the service water and 

spent fuel pool cooling systems. The applicant stated that other sections in the UFSAR that 

reference the ASFPC were also deleted.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.39-02 acceptable 

because the ASFPC is isolated from the service water and spent fuel pool cooling systems; 

thereby excluding it from scope of license renewal. The applicant stated that an UFSAR change 

request has been issued to remove all references to the ASFPC heat exchanger. Therefore, 

the staff’s concern described in RAI 2.3.3.39-02 is resolved.
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2.3.3.39.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the spent fuel pool cooling system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified all the mechanical components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.40 Switchyard

2.3.3.40.1 Summary of Technical Information in the Application

The 345-kV switching station consists of metal-enclosed, gas-insulated components (circuit 

breakers, disconnect switches, buses, surge arresters, potential devices, etc.) connected by an 

integral bus system. Pressurized sulphur hexafluoride (SF6), a nonflammable, nontoxic gas, is 

used as the insulating and arc-quenching medium. Each circuit breaker and each bus section 

of the 345-kV switching station forms a separate gas-insulated system that is individually 

monitored as a three-phase system. Each three-phase circuit breaker is supplied with its own 

self-contained SF6 gas system. There is no interconnection between the circuit breaker SF6 gas 

systems and the switching station gas systems.

The bus section gas systems include the three-phase bus connections between two circuit 

breakers, extending to the point of connection to a transformer or to an overhead line. 

Metal-enclosed, SF6-insulated buses connect the 345-kV switching station directly to the 

high-voltage bushings of the generator step-up (GSU) transformers and the reserve auxiliary 

transformers (RATs). The electrical configuration of the 345-kV switching station is a 

breaker-and-half arrangement.

2.3.3.40.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the switchyard mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the switchyard mechanical components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.41 Valve Stem Leak-off System

2.3.3.41.1 Summary of Technical Information in the Application

The valve stem leak-off system collects any stem leakage and directs it to a low point drain. 

This helps reduce the spread of contamination and keeps the water off the floor.

Initially, all manually and motor-operated valves of the RCS, which are 3 in. and larger were 

provided with double-packed stuffing boxes and intermediate lantern ring leakoff connections. 

Exceptions to this criterion are gate valves that have been determined to be susceptible to 

pressure locking, which have been modified to use the valve stem leakoff connection as a vent 
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path for the bonnet cavity. Packing configurations have evolved so that the preferred packing 

configuration is a single packing set. The industry has moved away from double packed stuffing 

boxes. These changes in packing configuration have been approved for use at Seabrook. 

Accordingly, either packing design configuration is acceptable for use at Seabrook. These 

valves use only a single packing set. Leakage to the atmosphere is essentially zero for these 

valves.

2.3.3.41.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.41, UFSAR Sections 9.2.3.1 and 9.3.2.2, UFSAR 

Tables 6.2-83 and 7.5-1, and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. In 

addition to the continuation issue identified in RAI 2.3-01 described in Section 2.3.3, the staff’s 

review identified areas in which additional information was required 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 2.3.3.41-01, dated January 5, 2011, the staff noted on LRA drawing 

PID-1-VSL-LR20776, at locations F-4 and F-11, that the applicant depicts four vent pipelines 

within scope for license renewal for 10 CFR 54.4 (a)(2). However, the valves associated with 

these vent lines are not listed on LRA Table 2.3.3-41 as a valve component type with intended 

function(s). The applicant was asked to justify the exclusion of the valves from LRA 

Table 2.3.3-41.

In its response dated February 3, 2011, the applicant stated the valves are the instrument vent 

valves for the primary component cooling water system flow indicating switches. The applicant 

indicated that the instrument valves are within scope of license renewal under the primary 

component cooling water system as a commodity. The applicant also indicated that a system 

flag designator should have been included on LRA drawing PID-1-VSL-LR20776 to denote that 

the vent valves were part of the primary component cooling water system.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.41-01 acceptable 

because the staff confirmed that the instrument vent valves were already included within scope 

of license renewal as instrument commodities for the primary component cooling water system. 

Therefore, the staff’s concern described in RAI 2.3.3.41-01 is resolved.

In RAI 2.3.3.41-02, dated January 5, 2011, the staff noted on LRA drawing 

PID-1-VSL-LR20776, at locations F-4 and F-11, that the applicant depicts four vent pipelines 

within scope of license renewal under 10 CFR 54.4 (a)(2). However, the seismic anchors could 

not be located on the nonsafety-related piping beyond the safety and nonsafety interface. The 

applicant was asked to provide the seismic anchor locations on the nonsafety-related piping 

beyond the safety and nonsafety interface.

In its response dated February 3, 2011, the applicant stated that the safety-related piping to 

nonsafety-related piping (or tubing) transition is through a flexible connector. The applicant 

explained that seismic anchors are not required since the flexible connectors decouple the 

piping system and negate a transfer of loads. However, the applicant indicated that the entire 

nonsafety-related piping (or tubing) was included within scope of license renewal and subject to 

AMR to ensure adequate protection of the safety-related piping. The applicant also indicated 

that the instrument racks, which contain the instruments that connect to the tubing, serve as the 
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seismic anchors for the valves, tubing, and instruments and are also included within scope of 

license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.41-02 acceptable 

because the nonsafety-related piping beyond the safety and nonsafety interface and connected 

to the instrument racks was already included within the scope of license renewal and subject to 

AMR. Therefore, the staff’s concern described in RAI 2.3.3.41-02 is resolved.

2.3.3.41.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the valve stem leak-off system mechanical components within the scope 

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified all the mechanical components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.42 Vent Gas System

2.3.3.42.1 Summary of Technical Information in the Application

The equipment vent gas (VG) system consists of three separate and distinct headers:an 

aerated vent header, a hydrogenated vent header, and a reactor coolant vent header. Local 

vents are not considered a part of this system but are vented to nearby ventilation system ducts.

Aerated Vent Header. The aerated vent header receives vent gas that is predominantly air plus 

radioactive contaminants from various components in the boron recovery system, liquid waste 

system (waste processing liquid system), waste solidification system, steam generator 

blowdown system, equipment and floor drainage system (waste processing liquid drains 

system), and the letdown degasifier during an oxygenated letdown sequence. The gas is then 

filtered and discharged to the atmosphere via the primary auxiliary building normal ventilation 

cleanup exhaust unit.

Hydrogenated Vent Header: The hydrogenated vent header collects radioactive contaminated 

H2 gas from the reactor coolant drain tank, chemical volume control tank, pressurizer relief tank 

sample vessel, chemical volume control tank sample vessel, primary drain tank, primary drain 

tank degasifier, and the letdown degasifier. Additionally, dependent on gaseous activity, the 

pressurizer may be purged to the hydrogenated vent header in preparation for outages. The 

collected gas is then processed through the radioactive gaseous waste system (WG system). 

The safety valve surge tank provides additional header capacity and reduces the magnitude of 

pressure fluctuations within the header. A pressure-regulating valve maintains a constant 

pressure of 2 psig in the influent line of the radioactive gaseous waste system that serves to 

isolate the radioactive gaseous waste system influent line from hydrogenated vent header 

pressure surges.

Reactor Coolant Vent Header. The reactor coolant vent header provides for the evacuation of 

the RCS during filling operations. Additionally, dependent on gaseous activity, the pressurizer 

may be purged to the hydrogenated vent header via the reactor coolant vent header in 

preparation for outages. During normal plant operations, the reactor coolant vent header is 

isolated from the hydrogenated vent header by a locked closed valve. Prior to the RCS filling 
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operation, the hydrogenated vent header is isolated from the reactor coolant vent header, 

except for a path to the primary auxiliary building exhaust unit, and the line is purged with 

nitrogen. The reactor coolant vent header is then connected to the components and piping of 

the RCS by the insertion of a spool piece between the vent line. A separator and silencer 

separates any entrained liquid, which is then drained to containment sump “A.” Prior to entering 

an outage and the opening of the RCS, the pressurizer gas space may be purged to the primary 

auxiliary building exhaust unit or the hydrogenated vent header dependent on gaseous activity. 

When routed to the hydrogenated vent header, the reactor coolant vent header is aligned to the 

pressurizer via the vent spool and purged with nitrogen. Following completion of the pressurizer 

purge, the reactor coolant vent header is isolated from the hydrogenated vent header. An 

evacuation pump is used during filling operations to direct the air from the reactor coolant vent 

header to the hydrogenated vent header, where it is filtered and discharged to the atmosphere.

2.3.3.42.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the VG system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the VG system mechanical components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.43 Waste Gas System

2.3.3.43.1 Summary of Technical Information in the Application

Hydrogenated fission product gases—from the reactor coolant letdown stream and from the 

liquids collected in the primary drain tank and the reactor coolant drain tank—are processed in 

the radioactive gaseous waste (WG) system. An iodine guard bed and a molecular sieve dryer 

reduce the contamination level of the gases before further processing by the carbon delay beds. 

The carbon delay beds provide a minimum of 60 days xenon delay and 85 hours krypton delay. 

Low activity aerated gas streams from the reactor plant aerated vent header and condenser 

vacuum pump units are filtered, monitored, and discharged to the plant unit vent.

The WG system is designed to provide sufficient processing so that gaseous effluents are 

discharged to the environment at concentrations below the regulatory limits of 10 CFR 20 and 

within the “as low as is reasonably achievable” guidelines set forth in 10 CFR Part 50, 

Appendix I. The WG system also provides sufficient holdup and control of gaseous releases, as 

specified in 10 CFR Part 50, Appendix A, GDC 60. The WG system can process a maximum 

surge flow of 1.2 standard cubic feet per minute (SCFM) from the degasifiers, which is based on 

the maximum letdown flow of 120 gpm from the RCS to the CS. This represents the most 

limiting plant operating condition for the WG system.

The portion of the waste processing building that houses the WG system is seismic Category I.

The WG system is designated NNS-related. H2 concentration is monitored in cubicles 

containing WG system components to detect a leak in the system. Monitoring of H2 

concentration is not required while the WG system is inerted with nitrogen. Dual oxygen 

monitors are provided to sample the process stream to monitor formation of explosive mixtures. 

An alarm is initiated at a predetermined setpoint prior to reaching a potentially explosive 

mixture. The WG system is designed to withstand an H2 explosion.
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The WG stream undergoes one of the following options:

• It is returned directly to the RCS via the volume control tank or the H2 injector.

• It is stored in the H2 surge tank.

• It is released to the environment via the equipment vent system.

• It is recycled to the hydrogenated vent header as makeup gas.

2.3.3.43.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the WG system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant adequately 

identified the WG system mechanical components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.44 Waste Processing Liquid System

2.3.3.44.1 Summary of Technical Information in the Application

The liquid waste system (waste processing liquid system) is nonnuclear safety class (NNS) and 

non-seismic Category I, in accordance with RG 1.26 and RG 1.29. The liquid waste system is 

designed to meet applicable requirements specified in 10 CFR, Part 20 and 10 CFR Part 50, as 

follows:

• provide a central collection point for radioactive liquid waste (This includes 

approximately 1,200 gal. per week of reactor grade and nonreactor grade leakage from 

various systems and approximately 400 gal. per week of floor drainage from area wash 

down.)

• provide preliminary processing through the use of a strainer and filters

• concentrate nonvolatile and, to some extent, volatile radioactive liquid contaminants, 

through evaporation, with a minimum decontamination factor (D.F. = Ratio of specific 

activity in the bottoms and distillate) of 104, at a bottoms concentration of 12 percent by 

weight

• concentrate the residual contaminants (bottoms) up to 12 percent total dissolved solids 

for transfer to the waste solidification system

• produce up to 25 gpm of distillate from the evaporator and condenser (The distillate is 

demineralized (if necessary) and tested in the waste processing liquid waste test tank 

before disposal offsite.)

• maintain, during normal operation, the radioactivity content of liquid effluents from the 

Seabrook site within the concentration limits expressed in 10 CFR Part 20, Appendix B, 

Table II, Column 2, on an instantaneous release basis and on an annual average 

release basis to maintain the radioactive liquid effluents so that the dose guidelines 

expressed in the Appendix I to 10 CFR Part 50 are not exceeded
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• provide processing equipment and capacity sufficient to maintain radioactivity in liquid 

effluents within the applicable flexibility provisions of Appendix I to 10 CFR Part 50 

during anticipated operational occurrences

2.3.3.44.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the waste processing liquid system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the 

applicant adequately identified the waste processing liquid system mechanical components 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.45 Waste Processing Liquid Drains System

2.3.3.45.1 Summary of Technical Information in the Application

This system includes tanks, sumps, pumps, piping and instrumentation, as required, to collect, 

segregate and control liquid leakage within the radioactively contaminated portions of the plant.

The equipment and floor drainage system (waste processing liquid drains system) is operable 

during all normal modes of operation. The entire system is classified as NNS, non-seismic 

Category I, non-Class 1E, with the exception of piping runs through the containment walls and 

the isolation valves for these penetrations.

The system is designed to handle all anticipated normal leakage volumes from component and 

liquid drain sources within the area covered by the equipment and floor drainage system.

The system is also designed to handle all anticipated abnormal leakage from sources such as 

malfunctioning pump seals, leaky flange gaskets, and blown valve stem packing. The maximum 

expected flow rate into any one sump from all expected abnormal sources is less than the 

50 gpm capacity of the sumps in areas containing safety class equipment. Abnormal flows from 

pipe breaks are not included in the system design.

2.3.3.45.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.45, UFSAR Sections 9.3.3 and 9.3.2.2, UFSAR 

Tables 6.2-83 and 7.5-1, and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The 

staff’s review identified areas in which additional information was required 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 2.3.3.45-01, dated January 5, 2011, the staff noted on LRA drawing 

PID-1-WLD-LR20218, at location G-6, that the applicant labels license renewal note 2, which 

states “[c]omponents have an internal environment of air/gas so they have no license 

renewal-intended function and are not in scope.” The portion of the 2 in. piping excluded from 

scope of license renewal is directly connected to the in-scope reactor coolant drain tank and 

continues up to the relief valve V-83. LRA Table 3.3.2-45 does not list an internal environment 

of air or gas for tanks. The staff is concerned with conditions where the relief valves actuate 

and the piping is fluid-filled during a DBE. The applicant was asked to do one of the following:
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• include the piping attached to the reactor coolant drain tank within the scope of license 

renewal and subject to AMR in accordance with 10 CFR 54.4(a)(2)

• provide the results of an evaluation that demonstrates the failure of this piping, while 

fluid-filled during a DBE, will not prevent the satisfactory accomplishment of any 

functions identified in 10 CFR 54.4(a)(1)

In its response dated February 3, 2011, the applicant stated that the 2 in. piping attached to the 

reactor coolant drain tank is excluded from the scope of license renewal since it contains air or 

gas during normal operation and would under extremely rare conditions contain drainage from 

the valve steam leak-off lines. The applicant stated that its assessment of the reactor coolant 

drain tank is consistent with its scoping methodology found in LRA Section 2.1.2.2.3, which 

states that nonsafety-related components containing air or gas are excluded from scope of 

license renewal with the exception of portions that are directly attached to safety-related 

components and were required for structural support. For additional justification for excluding 

the drain tank, the applicant referenced NUREG-1800, Section A.1 (BTP RLSP-1), which states 

specific aging effects from abnormal events need not be postulated for license renewal. The 

applicant determined that the internal environment of the 2 in. piping is air-indoor uncontrolled,

and no credible aging effect could degrade the piping. However, during the April 8, 2011,

teleconference between the applicant and staff, the applicant revised its position on excluding 

the 2 in. piping from scope of license renewal. The applicant submitted supplemental 

information to staff, which include the 2 in. piping within the scope of license renewal under 

10 CFR 54.4(a)(2) for spatial interaction.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.45-01 acceptable 

because the applicant revised its position regarding the 2 in. piping to include it within the scope 

of license renewal under 10 CFR 54.4(a)(2) for spatial interaction. Therefore, the staff’s 

concern described in RAI 2.3.3.45-01 is resolved.

In RAI 2.3.3.45-02, dated January 5, 2011, the staff noted on LRA drawing 

PID-1-WLD-LR20218, at location H-5, that the applicant depicts a relief valve tailpipe connected 

to relief valve V83 as not being within scope of license renewal. However, on LRA drawing 

PID-1-WLD-LR20219, at location F-4, the applicant depicts the tailpipe within the scope of 

license renewal under 10 CFR 54.4(a)(2). The applicant was asked to clarify the scoping 

classification for the relief valve tailpipe.

In its response dated February 3, 2011, the applicant initially stated that the relief valve tailpipe 

connected to relief valve V83 is not within the scope of license renewal. The applicant also 

indicated that LRA drawing PID-1-WLD-LR20219 erroneously depicted the relief valve tailpipe 

as being within the scope of license renewal. However, during the April 8, 2011, teleconference 

between the applicant and staff, the applicant revised its position on excluding the relief valve 

tailpipe from the scope of license renewal. The applicant submitted supplemental information to 

the staff by letter dated April 22, 2011, which included the relief valve tailpipes within the scope 

of license renewal under 10 CFR 54.4(a)(2) for spatial interaction.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.45-02 acceptable 

because the applicant revised its position regarding the relief valve tailpipe to include it within 

the scope of license renewal under 10 CFR 54.4(a)(2) for spatial interaction. Therefore, the 

staff’s concern described in RAI 2.3.3.45-02 is resolved.
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2.3.3.45.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the waste processing liquid drains system mechanical components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the mechanical 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:

• Section 2.3.4.1, “Auxiliary Steam (AS) System”

• Section 2.3.4.2, “Auxiliary Steam Condensate (ASC) System”

• Section 2.3.4.3, “Auxiliary Steam Heating (ASH) System”

• Section 2.3.4.4, “Circulating Water (CW) System”

• Section 2.3.4.5, “Condensate (CO) System”

• Section 2.3.4.6, “Feedwater (FW) System”

• Section 2.3.4.7, “Main Steam (MS) System (Includes Main Steam Drain System)”

• Section 2.3.4.8, “Steam Generator Blowdown (SB) System”

The staff’s findings on review of LRA Sections 2.3.4.1–2.3.4.8 are in provided in SER 

Sections 2.3.4.1–2.3.4.8, respectively.

2.3.4.1 Auxiliary Steam System

2.3.4.1.1 Summary of Technical Information in the Application

The auxiliary steam system is comprised of the following equipment:

• two package boilers, each rated at 80,000 pounds (lb) per hour of saturated steam at 

150 psig, complete with forced draft fans, breeching and common stack

• one 170,000 lb per hour de-aerating heater with storage tank

• three motor-driven boiler feed pumps rated at 180 gpm each (one spare)

• triplex fuel oil pumping set (one spare pump)

• one blowdown tank, one fuel oil storage tank, and two skid-mounted chemical feed units

• interconnecting piping

• safety-related primary auxiliary building isolation valves

During plant start-up, excess condensate from auxiliary steam used for turbine gland sealing 

and shell warming is returned to the auxiliary steam condensate system.
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Feedwater from the de-aerator is pumped to the auxiliary boilers and evaporated. Steam is 

piped to building heating units and operating equipment. Building heating system condensate 

and the equipment steam or drains, or both, are added to the main cycle or returned to the 

auxiliary boiler de-aerator.

The boilers are fired by No. 2 fuel oil. Steam atomization is used during normal boiler operation. 

Air is the atomizing medium for startup.

During normal plant operation, a branch line from main steam system lines can supply the 

required steam to the auxiliary steam system. A pressure-reducing valve reduces the main 

steam pressure to that equivalent to the output of the auxiliary boilers. The pressure-reducing 

station is closed during station startup, when the auxiliary boilers furnish the required steam. 

The auxiliary steam primary auxiliary building isolation valves are operable from the main 

control board and close automatically on an HELB signal.

2.3.4.1.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the auxiliary steam system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the auxiliary steam system mechanical components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.4.2 Auxiliary Steam Condensate System

2.3.4.2.1 Summary of Technical Information in the Application

The auxiliary steam condensate system is part of the auxiliary steam system, as described in 

UFSAR Section 10.4.11.

During plant start-up, excess condensate from auxiliary steam—used for turbine gland sealing 

and shell warming—is returned to the auxiliary steam condensate system. During normal 

operation, building heating system condensate and the equipment steam or drains, or both, are 

added to the main cycle or returned to the auxiliary boiler de-aerator. In the event that any of 

the systems being supplied with auxiliary steam become contaminated, the auxiliary condensate 

will, in turn, become contaminated. To prevent the auxiliary boiler from becoming contaminated, 

the unit is equipped with a radiation monitor, which samples the condensate in the condensate 

return line. If the radionuclide concentration exceeds a pre-selected level, the monitor 

automatically terminates the condensate return.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2, UFSAR Section 10.4.11, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. In addition to the continuation issue identified in RAI 2.3-01 

described in Section 2.3.3, the staff’s review identified an area in which additional information 

was required 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 2.3.4.2-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-ASC-LR20908, 

at location E-12, that the applicant depicts piping inside heat exchanger HWS-E-132 within the 
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scope of license renewal under 10 CFR 54.4(a)(2). However, on LRA drawing 

PID-1-HW-LR20056, at location F-11, the applicant depicts the same piping for the heat 

exchanger HWS-E-132 not within scope of license renewal. The applicant was asked to clarify 

the scoping of the piping inside the heat exchanger HWS-E-132.

In its response dated February 3, 2011, the applicant stated the piping (or tubing) inside the 

heat exchanger HWS-E-132 is excluded from within the scope of license renewal. The 

applicant also indicated that the LRA drawing erroneously depicted the tubing as being within 

scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-01 acceptable 

because the applicant clarified that the piping inside the heat exchanger is not in the scope of 

license renewal. The staff confirmed this to be acceptable by reviewing LRA Section 2.3.3.19, 

“Hot Water Heating System,” and confirming that the heat exchanger is in-scope for pressure 

boundary and the tubing inside the heat exchanger was not listed in the scope of license 

renewal. Therefore, the staff’s concern described in RAI 2.3.4.2-01 is resolved.

2.3.4.2.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the auxiliary steam condensate system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the mechanical components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.4.3 Auxiliary Steam Heating System

2.3.4.3.1 Summary of Technical Information in the Application

The auxiliary steam heating system provides low–pressure, saturated steam to various plant 

equipment and buildings for heating purposes.

2.3.4.3.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the auxiliary steam heating system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the 

applicant adequately identified the auxiliary steam heating system mechanical components 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.4 Circulating Water System

2.3.4.4.1 Summary of Technical Information in the Application

The circulating water system provides cooling water to the main condensers to remove the heat 

rejected by the turbine cycle and auxiliary systems. The design of the system also includes the 

capability for furnishing cooling water to the service water system, and returning it to the 

circulating water discharge flow. Cooling and lubricating water for the circulating water pumps 
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and motors is provided by the discharge of the operating pumps. On the startup of the first 

circulating water pump, the service water screen wash system pump provides the water source.

2.3.4.4.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and license renewal boundary drawings the staff concluded that the applicant 

appropriately identified the circulating water system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concluded that the applicant 

adequately identified the circulating water system mechanical components subject to an AMR, 

as required by 10 CFR 54.21(a)(1).

2.3.4.5 Condensate System

2.3.4.5.1 Summary of Technical Information in the Application

The condensate system, in conjunction with the feedwater system, returns the condensate from 

the turbine condenser hotwells through the regenerative feed heating cycle to the steam 

generators while maintaining the water inventories throughout the cycle.

Three motor-driven, constant-speed, vertical canned-type condensate pumps withdraw 

condensate from the three condenser hotwells. During normal operation, only two pumps will 

be operating, and one will be on standby. Seal and priming water are supplied to the 

condensate pumps from the condensate storage tank or the demineralized water system. The 

condensate pumps discharge into a common header that carries the flow to the steam packing 

exhauster, which condenses the turbine sealing steam and exhausts noncondensibles through 

blowers to the atmosphere. The common condensate header distributes the flow equally to the 

suction side of the two steam generator feed pumps.

Condenser hot well makeup is provided from either the condensate storage tank or the 

demineralized water storage tanks upon receipt of a hotwell low-level signal. The condensate 

storage tank is protected from freezing by a recirculation system, which uses a heat exchanger 

and pump controlled by tank temperature. All condensate system connections to the 

condensate storage tank, which are required for normal system operation, are located above 

the tank level required for emergency plant shutdown. The bottom half of the tank 

(212,000 gal.) is used only for emergency plant shutdown and cooldown by the emergency 

feedwater pumps. The EFW system is evaluated under the feedwater system.

A steam generator startup feed pump provides normal requirements for startup, cooldown, and 

no-load operation. The pump takes suction from the condensate storage tank and discharges 

through a startup heater into the high pressure feedwater heater discharge piping. The startup 

feedwater system is evaluated under the feedwater system. The condensate pumps can also 

be used for startup by using the steam generator feedwater pump bypass piping.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5, UFSAR Sections 6.8.2, 9.2.6, 10.4.7, UFSAR 

Table 7.4-1, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 

identified an area in which additional information was required to complete the review of the 
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applicant’s scoping and screening results. The applicant responded to the staff’s RAI, as 

discussed below.

In RAI 2.3.4.5-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-CO-LR20426, 

at location H-9, that the applicant depicts a floating seal in the condensate storage tank as not 

being within scope of license renewal. However, LRA Table 2.3.4-5 does not list this floating 

seal. The staff’s position is that the floating seal appears to be part of the condensate system 

tank, which is depicted as being within the scope of license renewal for 10 CFR 54.4(a)(1). The 

applicant was asked to justify the exclusion of the floating seal from the scope of license 

renewal and LRA Table 2.3.4-5.

In its response dated February 3, 2011, the applicant stated the floating cover seal was included 

within scope of license renewal under 10 CFR 54.4(a)(2) for providing functional support for the 

condensate storage tank. However, the applicant excluded the floating seal from being subject 

to an AMR due to the floating seal being replaced every six refueling cycles.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.5-01 acceptable 

because the floating seal was included within scope of license renewal under 10 CFR 54.4(a)(2) 

due to its functional support for the condensate storage tank. The staff confirmed that the 

applicant’s justification for exempting the floating seal from an AMR is consistent with 

10 CFR 54.21(a)(1)(ii) due to the floating seal being replaced every six refueling cycles. 

Therefore, the staff’s concern described in RAI 2.3.4.5-01 is resolved.

2.3.4.5.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the condensate system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.4.6 Feedwater System

2.3.4.6.1 Summary of Technical Information in the Application

The feedwater system receives water from the condensate system and a portion of the heater 

drain system (specifically, drains from high pressure heaters No. 6, low pressure heaters No. 5, 

moisture separator reheater shell drains, and moisture separator reheater drains). The 

feedwater is pumped through the final stage of feedwater heaters (high pressure heaters No. 6) 

to the four steam generators.

The four feedwater lines exit the turbine building; two routed east of the containment and two 

routed west, where they enter the east and west main steam and feedwater pipe chases. The 

east and west pipe chases house the feedwater isolation valves, which are located just 

upstream of the containment penetrations and connections to the steam generators. 

Immediately upstream of the feedwater isolation valve is a check valve and a flow measuring 

device. The EFW pump discharge connection to each main feedwater line is located between 

the containment penetration and the feedwater isolation valve.
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An ultrasonic feedwater flow measurement system is installed in the common feedwater header,

just upstream of the feedwater regulating valves. This system is comprised of a 36-in. in-line 

flow measurement spool piece and a local system processor panel. The ultrasonic flow 

measurement system provides high accuracy mass flow, feedwater temperature, and feedwater 

pressure signals to the main plant computer system via a digital communication link. These 

signals are used as inputs to the secondary power calorimetric calculation performed by the 

main plant computer system.

Each steam generator feedwater pump has a recirculation control system, which protects the 

pumps from damage at low loads by ensuring minimum flow. A feed pump gland seal water 

system regulates the flow of condensate from the condensate pump discharge header to the 

feed pump seals. Leak-off from the seals to the seal water receiver tank is returned to the 

condenser using a tank level controller, which operates a control valve in the outlet line from the 

tank to the condenser.

Individual steam turbines drive the steam generator feedwater pumps. The turbine drives are of 

the dual admission type, and each is equipped with two sets of stop and control valves. One set 

regulates high-pressure steam from the main steam system, and the other set regulates 

low-pressure steam extracted from the crossover piping. Gland steam is provided to the 

turbines from the main turbine gland steam supply system. The exhaust steam from the steam 

generator feedwater pump turbine drives is condensed in main condenser shells “A” and “C.”

One steam generator startup feed pump provides normal requirements for startup, cooldown,

and no-load operation. The pump takes suction from the condensate storage tank and 

discharges through a startup heater into the high pressure feedwater heater discharge piping. 

The pump suction may also be aligned to the demineralized water storage tanks as a backup 

water source. Startup feedwater flow may also be directed through both high pressure 

feedwater heaters in series. The startup feedwater system is described in Subsection 10.4.12 

of the UFSAR. The condensate pumps can also be used for startup by using the steam 

generator feedwater pump bypass piping. A sampling system is provided and connected to 

various points in the condensate, feedwater, and heater drains systems (see UFSAR 

Subsection 9.3.2).

Condensate and feedwater chemistry is controlled as described in UFSAR Subsection 10.3.5.

The chemical feed for the condensate and steam generator wet lay up systems is stored in

covered tanks for personnel protection.

EFW System

Heat is removed from the steam generators via the main condensers or the main steam safety 

or steam generator atmospheric relief valves. Steam generator water inventory is maintained 

by water makeup from the EFW system. The system will supply feedwater to the steam 

generators to remove sufficient heat to prevent the over-pressurization of the RCS and to allow 

for eventual system cooldown.

. Upon loss of normal feedwater flow, the reactor is tripped, and the decay and 

sensible heat is transferred to the steam generators by the RCS via the RCPs or by natural 

circulation when the pumps are not operational.

The EFW system is comprised of two full-sized pumps (one motor and one turbine driven) 

whose water source is the condensate storage tank. Suction lines are individually run from the 

condensate storage tank to each pump. A common EFW pump recirculation line discharges 

back to the condensate storage tank. This return line functions for recirculation pump testing 
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and ensures minimum flow to prevent pump damage for any system low-flow operating 

condition. Both pumps feed a common discharge header, which, in turn, supplies the four 

emergency feed lines. The common discharge header includes normally open gate valves 

between each branch connection to provide isolation in the event of a pipe break or for 

maintenance. Each emergency feed line is connected to one of the main feedwater lines 

downstream of the feedwater isolation valve. Each main feedwater line enters the containment 

through a single penetration and feeds a single steam generator.

Additional redundant pumping capability is provided by the startup feed pump in the feedwater 

system.

A dedicated 196,000 gal. of demineralized water is maintained in the lower half of the 

condensate storage tank for the exclusive use of the EFW system.

The branch lines to each steam generator include a manual gate isolation valve, two 

motor-operated flow control valves, a flow venturi, and a flow orifice. The flow control valves are 

normally in the open position when the system is not operating, and they are automatically 

closed during system operation in the event of a pipe break. These valves can be operated 

remotely, as described in UFSAR Subsection 6.8.5, to control steam generator water level. Two 

valves in series are provided for redundancy and are powered from different trains. Each valve 

is also provided with a hand wheel to permit manual operation. The open position of the flow 

control valves for system limiting conditions is set to insure the minimum required flow of 470 

gpm to three steam generators and a minimum total flow of 650 gpm to four steam generators 

with one EFW pump operational.

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6, UFSAR Sections 6.8, 9.3.2, 10.3.5, 10.4.7, 10.4.12,

UFSAR Tables 7.4-1, 7.5-1, and 6.2-83, and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

The staff’s review identified an area in which additional information was required to complete the 

review of the applicant’s scoping and screening results. The staff addressed the applicant’s 

response to RAI 2.3-01 in Section 2.3.3 of this SER. The staff did not identify any other 

additional concerns with the applicant’s scoping and screening of feedwater system 

components for license renewal.

2.3.4.6.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the feedwater system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).
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2.3.4.7 Main Steam System (Includes Main Steam Drain System)

2.3.4.7.1 Summary of Technical Information in the Application

The major function of the main steam system is to transport the steam generated in the four 

steam generators to the turbine generator for conversion to electrical power. Heat transferred 

from the reactor core to the RCS is subsequently transferred across the steam generator 

U-tubes for conversion of secondary feedwater into main steam.

This steam passes through a moisture separator and a flow restrictor as it leaves the steam 

generator and enters its main steam header. The moisture separator improves steam quality, 

while the flow restrictor prevents excessive steam flow in the event of an unisolable steam line 

rupture.

2.3.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.7, UFSAR Section 10.3, UFSAR Tables 6.2-83, 7.4-1, and 

7.5-1, and the license renewal boundary drawings using the evaluation methodology described 

in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review identified an 

area in which additional information was required to complete the review of the applicant’s 

scoping and screening results. The staff addressed the applicant’s response to RAI 2.3-01 in 

Section 2.3.3 of this SER. The staff did not identify any other additional concerns with the 

applicant’s scoping and screening of main steam system components for license renewal.

2.3.4.7.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the main steam system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.4.8 Steam Generator Blowdown System

2.3.4.8.1 Summary of Technical Information in the Application

Each of the four steam generators is provided with a bottom blow down connection on the 

secondary side above the tube sheet. During normal operation, each steam generator 

undergoes continuous blowdown with the blowdown water passing through a containment 

isolation valve, flow meter, and system valves. A small quantity of blowdown is continuously 

drawn off automatically into the sample system through a sample heat exchanger for monitoring 

of the activity in the blowdown. If the activity in the blow down discharge is higher than 

allowable, blowdown is automatically secured. The blowdown liquid then flows through a 

manual control valve, which establishes the blowdown rate. Some of the liquid flashes upon 

passing through the control valve, and two-phase flow then enters the flash tank. There, 

approximately 30 percent of the blowdown flow exits the top of the tank as saturated steam. 

The remaining 70 percent exits the bottom of the tank as saturated water.
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2.3.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.8, UFSAR Section 10.4.8, UFSAR Tables 6.2-83, 7.4-1,

and 7.5-1, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. In addition to the 

continuation issue identified in RAI 2.3-01 described in Section 2.3.3, the staff’s review identified 

an area in which additional information was required 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 2.3.4.8-01, dated January 5, 2011, the staff noted on LRA drawing PID-1-SS-LR20521, 

at location A-6, that the applicant depicts cooler H-376 as being within scope of license renewal 

under 10 CFR 54.4(a)(2). However, the applicant excludes the “vent to atmosphere” piping, 

which is attached to cooler H-376, from the scope of license renewal. The applicant was asked 

to justify its exclusion of the “vent to atmosphere” piping from the scope of license renewal.

In its response dated February 3, 2011, the applicant stated the “vent to atmosphere” piping is 

within scope of license renewal under 10 CFR 54.4(a)(2). The applicant also stated that LRA 

drawing PID-1-SS-LR20521 erroneously depicted the “vent to atmosphere” piping as being 

excluded from scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.8-01 acceptable 

because the “vent to atmosphere” piping was already included within the scope of license 

renewal under 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.4.8-01 is 

resolved.

2.3.4.8.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI responses, and license renewal boundary 

drawings to determine whether the applicant had identified all components within the scope of 

license renewal. In addition, the staff’s review determined whether the applicant had identified 

all components subject to an AMR. On the basis of its review, the staff concludes the applicant 

appropriately identified the steam generator blowdown system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the mechanical components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.4

This section documents the staff’s review of the applicant’s scoping and screening results for 

structures. Specifically, this section discusses the reactor building and other Class I and 

in-scope structures.

Scoping and Screening Results: Structures

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

SCs that meet the scoping criteria and are subject to an AMR.

The staff’s evaluation of the information in the LRA was the same for all structures. The 

objective was to determine if the applicant identified, in accordance with 10 CFR 54.4, 

components and supporting structures for structures that appear to meet the license renewal 
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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 if the applicant 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 if 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 safety-related intended functions, the staff sought to determine if the functions 

are performed with moving parts or a change in configuration or properties or if 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 Buildings, Structures within License Renewal

2.4.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.1, the applicant described the buildings and structures within license renewal 

as being NNS-related, miscellaneous buildings that could prevent satisfactory accomplishment 

of a safety-related 10 CFR 54.4(a)(1) function. In addition, these structures and buildings may 

house equipment for any of the 10 CFR 54.4(a)(3) regulated events. The following structures 

are described in LRA Section 2.4.1.

Discharge Transition Structure. This Non-Seismic Category I structure provides a path to 

discharge cooling water from the condenser through the discharge tunnel and into to the ocean, 

during normal operation. The structure is also aligned to provide water from the discharge 

tunnel to the service water pumphouse and the circulating water pumphouse if necessary.

Fire Pumphouse (including Fire Protection Water Storage Tanks (foundations only), Fire 

Pumphouse Boiler Building, Boiler Fuel Tank (foundation and steel framing only), and two Fuel 

Oil Day Tanks (foundations and steel framing only). The fire pumphouse is a non-seismic 

Category I structure that houses electric and diesel-driven fire pumps and associated controls. 

The two 500,000 gal. fire protection water storage tanks are non-seismic Category I structures. 

The fire pumphouse boiler building and boiler fuel tank are non-seismic Category I structures. 

The purpose of the boiler is to provide heat to the fire pumphouse. In addition, two Fuel oil day 

tanks provide diesel fuel to the two diesel-driven fire pumps.

Intake Transition Structure. This non-seismic Category I structure provides seawater to the 

service water pumphouse and the circulating water pumphouse from the ocean and intake 

tunnel. In addition, it serves as a surge chamber that stabilizes changing water levels.

Non-Essential Switchgear Building. This non-seismic Category I structure houses Appendix R 

emergency lighting needed for operation of safe shutdown equipment and for access and 

egress routes thereto. In addition, it houses and protects the electrical equipment used to 

provide lighting for the plant.
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Revetment. The revetment structures are classified as non-seismic Category I and provide 

flood protection to safety-related structures from a predicted probable maximum hurricane 

(PMH) surge by means of a protective retaining wall, a vertical seawall, and revetment (riprap).

Steam Generator Blowdown Recovery Building

LRA Table 2.4-1 identifies the components subject to an AMR, for the buildings and structures 

within license renewal, by component type and intended function.

. The steam generator blowdown recovery 

building is a non-seismic Category I structure and houses the steam generator blowdown 

recovery system. The loss of function of these systems and components will not affect the 

capability of a safe reactor shutdown.

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 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 has 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 2.4, the staff noted areas in which additional information was 

necessary to complete its review of the applicant’s scoping and screening results. Specifically, 

the staff noted that there were no trash racks, basket strainers, traveling screens, or any other 

debris prevention or removing mechanisms listed as part of the intake transition structure. By 

letter dated November 18, 2010, the staff issued RAI 2.4.1-1, requesting that the applicant verify 

if the aforementioned components are present and within the scope of license renewal of the 

identified structure and, thus, subject to an AMR. In addition, if they are subject to an AMR, the 

staff asked that the applicant identify the applicable aging effects and the AMP related to these 

components.

By letter dated December 3, 2010, the applicant responded to RAI 2.4.1-1 and stated the 

following:

There, are no structural components such as trash racks, basket strainers, 

traveling screens or any other debris prevention/removing mechanisms that are 

part of the Intake Transition Structure.

There is a Chlorination System (CL) Strainer, 1-CL-S-256, which is located in a 

pit, adjacent to the Intake Transition Structure that is in scope for license 

renewal. Being non-metallic and having no reported aging effects, the strainer 

does not require an aging management program.

The Service Water Pumphouse does contain traveling screens. These were 

screened out of License Renewal as being active components, except for the 

covering shrouds, which are in-scope with an (a)(2) intended function of 

protecting safety related equipment from raw water spray. The shrouds are 

fiberglass, with no aging effects, and are not age managed.
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Located in the Primary Auxiliary Building, a basket-type strainer is provided in 

each train of the, Service Water System to prevent shells and mussels, which 

could be carried into these lines, from fouling various heat exchangers. These 

strainers are within the scope of License Renewal and are age managed as part 

of the Open Cycle Cooling Water Aging Management Program.

In reviewing the applicant’s response to RAI 2.4.1-1, the staff found that the applicant 

adequately clarified the location of the trash racks, basket strainers, traveling screens, or any 

other debris prevention or removing mechanisms present. Additionally, for those present and

within the scope of license renewal, an AMP was in place to manage the age effects of the 

component. Based on its review, the staff finds the applicant’s response to RAI 2.4.1-1 

acceptable because it clarified that there are no trash racks, basket strainers, traveling screens,

or any other debris prevention or removing mechanisms in the intake transition structure within 

the scope of license renewal and subject to an AMR. The staff’s concern described in 

RAI 2.4.1-1 is resolved.

By letter dated November 18, 2010, the staff issued RAI 2.4.1-2, requesting that the applicant 

clarify if the following components listed below, which are credited for flood protection per 

UFSAR Section 3.4.1.1, would be required to be included within the scope of license renewal:

• rolling steel door in the fuel storage building (elevation 20 ft 6 in. mean sea level (MSL))

• double doors into the entrance vestibule of the Equipment vault section of the primary 

auxiliary building (elevation 20 ft 8 in. MSL)

For those components that should be included within the scope of license renewal, the staff also 

asked the applicant to detail the applicable aging effects and the appropriate AMP related to the 

component.

By letter dated December 3, 2010, the applicant responded to RAI 2.4.1-2 and stated, in part, 

that “[f]lood protection for the Fuel Storage Building is provided by a curb at elevation 21.5 ft 

MSL located on column 3 behind the rolling steel door...”

The floor of the vestibule into the Equipment Vault section of the Primary Auxiliary Building is 

sloped up 4 inches so that the high point in the floor is at elevation 21 ft MSL.

Both doors are in scope of license renewal for other intended functions other than flood 

protection. The Fuel Storage Building rollup door is included in the generic component Primary 

Structures (PST)-Carbon Steel Door-Fuel Storage Building in LRA Table 3.5.2-5 and the double 

doors into the Equipment Vault are included in the generic component PST-Carbon Steel 

Door-Primary Auxiliary Building in LRA Table 3.5.2-5.

In reviewing the applicant’s response to RAI 2.4.1-2, the staff found that the applicant clarified 

the inclusion of the following components from the scope of license renewal:

• rolling steel door in the fuel storage building (elevation 20 ft 6 in. MSL)

• double doors into the entrance vestibule of the Equipment vault section of the primary 

auxiliary building (elevation 20 ft 8 in. MSL)

Both doors are within the scope of license renewal for intended functions other than flood 

protection, and the applicant adequately described the flood protection mechanisms for the two 

access openings in the exterior wall that are below the design flood level. Based on its review, 
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the staff finds the applicant’s response to RAI 2.4.1-2 acceptable because it clarified that the 

rolling steel door in the fuel storage building and the double doors into the entrance vestibule of 

the equipment vault section of the primary auxiliary building are not credited for flood protection. 

However, they are included in the scope of license renewal for other intended functions. 

Therefore, the staff’s concern described in RAI 2.4.1-2 is resolved.

By letter dated November 18, 2010, the staff issued RAI 2.4.1-3, asking that the applicant 

provide additional information regarding the fire protection water storage tanks. Specifically, the 

staff sought to determine if there was any steel framing that was part of the structural 

arrangement of the tanks, since only the foundation was included in the scope of license 

renewal.

By letter dated December 3, 2010, the applicant responded to RAI 2.4.1-3 and stated that the 

fire protection water storage tanks are bolted to the tanks’ foundation, are free-standing, and 

have no supports.

In reviewing the applicant’s response to RAI 2.4.1-3, the staff found that the applicant clarified 

the structural configuration of the fire protection water storage tanks since they are free-standing 

and have no structural steel framing. Based on its review, the staff finds the applicant’s 

response to RAI 2.4.1-3 acceptable because the structural configuration of the fire protection 

water storage tanks has been included in the scope of license renewal and subsequent AMP. 

The staff’s concern described in RAI 2.4.1-3 is resolved

2.4.1.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, to determine whether the applicant had 

identified all SCs within the scope of license renewal. In addition, the staff’s review determined 

whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the

staff concludes the applicant has adequately identified the buildings and structures SCs within 

the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.4.2 Containment Structures

2.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.2, the applicant described the containment structures as seismic Category I 

structures that enclose and provide physical support and protection to the RCS. The 

containment structures consist of the following structures.

Containment Structure. This reinforced concrete containment structure completely encloses the 

RCS and has the form of a right vertical cylinder with a hemispherical dome and a flat 

foundation mat founded on bedrock. The inside face is lined with a welded carbon steel plate 

that provides a high degree of leak tightness. Containment penetrations are provided in the 

lower portion and consist of a personnel lock, an equipment hatch and personnel lock, a fuel 

transfer tube and piping, electrical, instrumentation, and ventilation penetrations. All 

penetrations are anchored to sleeves embedded in the concrete wall.

Containment Enclosure Building. This reinforced concrete containment enclosure building 

surrounds the containment structure and is designed in a similar configuration as a vertical right 

cylinder with a dome and a ring base. The structure is designed to entrap, filter, and then 
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discharge any leakage from the containment structure. The containment enclosure building 

provides the secondary containment barrier.

Containment Enclosure and Ventilation Area. This reinforced concrete structure is an irregularly 

shaped building that houses ventilation equipment such as fans and filters for the enclosure 

building. It is physically located on the southwest side of the containment.

Containment Internals

LRA Table 2.4-2 identifies the components, subject to an AMR for the containment structures 

within license renewal, by component type and intended function.

. The containment internals consist of intermediate floor slabs, internal 

walls, steel framing, and other support appurtenances. The purpose of the containment internal 

structures is to provide structural support for safety and nonsafety-related equipment, shielding, 

and HELB protection.

2.4.2.2 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all 

SCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant had identified all SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the containment structures SCs within the 

scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.4.3 Fuel Handling and Overhead Cranes

2.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.4.3, the applicant described the fuel handling and overhead cranes as 

consisting of overhead heavy load cranes encompassed by NUREG-0612 and light load cranes 

related to refueling handling systems. These systems are associated with reactor vessel 

assembly, fuel movement, spent fuel cask, and other overhead lifting activities that could have 

an effect on safe shutdown equipment or fuel integrity or both. LRA Table 2.4-3 identifies the 

components subject to an AMR for the fuel handling and overhead cranes by component type 

and intended function.

2.4.3.2 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all 

SCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant had identified all SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the fuel handling and overhead cranes 

SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to 

an AMR, as required by 10 CFR 54.21(a)(1).

2.4.4 Miscellaneous Yard Structures

2.4.4.1 Summary of Technical Information in the Application

In LRA Section 2.4.4, the applicant described the miscellaneous yard structures as non-building 

structures that are exposed to an outdoor environment. These structures include buried vaults, 
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duct banks and manholes, the condensate storage tank enclosure, and SBO structures. They 

are described below in more detail.

Condensate Storage Tank Enclosure. The seismic Category I enclosure consists of a 

cylindrical reinforced concrete wall that surrounds the condensate storage tank. In addition, two 

irregularly shaped rooms—north and south valve rooms—are integral with the circular wall.

Control Room Makeup Air Intake Structures. The seismic Category I air intake structures serve 

as terminals for buried ductwork that provide air for the control rooms during accident 

conditions.

Nonsafety-Related Electrical Duct Banks and Manholes. The reinforced concrete manholes and 

nonsafety-related electrical duct banks house select cables that support fire pump 1-FP-P21.

Safety-Related Electrical Duct Banks and Manholes. The safety-related electrical duct banks 

and manholes are made of reinforced concrete and are isolated by seismic joints.

Service Water Access Vault. The seismic Category I service water access vault is physically 

located underground north of the plant’s cooling towers. This structure provides access to 24 in.

service water piping.

Yard Structures that Support Coping with SBO

LRA Table 2.4-4 identifies the components, subject to an AMR for the miscellaneous yard 

structures within license renewal, by component type and intended function.

. The yard structures are described as providing 

equipment enclosure and structural support that ultimately supports SCs coping with an SBO 

event.

2.4.4.2 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all 

SCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant had identified all SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the miscellaneous yard structures SCs 

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an 

AMR, as required by 10 CFR 54.21(a)(1).

2.4.5 Primary Structures

2.4.5.1 Summary of Technical Information in the Application

In LRA Section 2.4.5, the applicant described the primary structures as being seismic Category I 

structures that are not part of the containment structures or water control structures. They 

consist of the following structures.

Containment Equipment Hatch Missile Shield. This structure consists of a removable, precast,

reinforced concrete wall physically located outside the equipment hatch. The shield protects the 

hatch from tornado-generated missiles.

Control Building and Diesel Generator Building. This structure is separated by a common wall 

in the north-south direction and is made of reinforced concrete founded on fill concrete and rock 
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below grade. The multi-function structure consists of the east portion occupied by the control 

room and the west portion occupied by the diesel generator building.

EFPH including Electrical Cable Tunnels and Penetration Area (Control Building to 

Containment) and Pre-Action Valve Building. The EFPH is physically located adjacent to the 

containment structure and consists of the EFW pump room located above a two-story high 

electrical cable tray tunnel. The pre-action valve room contains the deluge valve for the fire 

protection system and is located on the east side of the EFW building.

Fuel Storage Building. The spent fuel pool and storage facility consists of four main areas—the 

spent fuel pool, the fuel transfer canal, the spent fuel cask loading area, and a decontamination 

area. The spent fuel pool is constructed of reinforced concrete, with all interior surfaces lined 

with stainless steel.

Main Steam and Feedwater Pipe Chases-East and West. The main steam and feedwater pipe 

chase (east and west) are reinforced structures that house and protect the main steam and 

feedwater piping.

Personnel Hatch Area. The personnel hatch area is an irregularly shaped, reinforced concrete 

area that is physically located outside the personnel hatch of the containment and provides 

protection from missiles and illegal entry.

Primary Auxiliary Building including RHR Equipment Vault. The auxiliary building is a reinforced 

concrete structure that is physically located adjacent to the containment structure. The building 

houses most of the auxiliary systems for the RCS. In addition, it houses components essential 

for safe shutdown which could be subject to the effects of an HELB.

Tank Farm (Tunnels)—Including Dikes and Foundations for RWST and Reactor Makeup Water 

Storage Tank. The tank farm areas consist of a reinforced concrete portion and structural steel 

framing portion. The reinforced portion is associated with safety-related systems, and the steel 

portion is used to enclose the area above the tanks and to form the motor control center and 

switchgear room.

Waste Process Building

LRA Table 2.4-5 identifies the components, subject to an AMR for the PSTs within license 

renewal, by component type and intended function.

. The waste process building is a reinforced concrete structure that 

houses the liquid and gas waste processing, boron recovery, and solid waste systems. The 

building contains systems to process radioactive gases, liquids and solids.

2.4.5.2 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all 

SCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant had identified all SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the PSTs SCs 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).
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2.4.6 Supports

2.4.6.1 Summary of Technical Information in the Application

In LRA Section 2.4.6, the applicant described the supports commodity as including ASME and 

non-ASME pipe restraints and supports, jet impingement barriers and shields, pipe whip 

restraints, supports for tube tracks, instrument tubing, miscellaneous mechanical equipment, 

electrical raceways and conduit, HVAC ducts, racks, panels, cabinets, enclosures for electrical 

equipment, junction boxes, platforms, grout under base plates, fasteners and anchorage, 

instruments and battery racks, support base plate pads, etc. Supports provide the connection 

between a system’s equipment or component and a plant structural member, such as a wall, 

beam, or column.

LRA Table 2.4-6 identifies the components, subject to an AMR for the supports commodity 

within license renewal, by component type and intended function.

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 November 18, 2010, the staff issued RAI 2.4.6-1, requesting that the applicant confirm the 

inclusion of the structural bellows in the scope of license renewal, as applicable, and subject to 

an AMR, per 10 CFR 54.21(a)(1)(i), and provide the location in the LRA where they are 

covered. In addition, in the event that the structural bellows were omitted, the staff asked the 

applicant to justify the exclusion from scope of license renewal.

By letter dated December 3, 2010, the applicant responded to RAI 2.4.6-1 and stated, in part, 

the following:

There are three structural bellows at Seabrook Station and all are associated 

with the fuel transfer tube between the fuel storage building and the containment 

structure. All three bellows are in scope of LR. One bellow in the fuel storage 

building is in scope as part of the fuel transfer tube component in the primary 

structures (Table 3.5.2-5) and the other two bellows in the containment structure 

are located with the fuel transfer tube component in the containment structure 

(Table 3.5.2-2).

In reviewing its response to RAI 2.4.6-1, the staff found that the applicant verified the inclusion 

of all structural bellows within the scope of LR. 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 structural bellows at 
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Seabrook have been included in the scope of license renewal and subsequent AMP. The staff’s 

concern described in RAI 2.4.6-1 is resolved.

By letter dated November 18, 2010, the staff issued RAI 2.4.6-2, requesting that the applicant 

clarify a potential discrepancy regarding the neutron absorbent material attached to the spent 

fuel pool racks. Specifically, LRA Section 2.4.6 states that “BORAFLEX utilized in region 2 

racks is not credited with the neutron-absorbing capacity in the criticality analyses and therefore 

will not be managed for reduction of neutron absorbing capacity in the criticality analyses...” 

However, UFSAR Section 9.1.2.1 states that the “Region 2 Spent Fuel Racks contain 

BORAFLEX as a neutron absorbing material to assure a Keff<0.95.” In addition, the staff asked 

that the applicant clearly state the inclusion, or justify the exclusion, of the BORAFLEX from the 

scope of license renewal and subject to an AMR.

By letter dated December 3, 2010, the applicant responded to RAI 2.4.6-2 and stated, in part, 

the following:

An UFSAR change request has been issued to correct the inconsistency. The 

revised UFSAR will state that the BORAFLEX material is conservatively 

assumed to be neutron transparent based on industry experience of BORAFLEX 

degradation.

In reviewing the applicant’s response to RAI 2.4.6-2, the staff found that the applicant is aware 

of the inconsistency between references and has submitted a change request to reflect that 

BORAFLEX material will be conservatively assumed to be neutron transparent.

Based on its review, the staff finds the applicant’s response to RAI 2.4.6-2 acceptable because 

the inconsistency between references has been clarified. Therefore, the staff’s concern 

described in RAI 2.4.6-2 is resolved.

2.4.6.3 Conclusion

The staff reviewed the LRA, UFSAR, and RAI response, to determine whether the applicant had 

identified all SCs within the scope of license renewal. In addition, the staff’s review determined 

whether the applicant had identified all SCs subject to an AMR. On the basis of its review, the 

staff concludes that the applicant has adequately identified the supports SCs within the scope of 

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.4.7 Turbine Building

2.4.7.1 Summary of Technical Information in the Application

In LRA Section 2.4.7, the applicant described the turbine building as a non-seismic Category I 

structure that houses the turbine generator and the associated condensers, pumps, and 

feedwater heaters. In addition, the structure also houses the lube oil, secondary component 

cooling, and service and instrument air systems. The structure does not support any 

safety-related function per 10 CFR 54.4(a)(1). The structure only supports 10 CFR 54.4(a)(2) 

and 10 CFR 54.4(a)(3) functions.

LRA Table 2.4-7 identifies the components, subject to an AMR for the turbine building SCs 

within license renewal, by component type and intended function.
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2.4.7.2 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all 

SCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant had identified all SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the turbine building SCs within the scope 

of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.4.8 Water Control Structures

2.4.8.1 Summary of Technical Information in the Application

In LRA Section 2.4.8, the applicant described the water control structures as those structures 

used for cooling water for the ultimate heat sink. They consist of the structures described 

below.

Service Water Cooling Tower. The service water cooling tower is categorized as a seismic 

Category I structure, and it is composed of a concrete basin, pump rooms, electrical switchgear 

rooms, and mechanical equipment rooms.

Service Water Pumphouse. The service water pumphouse is categorized as a seismic 

Category I structure, and it contains the four service water pumps, which are available for 

normal operation and for post-accident cooldown. The structure is physically adjacent to the 

circulating water pumphouse.

Circulating Water Pumphouse

LRA Table 2.4-8 identifies the components, subject to an AMR for the water control structures 

SCs within license renewal, by component type and intended function.

. The circulating water pumphouse is categorized as a seismic 

Category I structure composed of a forebay and three bays with a circulating pump in each bay. 

Each pump bay has one traveling screen. The three pumps located in each bay supply cooling 

water to the condensers.

2.4.8.2 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all 

SCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant had identified all SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the water control structures SCs within 

the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.5

This section documents the staff’s review of the applicant’s scoping and screening results for 

electrical and I&C systems.

Scoping and Screening Results: Electrical and Instrumentation and Control 

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 
Structures and Components Subject to Aging Management Review

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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 information in the LRA was the same for all electrical and I&C 

systems. The objective was to determine if 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, 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 electrical and I&C 

system to determine if the applicant 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 if 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 if the functions are performed 

with moving parts or a change in configuration or properties or if 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.

2.5.1 Electrical Component 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 plant-wide approach for the review of plant equipment eliminates the 

need to indicate each unique component and its specific location and precludes improper 

exclusion of components from an AMR.

This approach groups all electrical and I&C components in commodity groups and identifies 

those electrical commodity groups that are subject to an AMR by applying the criteria of 

10 CFR 54.21(a)(1). Electrical components in the SBO recovery path are identified based on 

their intended function. Components interfacing with the electrical and I&C components are 

assessed in the appropriate mechanical or structural sections. LRA Table 2.5.4-1 identifies the 

following component and commodity types and their intended functions within the scope of 

license renewal and subject to an AMR:

• non-EQ electrical cables and connections—electrical continuity

• metal enclosed bus—electrical continuity, insulation-electrical

• fuse holders (not part of a larger assembly) metallic clamp—electrical continuity

• cable connections (metallic parts)—electrical continuity
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• SF6 insulated bus, connections and insulators—electrical continuity, insulation-electrical

2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5 and UFSAR Sections 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 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).

GDC 17 of 10 CFR Part 50, Appendix A, requires that electric power from the transmission 

network to the onsite electric distribution system is supplied by two physically independent 

circuits to minimize the likelihood of their simultaneous failure. In addition, the staff noted the 

guidance provided by letter dated April 1, 2002 (Agencywide Document Access Management 

System (ADAMS) Accession No. ML020920464), “Staff Guidance on Scoping of Equipment 

Relied on to meet the Requirements of the Station Blackout Rule (10 CFR 50.63) for License 

Renewal (10 CFR 54.4(a)(3)),” and later incorporated in SRP-LR Section 2.5.2.1.1

For purposes of the license renewal rule, the staff determined that the plant system portion of 

the offsite power system, which 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 SBO 

requirements are maintained over the period of extended license.

The applicant included the complete circuits between the onsite circuits and up to and including 

the switchyard 345 kV power circuit breakers connecting to the generator step up (GSU)

transformer, the unit auxiliary transformers (UATs), and the reserve auxiliary transformers 

(RATs) that are within the scope of license renewal. The circuit from the 345 kV power circuit 

breakers—through the UATs to the diesel-backed 4,160 volt (V) emergency buses—includes 

the SF6 bus from the 345 kV power circuit breakers to the GSU transformer, the isolated phase 

bus from the GSU to the UATs, and the non-segregated bus from the UATs to the 4,160 V 

Buses E5 (EDE-SWG-5) and E6 (EDE-SWG-6). The circuit from the 345 kV power circuit 

breakers—through the RAT to the diesel-backed 4,160 V emergency buses—includes the SF6

bus from the 345 kV power circuit breakers to the RATs and the non-segregated bus from the 

RATs to the 4,160 V Buses E5 (EDE-SWG-5) and E6 (EDE-SWG-6). Consequently, the staff 

concludes that the scoping is consistent with the guidance issued April 1, 2002, and later 

incorporated in SRP-LR Section 2.5.2.1.1.

The applicant did not include cable tie wraps in the commodity groups subject to an AMR 

because, based on a review, the applicant concluded that cable tie wraps would not prevent 

in-scope electrical conductors from performing their intended function. The staff reviewed the 

UFSAR and found that cable tie wraps are not credited in Seabrook’s design basis. Therefore, 
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the staff concludes that the exclusion of cable tie wraps from the commodity groups subject to 

an AMR is acceptable.

2.5.1.3 Conclusion

The staff reviewed the LRA and UFSAR to determine whether the applicant had identified all 

SCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant had identified all SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the electrical and I&C systems 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and those 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.6

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.” The staff finds that the applicant’s scoping and screening 

methodology is consistent with the requirements of 10 CFR 54.21(a)(1) and the staff’s position 

on the treatment of safety-related and nonsafety-related SSCs within the scope of license 

renewal, and the SCs requiring an AMR are consistent with the requirements of 10 CFR 54.4 

and 10 CFR 54.21(a)(1).

Conclusion for Scoping and Screening

On the basis of its review, the staff concluded that the applicant adequately identified those 

SSCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and those 

SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

3-1

SECTION 3

AGING MANAGEMENT REVIEW RESULTS

This section of the safety evaluation report (SER) evaluates aging management programs 

(AMPs) and aging management reviews (AMRs) for Seabrook Station Unit 1 (Seabrook). The 

evaluation is performed by the staff of the U.S. Nuclear Regulatory Commission (NRC) (the 

staff).

In Appendix B of its license renewal application (LRA), NextEra Energy Seabrook, LLC 

(NextEra) (the applicant) described the 42 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

In preparing its LRA, the applicant credited NUREG-1801, Revision 1, “Generic Aging Lessons 

Learned (GALL) Report,” dated September 2005. 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.

Applicant’s Use of the Generic Aging Lessons Learned 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 the following:

• systems, structures, and components (SSCs)

• SC materials

• environments to which the SCs are exposed

• aging effects of the materials and environments

• AMPs credited with managing or monitoring the aging effects

• recommendations for further applicant evaluations of aging management for certain

component types
Aging Management Review Results

3-2

To determine whether the use of the GALL Report would improve the efficiency of LRA review, 

the staff conducted a demonstration of the GALL Report process in order to model the format 

and content of safety evaluations based on it. The results of the demonstration project 

confirmed that the GALL Report process will improve the efficiency and effectiveness of LRA 

review while maintaining the staff’s focus on public health and safety. NUREG-1800, 

Revision 1, “Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants” (SRP-LR), dated September 2005, was prepared based on both the GALL 

Report model and lessons learned from the demonstration project.

The staff‘s review complied with Title 10, Part 54, of the Code of Federal Regulations

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

and the guidance of the SRP-LR and the GALL Report.

In addition to its review of the LRA, the staff conducted onsite audits of selected AMPs to verify 

the applicant’s claims of consistency with the GALL Report during the weeks of 

October 11, 2010, and October 18, 2010, as described in the “AMP Audit Report Regarding the 

Seabrook Station License Renewal Application,” dated March 21, 2011. The onsite audits and 

reviews are designed to maximize efficiency of the staff’s LRA review because the applicant can 

respond to questions, the staff can readily evaluate the applicant’s responses, and the need for 

formal correspondence between the staff and the applicant is reduced.

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. This revised LRA 

format incorporates lessons learned from the staff’s reviews of the previous five LRAs, which 

used a format developed from information gained during a staff-NEI demonstration project 

conducted to evaluate the use of the GALL Report in the LRA review process.

The organization of LRA Chapter 3 parallels that of SRP-LR Chapter 3. LRA Chapter 3 

presents AMR results information in the following table types:

• Table 3.x.1 (Table 1s)—In these tables, “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.

• Table 3.x.2-y (Table 2s)—In these tables, “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 GALL Report tables and the LRA tables are essentially the same. In its LRA, 

the applicant modified the tables in Chapter 3 to provide additional information that would assist 

the staff in its review. In each Table 1, the applicant summarized the portions of the application 

with respect to consistency with the GALL Report. In each Table 2, the applicant identified the 

linkage between the scoping and screening results in Chapter 2 and the AMRs in Chapter 3.

3.0.1.1 Overview of Table 1s 

Each of the Tables 3.x.1 (Table 1s) provides a summary comparison of how the facility aligns 

with the corresponding tables of the GALL Report. These tables are essentially the same as 

Tables 1–6 provided in the GALL Report, Volume 1, except that the “ID” column has been 

replaced by an “Item Number” column, the “Type” column is removed, and the “Related Generic 
Aging Management Review Results

3-3

Item” and “Unique Item” columns have been replaced by a “Discussion” column. The 

“Discussion” column is used by the applicant to provide clarifying and amplifying information. 

The following are examples of information that the applicant placed 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 row is consistent with the corresponding item in the GALL 

Report when the consistency may not be obvious

• discussion of how the item is different from the corresponding item in the GALL Report 

(e.g., when an exception is taken to a GALL Report AMP)

The format of the Table 1s allows the staff to align a specific Table 1 row with the corresponding 

GALL Report table row so that the consistency can be easily checked.

3.0.1.2 Overview of Table 2s 

Each of the Tables 3.x.2-y (Table 2s) provides the detailed results of the AMRs for those 

components identified in LRA Chapter 2 as subject to an AMR. The LRA contains a Table 2 for 

each of the systems or components “y” within a system grouping “x” (e.g., reactor coolant 

systems (RCSs), ESFs, auxiliary systems). For example, the ESFs group (3.2.2-y) contains 

tables specific to the containment vessel spray system, safety injection system, and residual 

heat removal (RHR) system. Each Table 2 consists of the following columns: 

• Component Type—The first column identifies the component types, commodity groups, 

structural members, or subcomponents from LRA Chapter 2 that are subject to an AMR. 

The component types are listed in alphabetical order.

• Intended Function—The second column contains the license renewal intended functions 

for the listed component types. Definitions of intended functions are contained in LRA 

Table 2.0-1.

• Material—The third column lists the particular materials of construction for the 

component type.

• Environment—The fourth column lists the environment to which the component types 

are exposed. Internal and external service environments are indicated, and a list of 

these environments is provided in LRA Table 3.0-1.

• Aging Effect Requiring Management (AERM)—The fifth column lists aging effects and 

AERMs. As part of the AMR process, the applicant determined any AERMs for each 

combination of material and environment.

• AMPs—The sixth column lists the AMPs that the applicant used to manage the identified 

aging effects.

• GALL Report Volume 2 Line Item—The seventh column lists the GALL Report item(s) 

that the applicant identified as corresponding to the AMR results in the LRA. The 

applicant compared each combination of component type, material, environment, AERM, 

and AMP in LRA Table 2 to the items in the GALL Report. If there were no 

corresponding items in the GALL Report, the applicant indicated "None" in the column. 
Aging Management Review Results

3-4

In this way, the applicant identified the AMR results in the LRA tables that corresponded 

to the items in the GALL Report tables.

• Table 1 Item—The eighth column lists the corresponding summary item number from 

Table 1. If the applicant identified AMR results in Table 2 that are consistent with the 

GALL Report, then the associated Table 3.x.1 line summary item number should be 

listed in Table 2. If there is no corresponding item in the GALL Report, then the eighth 

column indicates "None." That way, the information from the two tables can be 

correlated.

• Notes—The ninth column lists the corresponding notes that the applicant used to identify 

how the information in Table 2 aligns with the information in the GALL Report. The 

notes identified by letters were developed by an NEI working group to be used in LRAs. 

Any plant-specific notes are identified by a number and provide additional information 

concerning the consistency of the item with the GALL Report or other clarifying 

information.

3.0.2 Staff’s Review Process 

The staff conducted the following types of evaluations of the AMRs and AMPs:

• For items that the applicant stated were consistent with the GALL Report, the staff 

conducted either an audit or a technical review to determine consistency.

• For items that the applicant stated were 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 either an 

audit or 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 deviation from or 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 

prior to 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.

• 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 if 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.
Aging Management Review Results

3-5

3.0.2.1 Review of Aging Management Programs 

For AMPs for which the applicant claimed consistency with the GALL Report AMPs, the staff 

conducted either an audit or a technical review to verify the claim. For each AMP with one or 

more deviations, the staff evaluated each deviation to determine if the deviation was acceptable 

and if 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 program elements defined in 

SRP-LR Appendix A:

• Scope of the Program—Scope of the program should include the specific SCs subject to 

an AMR for license renewal.

• Preventive Actions—Preventive actions should prevent or mitigate aging degradation.

• Parameters Monitored or Inspected—Parameters monitored or inspected should be 

linked to the degradation of the particular SC’s intended function(s).

• Detection of Aging Effects—Detection of aging effects should occur before there is a 

loss of SC’s 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 and one-time inspections to ensure timely detection of aging effects.

• Monitoring and Trending—Monitoring and trending should provide predictability of the 

extent of degradation as well as timely corrective or mitigative actions.

• Acceptance Criteria—Acceptance criteria, against which the need for corrective action 

will be evaluated, should ensure that the SC’s intended function(s) are maintained under 

all CLB design conditions during the period of extended operation.

• Corrective Actions—Corrective actions, including root cause determination and 

prevention of recurrence, should be timely.

• Confirmation Process—Confirmation process should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective.

• Administrative Controls—Administrative controls should provide for a formal review and 

approval process.

• 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’s intended function(s) will be maintained during the period of 

extended operation.

Details of the staff’s audit evaluation of program elements one through six and ten are 

documented in the AMP audit report and are summarized 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 3.0.5.
Aging Management Review Results

3-6

3.0.2.2 Review of Aging Management Review 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. Item numbers in the seventh column of the LRA, “NUREG-1801 Vol. 2 

Item,” correlate to an AMR combination as identified in the GALL Report. The staff also 

conducted onsite audits to verify these correlations. A "None" in the seventh column 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 with the report and for which it does not recommend further evaluation, the staff’s 

audit and review determined if 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–E, indicating how 

the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these items to verify consistency with the GALL Report and validity of the AMR 

for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff audited these items to verify consistency with the GALL Report and confirmed

that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. 

The staff also determined if the applicant’s AMP was consistent with the GALL Report AMP and 

if the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from the component 

identified in 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 if the AMR 

item of the different component was applicable to the component under review and if the AMR 

was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from the component 

identified in the GALL Report, is consistent with the GALL Report for material, environment, and 

aging effect. In addition, the AMP takes some exceptions to the 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 the GALL Report AMPs have been reviewed and accepted. 

The staff also determined if the applicant’s AMP was consistent with the GALL Report AMP and 

if the AMR was valid for the site-specific conditions.
Aging Management Review Results

3-7

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 if the credited AMP would 

manage the aging effect consistently with the GALL Report AMP and if the AMR was valid for 

the site-specific conditions.

3.0.2.3 Updated Final Safety Analysis Report 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 

staff also conducted detailed discussions and interviews with the applicant’s license renewal 

project personnel and others with technical expertise relevant to aging management.

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.

Unless otherwise stated, the staff compared elements one through six of the applicant’s 

program to the corresponding elements of GALL Report and found the elements are bounded. 

For program elements inconsistent with the corresponding element of GALL Report, the staff 

determined the need for additional clarification, which resulted in the issuance of a request for 

additional information (RAI).

3.0.3 Aging Management Programs 

SER Table 3.0-1 presents the AMPs credited by the applicant and described in LRA 

Appendix B. The table also indicates the systems or structures, which credit the AMPs and the 

GALL Report AMP, with which the applicant claimed consistency and shows the section of this 

SER in which the staff’s evaluation of the program is documented.

Table 3.0-1. Aging Management Programs

AMP

(LRA section)

LRA 

section(s)

New or 

existing 

AMP

GALL Report 

comparison GALL Report AMPs Staff’s SER section

ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program

A.2.1.1

B.2.1.1

Existing Consistent XI.M1, “ASME Section XI

Inservice Inspection, 

Subsection IWB, IWC, and 

IWD”

3.0.3.1.1

Water Chemistry 

Program

A.2.1.2

B.2.1.2

Existing Consistent XI.M2, “Water Chemistry 

Program”

3.0.3.1.2
Aging Management Review Results

3-8

AMP

(LRA section)

LRA 

section(s)

New or 

existing 

AMP

GALL Report 

comparison GALL Report AMPs Staff’s SER section

Reactor Head 

Closure Studs 

Program

A.2.1.3

B.2.1.3

Existing Consistent with 

exception

XI.M3, “Reactor Head 

Closure Studs Program” 

3.0.3.2.1

Boric Acid Corrosion 

Program

A.2.1.4

B.2.1.4

Existing Consistent XI.M10, “Boric Acid 

Corrosion”

3.0.3.1.3

Nickel-Alloy 

Penetration Nozzles 

Welded to the Upper 

Reactor Vessel 

Closure Heads of 

Pressurized Water 

Reactors Program

A.2.1.5

B.2.1.5

Existing Consistent XI.M11A, “Nickel-Alloy 

Penetration Nozzles 

Welded to the Upper 

Reactor Vessel Closure 

Heads of Pressurized 

Water Reactors Program”

3.0.3.1.4

Fuse Holders 

Program

A.2.1.36

B.2.1.36

New Consistent XI.E5, “Fuse Holders 

Program”

3.0.3.1.5

Flow-Accelerated 

Corrosion Program

A.2.1.8

B.2.1.8

Existing Consistent XI.M17, “Flow-Accelerated 

Corrosion”

3.0.3.1.6

Bolting Integrity 

Program

A.2.1.9

B.2.1.9

Existing Consistent XI.M18, “Bolting Integrity” 3.0.3.1.7

Steam Generator 

Tube Integrity

Program

A.2.1.10

B.2.1.10

Existing Consistent with 

exception

XI.M19, “Steam Generator 

Tube Integrity”

3.0.3.2.2

Open-Cycle Cooling 

Water System 

Program

A.2.1.11

B.2.1.11

Existing Consistent with 

exception 

XI.M20, “Open-Cycle 

Cooling Water System 

Program”

3.0.3.2.3

Closed-Cycle Cooling 

Water System 

Program

A.2.1.12

B.2.1.12

Existing Consistent with 

exceptions and 

enhancements

XI.M21, “Closed-Cycle 

Cooling Water System 

Program”

3.0.3.2.4

Inspection of 

Overhead Heavy 

Load and Light Load 

Handling Systems 

Program

A.2.1.13

B.2.1.13

Existing Consistent with 

enhancements

XI.M23, “Inspection of 

Overhead Heavy Load 

and Light Load Handling 

Systems Program”

3.0.3.2.5

Compressed Air 

Monitoring Program

A.2.1.14

B.2.1.14

Existing Consistent with 

enhancement

XI.M24, “Compressed Air 

Monitoring”

3.0.3.2.6

Fire Protection 

Program

A.2.1.15

B.2.1.15

Existing Consistent with 

enhancements

XI.M26, “Fire Protection 

Program”

3.0.3.2.7

Fire Water System 

Program

A.2.1.16

B.2.1.16

Existing Consistent with 

enhancements

XI.M27, “Fire Water 

System Program”

3.0.3.2.8

Aboveground Steel 

Tanks Program

A.2.1.17

B.2.1.17

Existing Consistent with 

enhancements

XI.M29, “Aboveground 

Steel Tanks”

3.0.3.2.9

Fuel Oil Chemistry 

Program

A.2.1.18

B.2.1.18

Existing Consistent with 

exceptions and 

enhancements

XI.M30, “Fuel Oil 

Chemistry Program”

3.0.3.2.10

RV Surveillance 

Program

A.2.1.19

B.2.1.19

Existing Consistent with 

enhancements

XI.M31, “Reactor Vessel 

Surveillance Program”

3.0.3.2.11
Aging Management Review Results

3-9

AMP

(LRA section)

LRA 

section(s)

New or 

existing 

AMP

GALL Report 

comparison GALL Report AMPs Staff’s SER section

One-Time Inspection 

Program

A.2.1.20

B.2.1.20

New Consistent XI.M32, “One-Time 

Inspection”

3.0.3.1.8

Selective Leaching of 

Materials Program

A.2.1.21

B.2.1.21

New Consistent with 

exception

XI.M33, “Selective 

Leaching of Materials 

Program”

3.0.3.2.12

Buried Piping and 

Tanks Inspection 

Program

A.2.1.22

B.2.1.22

New Plant-specific None 3.0.3.3.1

One-Time Inspection 

of ASME Code 

Class 1 Small-Bore 

Piping Program

A.2.1.23

B.2.1.23

New Consistent with 

exception

XI.M35, “One-Time 

Inspection of ASME Code 

Class 1 Small-Bore Piping 

Program”

3.0.3.2.13

External Surfaces 

Monitoring Program

A.2.1.24

B.2.1.24

Existing Consistent with 

exceptions and 

enhancement

XI.M36, “External 

Surfaces Monitoring 

Program”

3.0.3.2.14

Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components Program

A.2.1.25

B.2.1.25

New Consistent with 

exceptions

XI.M38, “Inspection of 

Internal Surfaces in 

Miscellaneous Piping and 

Ducting Components 

Program”

3.0.3.2.15

Lubricating Oil 

Analysis Program

A.2.1.26

B.2.1.26

Existing Consistent with 

exception and

enhancements

XI.M39, “Lubricating Oil 

Analysis Program”

3.0.3.2.16

ASME Code

Section XI, 

Subsection IWE 

Program

A.2.1.27

B.2.1.27

Existing Consistent XI.S1, “ASME Section XI, 

Subsection IWE Program”

3.0.3.1.9

ASME Code

Section XI, 

Subsection IWL 

Program

A.2.1.28

B.2.1.28

Existing Consistent with 

enhancements

XI.S2, “ASME Section XI, 

Subsection IWL Program”

3.0.3.2.17

ASME Code

Section XI, 

Subsection IWF 

Program

A.2.1.29

B.2.1.29

Existing Consistent XI.S3, “ASME Section XI, 

Subsection IWF Program”

3.0.3.1.10

10 CFR Part 50, 

Appendix J Program

A.2.1.30

B.2.1.30

Existing Consistent XI.S4, “10 CFR Part 50, 

Appendix J Program”

3.0.3.1.11

Structures Monitoring 

Program

A.2.1.31

B.2.1.31

Existing Consistent with 

enhancements

XI.S5, “Masonry Wall 

Program”

XI.S6,” Structures 

Monitoring Program” 

XI.S7, “RG 1.127, 

Inspection of WaterControl Structures 

Associated with Nuclear 

Power Plants”

3.0.3.2.18
Aging Management Review Results

3-10

AMP

(LRA section)

LRA 

section(s)

New or 

existing 

AMP

GALL Report 

comparison GALL Report AMPs Staff’s SER section

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

environmental 

qualification (EQ)

Requirements 

Program

A.2.1.32

B.2.1.32

New Consistent XI.E1, “Electrical Cables 

and Connections Not 

Subject to 10 CFR 50.49 

Environmental 

Qualification 

Requirements Program”

3.0.3.1.12

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 EQ

Requirements Used 

in Instrumentation 

Circuits Program

A.2.1.33

B.2.1.33

New Consistent XI.E2, “Electrical Cables 

and Connections Not 

Subject to 10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits 

Program”

3.0.3.1.13

Inaccessible Medium 

Voltage Cables Not 

Subject to 

10 CFR 50.49 EQ

Requirements 

Program

A.2.1.34

B.2.1.34

New Consistent with 

enhancement

XI.E3, “Inaccessible 

Medium Voltage Cables 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Program”

3.0.3.2.19

Metal Enclosed Bus 

(MEB) Program

A.2.1.35

B.2.1.35

New Consistent XI.E4, “Metal Enclosed 

Bus Program”

3.0.3.1.14

Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 EQ

Requirements 

Program

A.2.1.37

B.2.1.37

New Consistent XI.E6, “Electrical Cable 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements Program”

3.0.3.1.15

Protective Coating 

Monitoring and 

Maintenance Program

A.2.1.38

B.2.1.38

Existing Consistent with 

enhancements

XI.S8, “Protective Coating 

Monitoring and 

Maintenance Program”

3.0.3.2.20

345 kV sulfur 

hexafluoride (SF6) 

Bus Program

A.2.1.1

B.2.2.1

New Plant-specific None 3.0.3.3.2

Boral Monitoring 

Program

A.2.2.2

B.2.2.2

Existing Plant-specific None 3.0.3.3.3

Nickel-Alloy Nozzles 

and Penetrations 

Program

A.2.2.3

B.2.2.3

Existing Plant-specific None 3.0.3.3.4

Metal Fatigue of 

Reactor Coolant 

Pressure Boundary 

(RCPB) Program

A.2.3.1

B.2.3.1

Existing Consistent with 

enhancements

X.M1, “Metal Fatigue of 

Reactor Coolant Pressure 

Boundary”

3.0.3.2.21

Pressure-Water 

Reactor (PWR)

Vessel Internals

Program

A.2.1.7

B.2.1.7

New Plant-specific None 3.0.3.3.5
Aging Management Review Results

3-11

AMP

(LRA section)

LRA 

section(s)

New or 

existing 

AMP

GALL Report 

comparison GALL Report AMPs Staff’s SER section

EQ of Electric 

Equipment Program

A.2.3.2

B.2.3.2

Existing Consistent X.E1, “Environmental 

Qualification (EQ) of 

Electric Components”

3.0.3.1.16

3.0.3.1 Aging Management Programs Consistent with the Generic Aging Lessons 

Learned Report 

In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL 

Report:

• American Society of Mechanical Engineers (ASME) Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program

• Water Chemistry Program

• Boric Acid Corrosion Program

• Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of 

Pressurized Water Reactors Program

• Fuse Holders Program

• Flow-Accelerated Corrosion Program

• Bolting Integrity Program

• One-Time Inspection Program

• ASME Code Section XI, Subsection IWE Program

• ASME Code Section XI, Subsection IWF Program

• 10 CFR Part 50, Appendix J Program

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification (EQ) Requirements Program

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used 

in Instrumentation Circuits Program

• Metal Enclosed Bus (MEB) Program

• Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program

• EQ of Electrical Components Program

3.0.3.1.1 ASME Code Section XI Inservice Inspection, Subsection IWB, IWC, and IWD

Program

Summary of Technical Information in the Application. LRA Section B.2.1.1 describes the 

existing ASME Code Section XI Inservice Inspection, Subsection IWB, IWC, and IWD Program, 

as consistent with GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, 

Subsection IWB, IWC, and IWD.” The applicant stated that this program manages the aging 

effects of cracking due to cyclic, thermal, or mechanical loading; stress corrosion; loss of 

fracture toughness due to thermal embrittlement; and loss of material due to pitting, crevice 
Aging Management Review Results

3-12

corrosion, or wear. The applicant also stated that this program manages aging degradation in 

ASME Code Classes 1, 2, and 3 piping and components within the scope of license renewal. 

The applicant further stated that the program includes periodic visual inspection, surface or

volumetric examination or both for components identified in ASME Code Section XI, “Rules for 

Inservice Inspection of Nuclear Power Plant Components,” or commitments that require an 

augmentation of inservice inspection (ISI). The applicant also stated that the program will 

provide the requirements for ISI, repair, and replacement of all ASME Code Classes 1, 2, and 3 

components. The applicant further stated that the program consists of condition monitoring 

activities that will detect degradation of components prior to the loss of intended function.

Staff Evaluation

The staff compared elements one through six 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, with the exception of the “detection of aging effects” program element. For 

this element, the staff determined the need for additional clarification, which resulted in the 

issuance of a request for additional information (RAI).

. 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.

GALL Report AMP XI.M1 recommends that Class 1 component inspections include ASME Code

Section XI examination Categories B–F and B–J. During the audit, the staff found that the 

applicant is currently including applicable portions of the Categories B–F and B–J in its Risk 

Informed Inservice Inspection Program. The staff noted that the approval of the risk-informed 

methodology cannot be assumed for the subsequent 10-year ISI intervals because the staff’s 

approval of an alternative program or relief request typically does not extend beyond the current 

10-year interval for which the alternative was proposed. An applicant must submit relief 

requests in accordance with 10 CFR 50.55a(a)(3) for use in subsequent 10-year ISI intervals 

during the period of extended operation. By letter dated December 14, 2010, the staff issued 

RAI B.2.1.1-1 requesting that the applicant clarify how the inspection of Categories B-F and B-J 

will be implemented during the period of extended operation.

In its response dated January 13, 2010, the applicant stated that this program has been revised 

to state that Risk Informed ISI is implemented as an alternative to Categories B-F and B-J, as 

approved by the NRC, for each individual ISI interval. The applicant also stated that if the Risk 

Informed ISI Program is not approved during the period of extended operation, it will follow the 

applicable requirements of ASME Code Section XI, Subsection IWB.

Based on its review, the staff finds the applicant’s response to RAI B.2.1.1-1 acceptable 

because the applicant modified its ASME Code Section XI ISI, Subsection IWB, IWC, and IWD 

Program. This modification indicated that, if the Risk Informed ISI is not approved for any of the 

inspection intervals during the period of extended operation, the applicant will instead use the 

requirements in the ASME Code Section XI, consistent with the recommendations of GALL 

Report AMP XI.M1. The staff’s concern described in RAI B.2.1.1-1 is resolved.

Based on its audit and review of the applicant’s response to RAI B.2.1.1-1, the staff finds that 

elements one through six of the applicant’s ASME Code Section XI ISI, Subsection IWB, IWC, 

and IWD Program are consistent with the corresponding program elements of GALL Report 

AMP XI.M1 and, therefore, are acceptable.
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Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff also conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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.

. LRA Section B.2.1.1 summarizes operating experience related to the 

ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program. In March 2008, the 

applicant stated that, during a routine visual inspection, excessive dry boric acid accumulation 

on a containment building spray system valve gland leak-off plug was identified. The applicant 

stated that the gland leak-off plug was tightened, and the leakage was stopped. The applicant 

further stated that, in September 2006, while performing a VT-2 visual examination, the 

inspector identified a packing leak from a main steam valve with the emergency feedwater 

steam supply header pressurized to the main steam header pressure. The applicant stated that 

it adjusted the packing to stop the leak. The applicant stated that these examples demonstrate 

that the VT-2 inspections have been effective in identifying degraded conditions.

Based on its audit and review of the application, the staff finds that the operating experience 

related to the applicant’s program demonstrates that it can adequately manage the detrimental 

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. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.1.1 provides the UFSAR supplement for the ASME 

Code Section XI ISI, Subsection IWB, IWC, and IWD 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 3.1-2. The staff determined

that the information in the UFSAR supplement is an adequate summary description of the 

program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.1.2 Water Chemistry Program

. On the basis of its review of the applicant’s ASME Code Section XI ISI, 

Subsection IWB, IWC, and IWD Program, the staff finds all program elements consistent with 

the GALL Report. The staff concludes that the applicant 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).

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 applicant stated that its Water Chemistry Program manages aging effects of 

cracking, loss of material, and reduction of heat transfer. The applicant further stated that the 

primary scope of the program is the RCS and related auxiliary systems. The applicant also 

stated that the program is used to control water chemistry for impurities. The applicant stated 

that the chemistry parameters include chlorides, fluorides, dissolved oxygen, and sulfate 
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concentrations. The applicant stated that it bases its monitoring and control on industry 

guidelines such as Electrical Power Research Institute's (EPRI) “Pressurized Water Reactor 

Primary Water Chemistry Guidelines—Revision 6,” for primary water chemistry and 

“Pressurized Water Reactor Secondary Water Chemistry Guidelines—Revision 7,” for 

secondary water chemistry.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M2. 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.M2, with the exception of the “monitoring and trending” program element. For 

this element, the staff determined the need for additional clarification, which resulted in the 

issuance of an RAI.

. 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.

GALL Report AMP XI.M2 states that whenever corrective actions are taken to address an 

abnormal chemistry condition, increased sampling is used to verify the effectiveness of these 

actions. However, during its audit, the staff reviewed the applicant’s chemistry guidelines and 

could not identify any statements that indicated under abnormal chemistry conditions the 

sampling frequency should be increased. By letter dated November 18, 2010, the staff issued 

RAI B.2.1.2-1 requesting that the applicant describe how the Water Chemistry Program will 

verify the effectiveness of corrective actions when an abnormal chemistry conditions occurs.

In its response dated February 18, 2011, the applicant committed (Commitment No. 62) to 

revise the chemistry program documents to include the statement that sampling frequencies are 

increased, as appropriate, when chemistry action levels are exceeded. The staff finds the 

applicant’s response acceptable because it committed to include increased sampling 

frequencies when chemistry action levels are exceeded, which is consistent with GALL Report 

AMP XI.M2. The staff’s concern described in RAI B.2.1.2-1 is resolved.

Based on its audit and review of the applicant’s response to RAI B.2.1.2-1, the staff finds that 

elements one through six of the applicant’s Water Chemistry Program are consistent with the 

corresponding program elements of GALL Report AMP XI.M2 and, therefore, are acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

. LRA Section B.2.1.2 summarizes operating experience related to the 

Water Chemistry Program. The applicant stated that in December 2001, the condensate 

storage tank (CST) oxygen levels increased above 75 parts per billion (ppb). The applicant 

stated that it took corrective actions by monitoring oxygen concentrations at various points in the 

condensate and demineralized water system. The applicant stated that the oxygen ingress was 

caused by the air in-leakage from the condensate storage pump. The applicant stated it 

repaired the pump, and the CST returned to within the Water Chemistry Program specifications. 

The applicant also indicated that, in the fall of 2003, the steam generator sludge analysis results 

indicated that low or less than detectable concentration of contaminants and sulfur were 

detected by bulk deposit analysis. The applicant stated that this was an example of the 

effectiveness of the secondary chemistry control.
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information to determine if the applicant adequately incorporated and evaluated operating 

experience related to this program. During its review, the staff identified operating experience,

which could indicate that the applicant’s program may not be effective in adequately managing 

aging effects during the period of extended operation. The staff determined the need for 

additional clarification, which resulted in the issuance of an RAI.

In LRA Section B.2.1.2, the applicant stated that it addressed operating experience related to 

water chemistry. However, the staff found that the applicant had a recurring condition with the 

CST where the specific conductivity is high and out of specification. By letter dated 

November 18, 2010, the staff issued RAI B.2.1.2-2 requesting that the applicant provide 

additional information to explain if the CST conductivity excursions were evaluated for similar 

root causes. If the root cause is the same for the three instances referenced previously, the 

applicant was asked to provide additional information on what steps have been taken to reduce 

the occurrence of any future CST conductivity excursions.

In its response dated December 17, 2010, the applicant stated that the high specific conductivity 

in the CST could have been due to either recirculation flows from the startup feed pump and 

emergency feedwater pumps or air ingress past the CST floating lid seal. The applicant stated 

that when the high specific conductivity started, it immediately sampled the CST to determine if 

any leakage from the auxiliary steam side into the CST had occurred; however, no leakage was 

found. The applicant stated that the tank was then fed and bled to reduce the high specific 

conductivity to within acceptable limits. The applicant further stated that during the April 2008 

refueling outage, it replaced the faulty floating lid seal, and since this time, the specific 

conductivity has remained below the 0.1 siemens (S)/cm limit. An additional step for 

conductivity control has been the continued monitoring and replacement of the CST float seal 

when necessary and the supply of condenser hotwell makeup from the demineralized water 

storage tank instead of the CST. Based on its review, the staff finds the applicant’s response to 

RAI B.2.1.2-2 acceptable because the applicant indicated how this program brought the water 

chemistry excursions back within limits; determined that the likely root cause for the events was 

due to either recirculation flows from the startup feed pump and emergency feedwater pumps or 

air ingress past the CST floating lid seal that the applicant replaced; and used monitoring, 

replacement, and alternate condenser water sources to minimize the possibility of conductivity 

excursions. The staff’s concern described in RAI B.2.1.2-2 is resolved.

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

RAI B.2.1.2-2, the staff finds that 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. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.1.2 provides the UFSAR supplement for the Water 

Chemistry Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it conforms to the recommended description for this type of program, as described in 

SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, and 3.5-2. The staff determined 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 review of the applicant’s Water Chemistry Program, the staff 

finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant demonstrated that the effects of aging will be adequately managed so that the 
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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).

3.0.3.1.3 Boric Acid Corrosion Program

Summary of Technical Information in the Application. LRA Section B.2.1.4 describes the 

existing Boric Acid Corrosion Program as consistent with GALL Report AMP XI.M10, “Boric Acid 

Corrosion.” The applicant stated that its Boric Acid Corrosion Program manages loss of 

material in mechanical, electrical, and structural components due to leakage from systems 

containing borated water. The applicant further stated that the program implements the 

recommendations of NRC Generic Letter (GL) 88-05, “Boric Acid Corrosion of Carbon Steel 

Reactor Pressure Boundary Components in PWR Plants.” The applicant also stated that the 

program includes visual inspections and early discovery of borated water leaks such that 

mechanical, electrical, and structural components that may be contacted by leaking borated 

water will not be adversely affected or their intended functions impaired. The applicant also 

stated that the program includes both focused inspections and observations by plant personnel 

during normal operational activities and during refueling shutdowns to identify boric acid 

accumulation or leakage.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M10. As discussed in the audit report, the staff confirmed 

that these elements are consistent with the corresponding elements of GALL Report 

AMP XI.M10. Based on its audit, the staff finds that elements one through six of the applicant’s 

Boric Acid Corrosion Program are consistent with the corresponding program elements of GALL 

Report AMP XI.M10 and, therefore, are acceptable.

. 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.

Operating Experience

The applicant provided an account of a self-assessment of its Boric Acid Corrosion Program 

conducted in 2008. The self-assessment compared the Seabrook Boric Acid Corrosion 

Program to the current industry guidance document, [Westinghouse Commercial Atomic Power] 

WCAP-15988-NP, Revision 1, “Generic Guidance for an Effective Boric Acid Inspection 

Program for Pressurized Water Reactors,” which identifies potential enhancements to the Boric 

Acid Corrosion Programs described in the utility responses to GL 88-05. The applicant stated 

that, based on the results of the self-assessment, the program was operationally sound and 

deemed to be in a mode of continuous improvement. The applicant further described the 

self-assessment as a source of identified areas where the program could benefit by being more 

prescriptive in addressing some of the objectives in the Westinghouse Commercial Atomic 

. LRA Section B.2.1.4 summarizes operating experience related to the 

Boric Acid Corrosion Program. The applicant’s operating experience provided details on 

engineering analyses and corrective actions taken in response to detected leakage of boric 

acid. In one recorded instance of operating experience, the applicant described the detection of 

boric acid residue on a chemical and volume control system valve during a plant walkdown. 

The observation led to actions to replace the affected valve packing. In another instance, the 

applicant described the detection of boric acid residue on a RHR system valve. The 

observation led to actions to replace the affected valve gasket.
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Power citation. Condition reports were generated during the course of the self-assessment. 

None of these condition reports identified programmatic failures, and all were directed towards 

future Boric Acid Program enhancements.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated 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 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement. LRA Section A.2.1.4 provides the UFSAR supplement for the Boric Acid 

Corrosion 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 Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, 3.5-2, and 3.6-2. The staff determined that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d).

Conclusion

3.0.3.1.4 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure 

Heads of Pressurized Water Reactors Program

. On the basis of its review of the applicant’s Boric Acid Corrosion Program, the staff 

finds that all program elements are consistent with GALL Report AMP XI.M10. The staff 

concludes that the applicant 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).

Summary of Technical Information in the Application. LRA Section B.2.1.5 describes the 

existing Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads 

of Pressurized Water Reactors Program (hereafter Nickel-Alloy Head Penetration Program) as 

consistent with GALL Report AMP XI.M11A, “Nickel-Alloy Penetration Nozzles Welded to the 

Upper Reactor Vessel Closure Heads of Pressurized Water Reactors.” The applicant stated 

that the program manages the aging effect of cracking due to primary water stress corrosion 

cracking (PWSCC) in the reactor coolant environment. The applicant also stated that the 

program includes all nickel-alloy penetration nozzles welded to the upper reactor vessel head. 

The applicant further stated that cracking was mitigated through the control of water chemistry. 

The applicant finally stated that inspections are performed in accordance with ASME Code 

Case N-729-1, “Alternative Examination Requirements for PWR Reactor Vessel Upper Heads 

With Nozzles Having Pressure-Retaining Partial-Penetration Welds, Section XI, Division 1, 

Supp 4,” as modified in 10 CFR 50.55a(g)(6)(ii)(D), and this code case and regulation meet the 

AMP criteria of being “established to supersede the requirements of Order EA-03-009.”
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Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M11A. The staff confirmed that these elements are 

consistent with the corresponding elements of GALL Report AMP XI.M11A. Based on its 

review, the staff finds that elements one through six of the applicant’s Nickel-Alloy Head 

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

AMP XI.M11A and, therefore, are acceptable.

. 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.

Operating Experience

The staff reviewed operating experience information—which is contained in the application, in 

the GALL Report, and which has occurred since the publication of the GALL Report—to

determine if all the applicable aging effects and industry and plant-specific operating experience 

were considered by the applicant and whether the proposed AMP is sufficient to address this 

operating experience. 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.

. LRA Section B.2.1.5 summarizes operating experience related to the 

Nickel-Alloy Head Penetration Program. In this section, the applicant states that it has 

conducted several inspections of the upper vessel head penetration nozzles and that it has not 

detected any indication of PWSCC. As evidence of the effectiveness of its AMP, the applicant 

provides descriptions of inspection findings for RFOs 8, 9, 10, and 11 (spring 2002, fall 2003,

spring 2005, and fall 2006, respectively). In RFO 8, the applicant performed a robotic bare 

metal exam of the top head. The applicant stated that no evidence of penetration leakage was 

observed. In RFO 9, boric acid was observed on the upper reactor vessel head flange. This 

acid was traced to two leaking canopy seal welds. The applicant states that no boric acid 

corrosion was observed. The leakage was halted through the application of a canopy seal 

clamp assembly. The applicant attributed the leakage to transgranular cracking due to the 

presence of halogens, probably chlorides. Followup inspections conducted during RFO 10 and 

RFO 11 did not identify additional canopy seal weld leaks. In RFO 11, inspections were 

conducted under the first revised NRC Order 03-009. These inspections included a robotic bare 

metal examination from the top of the head and a robotic ultrasonic and surface examination of 

the J-groove welds and penetration tubes from the bottom of the head. The applicant stated 

that no unacceptable indications were discovered.

Based on its review of the application, the GALL Report, and recent industry operating 

experience, the staff finds that operating experience related to the applicant’s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking appropriate preventive actions. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

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 3.1-2. The staff determined that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

. LRA Section A.2.1.5 provides the UFSAR supplement for the Nickel-Alloy 

Head Penetration Program.
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Conclusion

3.0.3.1.5 Fuse Holders Program

. On the basis of its review of the applicant’s Nickel-Alloy Head Penetration 

Program, the staff finds that program elements 1–6 and 10 are consistent with the GALL Report. 

The staff concludes that the applicant 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).

Summary of Technical Information in the Application. LRA Section B.2.1.36 describes the new 

Fuse Holders Program as consistent with GALL Report AMP XI.E5, “Fuse Holders.” The 

applicant stated that the Fuse Holders Program is a new program that will manage the aging 

effects of thermal fatigue in the form of high resistance due to corrosion or oxidation of in-scope 

metallic clamps of fuse holders. The applicant also stated that the program will perform tests on 

the in-scope fuse holders (metallic clamps). The applicant further stated that the test will be a 

proven test such as thermography or contact resistance, which detects thermal fatigue in the 

form of high resistance caused by corrosion or oxidation. The first test will be completed prior to 

entering the period of extended operation and at least once every 10 years thereafter.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.E5. As discussed in the audit report, the staff confirmed that 

each element of the applicant’s program is consistent with the corresponding elements of GALL 

Report AMP XI.E5, with the exception of the “parameters monitored or inspected” program 

element. For this element, the staff determined that additional clarification was required.

. 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 whether they are 

bounded by the conditions for which the GALL Report was evaluated.

GALL Report AMP XI.E5, under the “parameters monitored or inspected” element, states that 

the monitoring includes thermal fatigue in the form of high resistance caused by ohmic heating, 

thermal cycling or electrical transients, mechanical fatigue caused by frequent removal or 

replacement of the fuse or vibration, chemical contamination, corrosion, and oxidation. In the 

Seabrook AMP basis document LRAP-E5 under the same program element, the applicant 

states that the Seabrook program only includes monitoring for the presence of corrosion and 

oxidation. The applicant concluded that the aging effects and mechanisms due to thermal 

fatigue—in the form of high resistance caused by ohmic heating, thermal cycling or electrical 

transients, mechanical fatigue caused by frequent removal or replacement of the fuse or 

vibration—identified by GALL are not applicable to the fuse holders at Seabrook. However, the 

applicant does not provide any justification to substantiate its conclusion. During the LRA onsite 

audit in the week of October 18, 2010, the staff discussed the applicant’s lack of analysis to 

exclude certain aging effects for fuse holder metallic clamps in the scope of license renewal. In 

a letter dated November 15, 2010, the applicant revised the Fuse Holders Program description 

to clarify the exclusion of certain aging mechanisms from the AMP. The staff finds the exclusion 

of certain aging mechanisms acceptable, as documented in SER Section 3.6.2.3.1.

Based on its audit and review of the applicant’s response by letter dated November 15, 2010, 

the staff finds that elements one through six of the applicant’s Fuse Holders Program are 

consistent with the corresponding program elements of GALL Report AMP XI.E5 and, therefore, 

are acceptable.
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Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program. Further, 

the staff performed a search of regulatory operating experience for the past 10-year period 

through March 2010. Databases were searched using various key word searches and then 

reviewed by the technical auditor staff.

. LRA Section B.2.1.36 summarizes operating experience related to the 

Fuse Holders Program. The applicant’s Fuse Holders Program operating experience evaluation 

states that Seabrook routinely performs infrared thermography tests on numerous pieces of 

equipment, including electrical connections, as part of the Preventive Maintenance Program. In 

2008, during a routine infrared thermography test, a fuse holder was found to be 50°F [degrees 

Fahrenheit] hotter than similar fuses in the cabinet. The problem was diagnosed as a defective 

fuse holder. The documentation identified this anomaly as defective equipment and not agerelated. The applicant also stated that Seabrook has performed thermography or resistance 

tests on fuses located in the in-scope fuse panels. All recent tests were reviewed and found to 

be satisfactory. The applicant further stated that, in 2009, members of the Seabrook license 

renewal team performed a walkdown of the in-scope Train “B” fuse cabinets. The walkdown 

assessed the current condition of the in-scope fuse panels. The applicant stated that the 

walkdown results concluded that fuse blocks showed no signs of excessive heating, 

discoloration, corrosion, degradation, or looseness. However, a condition report was written to 

document the presence of a residue on the fuse cabinet mounting bolts. The evaluation of the 

anomaly concluded that residue on the bolts had no effect on the fuse holders.

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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and has resulted in the applicant taking 

corrective action. The staff confirmed that the “operating experience” program element satisfies 

the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

. LRA Section A.2.1.36 provides the UFSAR supplement for the Fuse 

Holders 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 3.6-2. The staff also noted that the applicant committed (Commitment No. 38) to 

implement the new Fuse Holders Program prior to entering the period of extended operation for 

managing aging of applicable components.

Conclusion. On the basis of its review of the applicant’s Fuse Holders Program, the staff finds 

all program elements consistent with the GALL Report. The staff concludes that the applicant 

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 
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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 Flow-Accelerated Corrosion Program

Summary of Technical Information in the Application. LRA Section B.2.1.8 describes the 

existing Flow-Accelerated Corrosion Program as consistent with GALL Report AMP XI.M17, 

“Flow-Accelerated Corrosion.” The applicant stated that this program manages loss of material 

due to wall thinning on the internal surfaces of carbon or low alloy steel components containing 

high-energy fluids. The applicant also stated that the program is based on the guidelines of 

EPRI NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion 

Program," which includes determining susceptible lines, performing baseline and followup 

inspections to confirm predictions, and repairing or replacing components if needed. The 

applicant further stated that the program monitors the effects of flow-accelerated corrosion by 

measuring wall thickness of the components, and the inspection schedule is developed based 

on model prediction, inspection results, and operating experience.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M17. 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.M17, with the exception of the “parameters monitored or inspected” 

program element. For this element, the staff determined the need for additional clarification, 

which resulted in the issuance of an RAI.

. 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.

GALL Report AMP XI.M17 recommends that the program monitors the aging effects of 

flow-accelerated corrosion on the intended function of piping and components by measuring 

wall thickness. LRA Section B.2.1.8 states that valves, orifices, equipment nozzles, and other 

like components, which cannot be inspected completely with ultrasonic testing (UT) techniques 

due to their shape and thickness, are evaluated based on the wear of piping located 

immediately downstream. By letter dated December 14, 2010, the staff issued RAI B.2.1.8-1 

requesting that the applicant provide additional information regarding inspection of the valves, 

orifices, equipment nozzles, and other like components that cannot be inspected completely 

with ultrasonic techniques due to their shape and thickness if significant wear is detected in 

piping located immediately downstream. The staff also asked the applicant to explain how the 

followup inspections will be implemented in the Flow-Accelerated Corrosion Program.

In its response dated January 13, 2011, the applicant stated that its Flow-Accelerated Corrosion 

Program is revised to state that if significant wear is detected in piping immediately downstream 

of a valve, orifice, equipment nozzle or other like component, the component should also be 

examined. The applicant also stated that these components will be examined by ultrasonic, 

radiographic, or visual techniques typically used to inspect valves, orifices, and equipment 

nozzles. The applicant further stated that the followup inspections will be implemented in the 

Flow-Accelerated Corrosion Program, which is consistent with the guidelines delineated in 

NSAC-202L-R2.

The staff finds the applicant’s response acceptable because the applicant’s Flow-Accelerated 

Corrosion Program will implement the guidance of NSAC-202L-R2 to include inspections of 
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valves, orifices, equipment nozzles, and other like components using ultrasonic, radiographic, or 

visual techniques if significant wear is detected in the downstream pipe, which makes the 

applicant’s program consistent with GALL Report AMP XI.M17. The staff’s concern described in 

RAI B.2.1.8-1 is resolved.

Based on its audit and review of the applicant’s response to RAI B.2.1.8-1, the staff finds that 

elements one through six of the applicant’s Flow-Accelerated Corrosion Program are consistent 

with the corresponding program elements of GALL Report AMP XI.M17 and, therefore, are 

acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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.

. LRA Section B.2.1.8 summarizes operating experience related to the 

Flow-Accelerated Corrosion Program. The applicant stated that following the initial 

implementation of CHECWORKS in 1991, a significant portion of the high-pressure extraction 

steam piping was found to be degraded during the first flow-accelerated corrosion inspections. 

As a result, the applicant stated it replaced the piping with a chrome-moly material that is more 

resistant to flow-accelerated corrosion, and no degradation has been noted in the piping after 

replacement. The applicant also stated that during RFO 8 in 2002, it identified one feedwater 

heater with wall thinning in the area below the extraction steam inlet nozzle and took 

appropriate corrective actions to repair the heater using a weld overlay. The applicant further 

stated that the component is being monitored during each RFO, and no additional wall thinning 

has been observed since the repair.

Based on its audit and review of the application, the staff finds that 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement. LRA Section A.2.1.8 provides the UFSAR supplement for the 

Flow-Accelerated Corrosion 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 Tables 3.1-2, 3.2-2, and 3.4-2. The staff determined 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 review of the applicant’s Flow-Accelerated Corrosion Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant 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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3.0.3.1.7 Bolting Integrity Program

Summary of Technical Information in the Application

• NUREG-1339, “Resolution of Generic Safety Issue 29; Bolting Degradation or Failure of 

Bolting in Nuclear Power Plants”

. LRA Section B.2.1.9 describes the 

existing Bolting Integrity Program as consistent with GALL Report AMP XI.M18, “Bolting 

Integrity.” The applicant stated that the program covers bolting within the scope of license 

renewal, including safety-related bolting, bolting for nuclear steam supply system (NSSS)

component supports, bolting for other pressure-retaining components (including 

nonsafety-related bolting), and structural bolting. The applicant also stated that the program 

manages the aging effects of cracking due to stress corrosion cracking, loss of material due to 

general, crevice, pitting, and galvanic corrosion, microbiologically-influenced corrosion, fouling 

and wear, and loss of preload due to thermal effects, gasket creep, and self-loosening 

associated with bolting. The applicant further stated that the program manages the aging 

effects associated with bolting through material selection and testing, bolting assembly and 

pre-load control, operation, maintenance, and the performance of periodic inspections. The 

applicant stated that the program relies on the performance of periodic inspections and credits 

other AMPs for the inspection of bolting such as the ASME Code Section XI, ISI, 

Subsections IWB, IWC, and IWD Program (B.2.1.1). The applicant further stated that the 

program follows the guidelines and recommendations delineated in the following documents:

• EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants” (with the 

exceptions noted in NUREG-1339)

• EPRI TR-104213, “Bolted Joint Maintenance and Application Guide,” for comprehensive 

bolting maintenance

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M18. 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.M18, with the exception of the “parameters monitored or inspected” 

program element. For this element, the staff determined the need for additional clarification, 

which resulted in the issuance of an RAI.

. 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.

GALL Report AMP XI.M18 recommends that safety-related and nonsafety-related bolting be 

visually inspected for leakage under the “parameters monitored or inspected” program element. 

However, during its audit, the staff found that there are in-scope components in the applicant’s 

fire protection system, service water system, and spent fuel pool cooling system that are in 

moist or submerged environments for which visual inspection to detect leakage is not feasible 

due to the environmental conditions. By letter dated November 18, 2010, the staff issued 

RAI B.2.1.9-1 requesting that the applicant provide details on how the in-scope components in 

wet environments will be inspected for leakage.

In its response dated December 17, 2010, the applicant stated that the Bolting Integrity Program 

will be amended to credit the Open-Cycle Cooling Water System Program to manage the aging 

effects of loss of material and loss of preload in submerged in-scope bolting, specifically, the 

service water pump column bolting. The applicant also stated that through inspections 
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implemented by the Open-Cycle Cooling Water System Program, the water pump column 

bolted connections, which are submerged in raw water, will be visually inspected when the 

pumps are removed for maintenance. The applicant further stated that a corrective action 

document has been generated to require inspection for loose or missing in-scope bolts. The 

applicant further stated that the stainless steel bolting in the spent fuel pool cooling system 

externally exposed to borated water was incorrectly shown as being in-scope in LRA 

Table 3.3.2-39. The item was subsequently removed due to the fact that those bolts were 

reassessed to be out of the scope of license renewal since they are associated with an out of 

scope component and provide no pressure boundary function.

The applicant also stated that the Buried Piping and Tanks Inspection Program will be used to 

manage aging effects for bolting used in buried, underground, and inaccessible submerged 

piping. The applicant further stated that in instances where hydrostatic testing, flow testing, or 

fire protection jockey pump monitoring are used in lieu of visual inspections, these methods will 

also be credited to identify leakage caused by loss of preload at bolted connections. The 

applicant also stated that the Buried Piping and Tanks Inspection Program will be used in 

conjunction with the ISI Program and the External Surfaces Monitoring Program, which are cited 

in the LRA as credited for managing the aging effects of bolting.

The staff finds the applicant’s response acceptable because the applicant amended the LRA to 

manage wet or submerged bolting with AMPs that are appropriate for these specific 

environments. These AMPs can manage the loss of material through the implementation of 

periodic and opportunistic visual inspections and loss of preload through hydrostatic testing, 

flow testing, pump monitoring, visual inspections, and other inspections to detect leakage or 

loose and missing bolts. In addition, the staff finds the removal of the two items in LRA 

Table 3.3.2-39 acceptable and determined the bolts are out of the scope of license renewal 

since they are associated with an out of scope component and provide no pressure boundary 

function.. The staff’s concern described in RAI B.2.1.9-1 is resolved.

Based on its audit and review of the applicant’s response to RAI B.2.1.9-1, the staff finds that 

elements one through six of the applicant’s Bolting Integrity Program are consistent with the 

corresponding program elements of GALL Report AMP XI.M18 and, therefore, are acceptable.

Operating Experience

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant and are evaluated in the GALL Report. 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 incorporated and 

evaluated operating experience related to this program. During its review, the staff identified 

industry operating experience for which it determined the need for additional clarification 

resulting in the issuance of an RAI, as discussed below. 

. LRA Section B.2.1.9 summarizes operating experience related to the 

Bolting Integrity Program. The applicant stated that rust was observed on the pipe supporting 

bolts for the RHR equipment vault, an engineering evaluation was conducted, the rusted 

condition was determined to not impact the function of the bolts, and the affected area was 

painted to prevent further degradation. The applicant also stated that galvanic corrosion was 

detected on the bolting associated with one of the containment air handling coolers, determined 

to be due to condensation on dissimilar metal interfaces, and the corrective action involved a 

materials substitution that provided adequate resistance to galvanic corrosion, which removed 

the susceptibility for further degradation.
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The staff lacks sufficient information to conclude that the applicant’s program is effective at 

managing aging of pressure-retaining bolting and component external surfaces which are 

surrounded by seal cap enclosures. The staff noted that in recent reviews of license renewal 

applications and operating experience, the applicant may have used, or currently uses, seal cap 

enclosures to contain water leakage, and the use of the enclosures may not be accounted for in 

the LRA. By letter dated May 29, 2012, the staff issued RAI B.2.1.9-2 requesting that for all 

pressure-retaining bolting and external surfaces that are surrounded by seal cap enclosures, the 

applicant describe a) the bolting and component material and the leaking water environment, b) 

new AMR items for the aging management of the bolting and external surfaces for loss of 

material, loss of preload, change in material properties, and cracking due to SCC in the 

submerged environment, c) technical justification for how the aging effects above are managed 

if direct inspection is not possible, and d) how future use of seal cap enclosures is controlled 

such that aging is managed. These issues are open item OI 3.0.3.1.7-1. 

Based on its audit and review of the application, the staff finds, with the exception of 

OI 3.0.3.1.7-1, that 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. The staff 

confirmed that, pending resolution of OI 3.0.3.1.7-1, the “operating experience” program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

UFSAR Supplement. LRA Section A.2.1.9 provides the UFSAR supplement for the Bolting 

Integrity 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 Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, and 3.5-2. The staff determined that, pending 

resolution of OI 3.0.3.1.7-1, the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.1.8 One-Time Inspection Program

. On the basis of its review of the applicant’s Bolting Integrity Program, the staff finds 

all program elements consistent with the GALL Report, with the exception of the “operating 

experience” program element, which is associated with OI 3.0.3.1.7-1. The staff concludes that, 

with the exception of OI 3.0.3.1.7-1, 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, pending resolution of 

OI 3.0.3.1.7-1, it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Summary of Technical Information in the Application

• determination of appropriate inspection sample size

. LRA Section B.2.1.20 describes the new 

One-Time Inspection Program as consistent with GALL Report AMP XI.M32, “One-Time 

Inspection.” The applicant stated that the One-Time Inspection Program is a new program that 

addresses component, material, and environment combinations for which aging effects are 

either not occurring or are progressing so slowly as to have negligible effect on the intended 

function of the structure or components through the period of extended operation. The applicant 

also stated that the program will provide the following functions:

• identification of inspection locations
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• selection of examination techniques, including acceptance criteria

• evaluation of results to determine the need for additional inspections or other corrective 

actions

The applicant further stated that the inspection methods of the program may include visual (or 

remote visual), surface or volumetric examinations, or other established nondestructive 

examination techniques.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M32. As discussed in the audit report, the staff confirmed 

that these elements are consistent with the corresponding elements of GALL Report 

AMP XI.M32, with the exception of the “detection of aging effects” program element. In this 

element, the staff determined the need for additional clarification, which resulted in the issuance 

of an RAI.

. 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.

GALL Report AMP XI.M32 states that the inspection includes a representative sample of the 

system population, and, where practical, focuses on the bounding or lead components most 

susceptible to aging due to time in service, severity of operating conditions, and lowest design 

margin. However, during the staff’s review of the applicant’s One-Time Inspection Program, the 

staff noted that the applicant did not include specific information regarding how the sample set 

of components are to be selected or how the sample size will be determined. The staff also 

noted that large sample sizes (e.g., at least 20 percent) may be necessary in order to 

adequately confirm an aging effect does not occur because of the uncertainty in determining the 

most susceptible locations and the potential for aging to occur in other locations. By letter dated 

December 14, 2010, the staff issued RAI B.2.1.20-1 requesting that the applicant provide 

specific information regarding how the sample set of components will be selected and how the 

size of the sample of components will be determined.

In its response dated January 13, 2011, the applicant stated that the program will be modified to 

include the inspection of approximately 20 percent of the components of each in-scope material 

type, environment, and aging effect combination, but not to exceed 25 components. The staff 

noted that LRA Section B.2.1.20 states that the samples include locations where the most 

severe aging effects would be expected to occur. The samples will be based on aspects such 

as location, design, material of construction, service environment, and previous failure history, 

and they will include stagnant or low-flow areas. The staff finds the applicant’s response 

acceptable because the applicant’s sampling methodology ensures a representative sample of 

material and environment combinations is considered, ensures sample locations will focus on 

the most susceptible components, and includes an appropriate sample size. The staff’s 

concern described in RAI B.2.1.20-1 is resolved.

Based on its audit and review of the applicant’s response to RAI B.2.1.20-1, the staff finds that 

elements one through six of the applicant’s One-Time Inspection Program are consistent with 

the corresponding program elements of GALL Report AMP XI.M32 and, therefore, are 

acceptable.

Operating Experience. LRA Section B.2.1.20 summarizes operating experience related to the 

One-Time Inspection Program. The applicant stated that there is no operating experience 
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specifically applicable to the new one-time inspections. However, the applicant provided 

examples of operating experience that indicated the existing Condition Monitoring and Condition 

Reporting Programs are effective in identifying, evaluating, and correcting aging effects typical 

of the scope of this program. For example, the applicant described an instance in which 

corrosion was observed on the pump discharge head flange during the replacement of a service 

water cooling tower pump. In response to the observed corrosion, the discharge head was 

replaced with a more corrosion-resistant material.

In another instance of operating experience, the applicant described a case in which a large 

amount of rust and scale was found in piping connecting valves with air receivers. The 

applicant stated that the response involved removal of all loose corrosion products, and no 

evidence of pitting or wall thinning was found.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

The staff also noted that in LRA Supplement 2 to the LRA, Appendix A, the applicant committed 

(Commitment No. 22) to implement the new One-Time Inspection Program within 10 years prior 

to the period of extended operation. The staff determined that the information in the UFSAR 

supplement, as amended, is an adequate summary description of the program, as required by 

10 CFR 54.21(d).

. LRA Section A.2.1.20 provides the UFSAR supplement for the One-Time 

Inspection 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 Tables 3.1-2, 3.2-2, 3.3-2, and 3.4-2.

Conclusion. On the basis of its review of the applicant’s One-Time Inspection Program, the staff 

finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant 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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3.0.3.1.9 ASME Code Section XI, Subsection IWE Aging Management Program

Summary of Technical Information in the Application. LRA Section B.2.1.27 describes the 

existing ASME Code Section XI, IWE AMP as consistent with GALL Report AMP XI.S1, “ASME

Section XI, Subsection IWE.” The LRA states that this program manages aging effects of the 

containment steel liner plate, electrical penetrations, mechanical penetrations (piping, 

ventilation, and spares), personnel lock, equipment hatch, recirculation sump, reactor pit, 

moisture barriers, seals, gaskets, pressure-retaining bolting, and supports. Inspection of the 

containment liner plate and the associated components are performed in accordance ASME 

Code Section XI, Subsection IWE. The applicant also stated that the acceptance criteria, 

corrective actions, and expansion of the inspection scope when degradation exceeding the 

acceptance criteria is found are in accordance with the IWE requirements. According to the 

LRA, the applicant followed the requirements of the 1995 Edition, including the 1996 Addenda, 

of ASME Code Section XI, Sub-Section IWE for the first 10-year inspection interval effective 

from August 19, 2000–August 18, 2010, and in accordance with 10 CFR 50.55a. The applicant 

also stated that the next and subsequent 120-month inspection interval will incorporate the 

requirements specified in the version of the ASME Code incorporated into 10 CFR 50.55a, 

12 months before the start of the inspection interval.

Summary of Staff Evaluation. The staff reviewed the various elements of the containment liner 

plate aging management program and found them consistent with the corresponding elements 

of GALL Report AMP XI.S1; however, the staff noted the applicant's previous failure to maintain 

the annular space between the containment and containment enclosure buildings in a 

dewatered state. Based on this operating experience, the applicant in Commitment 52, 

committed to maintain the annular space in a dewatered state. The staff is concerned that the 

applicant has not, until now, implemented procedures and inspection requirements to keep this 

area dewatered in the future. Accumulation of water in the annular space can potentially 

degrade the containment liner plate. The staff's concern is tracked as Open Item OI 3.0.3.1.9-1.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.S1. As discussed in the audit report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL Report AMP XI.S1. 

Based on its audit, the staff finds that elements one through six of the applicant’s ASME Code

Section XI, Subsection IWE AMP are consistent with the corresponding program elements of 

GALL Report AMP XI.S1 and, therefore, are acceptable.

. 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.

Operating Experience. LRA Section B.2.1.27 summarizes operating experience related to the 

ASME Code Section XI, Subsection IWE AMP. The applicant stated it has reviewed the 

industry operating experience concerning containment liner plate degradation, including NRC 

Information Notices (INs) 86-99, “Degradation of Steel Containments,” IN 88-82, “Torus Shells 

with Corrosion and Degraded Coatings in BWR Containments,” IN 89-79, “Degraded Coatings 

and Corrosion of Steel Containment Vessels,” and IN 97-10, “Liner Plate Corrosion in Concrete 

Containments,” and considered their applicability to Seabrook. The applicant also stated that it 

has reviewed the containment liner issue from Beaver Valley, where inspections in 2009 

revealed degradation from the inaccessible side of the steel liner. The applicant further stated 

that no potentially through-liner corrosion issues have been noted during the IWE examinations.
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The applicant identified several condition reports in a search for “containment liner” 

documenting material found to be in contact with the containment liner (e.g., scaffolding, grating 

hose reels, and outage contractor storage boxes) during outage activities. These were promptly 

and appropriately dispositioned. In addition, the applicant stated, during the Seabrook nuclear 

oversight audit of key activities during RFO 7 (fall of 2000), one material was observed as a 

faulty moisture barrier at the minus 26 ft level, azimuth 250°. A condition report was initiated,

and the barrier was repaired. The applicant also stated that, in November 2001, a condition 

report documented the opportunity to complete IWE examinations for containment recirculation 

sump area during the RFO window for containment liner inspection that had been inaccessible. 

The applicant stated that this condition report documented the understanding of the scope of 

this program and the ability to recognize respective windows of opportunity.

The staff reviewed operating experience information, in the application, and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program. During its 

review, the staff identified operating experience that could indicate that the applicant’s program 

may not be effective in adequately managing aging effects during the period of extended 

operation. The staff determined the need for additional clarification, which resulted in the 

issuance of RAIs.

During the AMP audit, the staff interviewed the applicant's staff and reviewed documentation 

about the groundwater seepage in different plant structures. The staff found that groundwater 

infiltrated into the annular space between the concrete enclosure building and concrete 

containment. The bottom 6 ft of the concrete containment wall was in contact with the 

groundwater for an extended period of time. In addition, cracks due to alkali-silica reaction 

(ASR) have been observed in different Seabrook plant concrete structures, including the 

concrete enclosure building. Therefore, the groundwater may have penetrated the concrete 

containment wall and come into contact with the containment liner plate. This can result in 

through-wall corrosion of the containment liner plate. Therefore, in a letter dated 

November 18, 2010, the staff issued RAI B.2.2.27-1. The staff requested that the applicant 

explain any plans to perform nondestructive examinations, such as UT, of the containment liner 

to demonstrate that the effects of prolonged exposure of the bottom portion of the concrete 

containment to groundwater have not introduced corrosion on the concrete side of the liner 

plate. Corrosion on the concrete side of the containment liner could affect its ability to perform 

its intended design function during the period of extended operation.

In its response, dated December 17, 2010, the applicant stated that Seabrook continues to 

monitor the annulus area including the exterior concrete surface of containment where 

groundwater had accumulated. The applicant also stated that the lack of oxygen and high pH 

alkali environment of the concrete are inhibitors to a corrosive environment that would be 

detrimental to the integrity of the liner; therefore, the potential for loss of material at the concrete 

to liner plate interface due to water accumulating in the annulus area is very low. However, 

based on NRC IN 2010-12, “Containment Liner Corrosion,” and other industry and site-specific 

operating experience, Seabrook will perform testing of the containment liner plate for loss of 

material. The applicant added an enhancement and commitment (Commitment No. 50) to its 

ASME Code Section XI, Subsection IWE AMP to perform testing of the containment liner plate 

for loss of material on the concrete side of the liner. The testing will be conducted in 

accordance with approved ASME Code Section XI, Subsection IWE methodology, and it will be 

completed prior to the period of extended operation. In addition, the applicant in accordance 
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with Commitment 52 will implement measures to maintain the exterior surface of the 

containment structure from elevation -30 ft to +20 ft in a dewatered state.

The staff reviewed the applicant’s response to RAI B.2.1.27-1 and noted that the applicant 

committed to perform testing of the containment liner plate for the loss of material on the side of 

the concrete; however, it is not clear how this testing will be performed. Therefore, in a letter 

dated March 17, 2011, the staff issued followup RAI B.2.1.27-1 requesting the applicant provide 

details regarding the testing to be performed to determine the loss of material on the concrete 

side of the liner plate. The staff asked that these details include a description of the 

nondestructive testing methods and locations where thickness measurements will be obtained 

and explain why the measurement locations will provide an adequate representation of liner 

plate locations that may be degraded.

In its response, dated April 14, 2011, the applicant stated that Seabrook will perform UT testing 

of the liner plate inside containment for loss of material on the concrete side of the liner. The 

testing will be subject to ASME Code Section XI, Subsection IWE acceptance criteria (the code 

currently in use at Seabrook is the 2004 ASME code) and will be completed by 

December 31, 2015. The applicant further stated under IWE 1241(a), Seabrook will designate 

the area of the containment liner that is within 10 in. of the moisture barrier at the containment 

basement floor for examination. This is the lowest accessible point on the liner and for potential 

degradation due to moisture; the lowest point is the most susceptible. Locations spaced at 10°

increments (approximately every 12 ft) of accessible circumference, or locations showing visible 

signs of degradation, will be tested with one or more readings taken at each location. The 

examination will be repeated at intervals of no more than five RFOs. If any indications are 

found that show a loss of material exceeding 10 percent of nominal thickness (ASME Code 

acceptance criteria), an engineering evaluation of deficient indications will be performed and 

actions planned accordingly. The applicant revised the enhancement and Commitment No. 50 

to perform UT testing in the vicinity of the moisture barrier for loss of material at a nominal 10°

increment around the circumference of containment, and to complete it no later than 

December 31, 2015. The UT testing will be repeated at intervals of no more than five RFOs.

Based on its review, the staff finds the applicant’s response acceptable because the applicant

committed to monitor the containment liner plate condition and thickness prior to 

December 31, 2015, and subsequently at intervals of no more than five RFOs (7.5 years) before 

and during the period of extended operation. The UT testing will be performed at 10°

increments (36 locations) around the circumference of containment. The augmented UT 

examination, in conjunction with visual examination in accordance with IWE, will provide 

reasonable assurance that any potential loss of material at the concrete-to-liner-plate interface 

due to water accumulating in the annulus area will not affect the structural integrity of the 

containment liner plate. In case loss of liner plate thickness is detected during the visual and 

UT examinations, the applicant will perform an engineering evaluation and will perform remedial 

actions in accordance with the Corrective Actions Program. The applicant’s Commitment 

No. 50 also demonstrates that the applicant addressed operating experience identified after 

issuance of the GALL Report, including IN 2010-12, concerning through-wall corrosion of the 

liner plate at Beaver Valley Power Station. The staff’s concerns in RAI B.2.1.27-1 and the 

associated followup RAI concerning liner plate corrosion and loss of material are resolved.

The staff also noted that, in response to RAI B.2.28-3, the applicant committed (Commitment 

No. 52) to implement measures to maintain the containment exterior surface between elevations 

-30 ft to +20 feet dewatered by December 31, 2012. During the December 31, 2010, inspection,

NRC inspectors examined the subject area and found it in a dewatered state. Portable sump 
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pumps are used to dewater the area. However, the staff is concerned that until now the 

applicant has not implemented any permanent measures for dewatering and revised procedures 

for routine inspection of this area. Accumulation of water in the annular space between the 

containment and containment enclosure buildings can potentially degrade the containment liner 

plate. The staff's concern is tracked as Open Item OI 3.0.3.1.9-1.

During the site audit, the staff reviewed documentation concerning the corrosion of the 

containment liner plate around the fuel transfer tube vault documented during the 2009 IWE 

inspection. The containment liner plate had indications of heavy corrosion. UT examination of 

the containment liner indicated that liner plate thickness varied between 0.484–0.411 in.

(variation of 18 percent) within a small area. The applicant accepted this degradation of the 

liner plate based on engineering evaluation. The applicant justification for acceptance was that 

the measured thickness of the liner plate was still greater than the 0.375 in. nominal thickness of 

the liner plate. However, the staff did not find any requirement in the applicant's engineering 

evaluation that requires UT reexamination of the affected portion of the liner plate for three 

consecutive periods in accordance with IWE-2420. Therefore, in a letter dated 

November 18, 2010, the staff issued RAI B.2.2.27-2, requesting that the applicant provide the 

details of any actions planned for augmented examination of the containment liner plate around 

the fuel transfer tube where the corrosion was detected during the 2009 inspection.

In its response, dated December 17, 2010, the applicant stated that this condition requires 

augmented inspection in accordance with 1995 Edition with 1996 Addenda of the ASME Boiler 

and Pressure Vessel (B&PV) Code, Section XI, Subsection IWE-2420(b) and IWE-2420(c). The 

applicant further stated that the condition has been identified in the ISI Program database for 

reexamination during subsequent scheduled inspections.

The staff reviewed the applicant’s response to RAI B.2.1.27-2 and noted that the ASME Code

1995 Edition with 1996 Addenda, Section XI, Subsection IWE-2420(b) and IWE-2420(c) state 

that reexamination of degraded areas is no longer required if these areas remain essentially 

unchanged for three consecutive inspection periods. However, it was not clear from the 

applicant’s response if the containment liner plate around the fuel transfer tube is still exposed 

to the borated water leakage. Exposure to borated water can promote corrosion of the liner 

plate and adversely affect the ability of the liner to perform its intended function. Therefore, in a 

letter dated March 17, 2011, the staff issued followup RAI B.2.1.27-2 requesting that the 

applicant describe steps that are being taken to monitor the liner plate thickness around the 

transfer tube or efforts to address the leakage of borated water or both.

In its response, dated April 14, 2011, the applicant stated that the leak path into the fuel transfer 

tube vault has been repaired and the borated water leakage stopped. The area of the 

containment liner plate that had showed signs of deficiency (loss of material) have been 

examined and accepted by engineering evaluation. The areas are subject to IWE required 

augmented UT examinations for the next three exam cycles. If no further degradation (loss of 

material) is observed during those three cycles, the subject area will return to normal visual IWE 

inspections. These visual inspections would be able to identify any further leakage of borated 

water.

Based on its review, the staff finds the applicant’s response to RAI B.2.1.27-2 acceptable 

because the applicant evaluated the local loss of thickness and degradation in the liner plate 

around the fuel transfer tube and found it acceptable. The applicant also identified this 

degradation in its ISI Program database for reexamination during the next three exam cycles in 

accordance with IWE-2420 requirements. In addition, the applicant repaired the leak path into 
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the fuel transfer tube vault to stop the borated water leakage. The normal visual examinations 

and augmented UT examination of the affected area during the next three exam cycles in 

accordance with IWE requirements will ensure that the containment liner aging is managed in 

accordance with the guidance provided in GALL Report AMP XI.S1. The staff’s concerns in 

RAI B.2.1.27-2 and the associated followup RAI are resolved.

Based on its audit and review of the application and review of the applicant’s responses to RAIs 

RAI B.2.1.27-1 and RAI B.2.1.27-2, the staff finds that operating experience related to the 

applicant’s program demonstrates that it can adequately manage the detrimental effects of 

aging on SSCs within the scope of the program. The staff also finds that implementation of the 

program has resulted in the applicant taking appropriate corrective actions. The staff confirmed 

that the “operating experience” program element satisfies the criterion in SRP-LR

Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment No. 50) to ongoing 

implementation of the existing ASME Code Section XI, Subsection IWE AMP for managing 

aging of applicable components during the period of extended operation. Specifically, the 

applicant committed to perform UT testing in the vicinity of moisture barrier for loss of material at 

a nominal 10° increment around the circumference of containment and to complete it no later 

than December 31, 2015. The UT testing will be repeated at intervals of no more than five 

RFOs. The applicant has also committed (Commitment 52) to keep the annular space between 

the containment and containment enclosure buildings in a dewatered state. The staff 

determined that the information in the UFSAR supplement, as amended, pending resolution of 

Open Item OI 3.0.3.1.9-1, is an adequate summary description of the program, as required by 

10 CFR 54.21(d).

. LRA Section A.2.1.27 provides the UFSAR supplement for the ASME 

Code Section XI, Subsection IWE Aging Management 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 3.5-2.

Conclusion

3.0.3.1.10 ASME Code Section XI, Subsection IWF Program

. On the basis of its review of the applicant’s ASME Code Section XI, 

Subsection IWE AMP, the staff finds all program elements consistent with the GALL Report. 

Also, the staff reviewed the enhancement and confirmed that its implementation through 

Commitment No. 50 prior to the period of extended operation (no later than December 31, 2015) 

would make the existing AMP consistent with the GALL Report AMP to which it was compared. 

However, the staff is concerned that, until now, the applicant has not implemented 

Commitment 52 to ensure that the annular space between the containment and containment 

enclosure buildings is maintained in a dewatered state. The staff's concern is tracked as Open 

Item OI 3.0.3.1.9-1.

Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the 

existing ASME Code Section XI, Subsection IWF as consistent with GALL Report AMP XI.S3, 

“ASME Section XI, Subsection IWF.” In the LRA, the applicant stated that this program 

manages aging effects of the ASME Code Classes 1, 2, 3, and metal containment component 

supports. The Seabrook ASME Code Section XI, Subsection IWF Program is implemented on a 

10-year cycle in accordance with the requirements of 10 CFR 50.55a, with specified limitations, 

modifications, and NRC-approved alternatives. The program specifies the percentage of 

supports that must be examined. For supports, other than piping supports, the supports of only 
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one component of a group having similar design, function, and service are examined. The 

applicant also stated that the program uses VT-3 visual examination for detection of degradation 

and uses the acceptance standards for visual examination specified in ASME Code Section XI, 

Subsection IWF-3410.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.S3. As discussed in the audit report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL Report AMP XI.S3. 

Based on its audit, the staff finds that elements one through six of the applicant’s ASME Code

Section XI, Subsection IWF Program are consistent with the corresponding program elements 

of GALL Report AMP XI.S3 and, therefore, are acceptable.

. 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.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program.

. LRA Section B.2.1.29 summarizes operating experience related to the 

ASME Code Section XI, Subsection IWF Program. In the LRA, the applicant stated that an 

operating experience review found instances of supports being deficient but operable. These 

conditions were reported and evaluated in accordance with the Corrective Action Program. The 

LRA also states that IWF Program inspections in the spring of 1997 and spring of 1999 resulted 

in 36 and 5 deficiencies, respectively. The applicant stated that these conditions were 

evaluated and dispositioned. During the spring of 2005 inspection, no deficiencies requiring 

further evaluation were identified.

During its review, the staff identified operating experience which could indicate that the 

applicant’s program may not be effective in adequately managing aging effects during the 

period of extended operation. The staff determined the need for additional clarification, which 

resulted in the issuance of an RAI.

The GALL Report AMP XI.S3 states that the IWF scope of inspection for supports is based on 

sampling of the total support population. Discovery of support deficiencies during regularly 

scheduled inspections triggers an increase of the inspection scope in order to ensure that the 

full extent of the deficiencies is identified. IWF-2430 provides guidance on how to increase the 

sample size in case deficiencies are identified during examination of the supports. However, 

during the audit, the staff did not find any documentation that the supports sample size was 

increased in accordance with IWF-2430 after the ISI inspections conducted during 1997 and 

1999, which identified 36 and 5 support conditions with deficient conditions, respectively. 

Therefore, to address this issue, by letter dated November 18, 2010, the staff issued 

RAI B.2.1.29-1 requesting the applicant provide documentation demonstrating IWF inspections 

are performed in accordance with the recommendations of GALL Report XI.S3 regarding 

increase in the sample size when deficiencies are identified during examination of supports.

In its response dated December 17, 2010, the applicant stated that during the 1997 IWF (RFO

OR05) Inspection, 36 apparent deficiencies were identified. All 36 were evaluated by the 

applicant engineering personnel. Of the 36 deficiencies, 32 were suspect clearances that were 
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found acceptable, 2 were determined to be design issues (which were corrected), and 2 were 

evaluated as deficiencies which were repaired to acceptable condition. For these last two 

deficiencies, the applicant conducted expanded inspections. The applicant also stated that the 

32 clearance deficiencies noted above were identified on the basis of ISI drawings, which gave 

an absolute value for clearance. The applicant further stated that the engineering evaluation 

that evaluated the clearances against tolerances of the design and construction specifications, 

found the conditions to be nonrelevant in accordance with IWF-3410(b). Therefore, no 

corrective action was called for and an extended examination was not required. Similar results 

for clearance deficiencies were seen and dispositioned during the following, 1999 IWF 

Inspection.

The staff reviewed the applicant’s response to the RAI B.2.29-1 and found it acceptable 

because the applicant expanded the scope of inspections for the two supports that were found 

deficient and repaired them, as required by ASME Code Section XI, Subsection IWE. The other 

supports with clearance deficiencies were found to be acceptable after review of design 

drawings. IWF-3410 considers general conditions that are acceptable by the material, design, 

or construction specifications as nonrelevant. Expanded scope, in accordance with IWF-3410,

is not required for nonrelevant conditions. The staff’s concern in RAI B.2.1.29-1 is resolved.

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

RAI B.2.1.29-1, the staff finds that operating experience related to the applicant’s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking appropriate corrective actions. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

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 3.5-2. The staff determined that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

. LRA Section A.2.1.29 provides the UFSAR supplement for the ASME 

Code Section XI, Subsection IWF Program.

Conclusion

3.0.3.1.11 10 CFR Part 50, Appendix J Aging Management Program

. On the basis of its review of the applicant’s ASME Code Section XI, 

Subsection IWF Program and RAI B.2.1.29-1 response, the staff finds all program elements 

consistent with the GALL Report. The staff concludes that the applicant 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).

Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the 

existing 10 CFR Part 50, Appendix J AMP as consistent with GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J.” According to the applicant, this program is a containment leak 

rate monitoring program that includes integrated and local leak rate tests of components that 

make up the primary containment pressure boundary. The program includes Types A, B, and C 
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testing as described in 10 CFR Part 50, Appendix J and provides for periodic verification of the 

leak-tight integrity of the primary reactor containment. The applicant also stated that the 

Seabrook Station Leakage Test Reference is based on guidance provided in NEI 94-01,

"Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, 

Appendix J,” and ANSI/ANS-56.8-1994, “Containment System Leakage Testing Requirements,”

with the restrictions identified in Regulatory Guide (RG) 1.163, "Performance-based 

Containment Leak-Test Program." The applicant further stated that its 10 CFR Part 50,

Appendix J program, in conjunction with its ASME Code Section XI, Subsection IWE and ASME 

Code Section XI, Subsection IWL programs, provides an AMP that is effective at detecting 

degradation of the containment boundary.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.S4. 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.S4, with the exception of the “detection of aging effects” program element. For 

this element, the staff determined the need for additional clarification, which resulted in the 

issuance of RAIs.

. 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 whether they are 

bounded by the conditions for which the GALL Report was evaluated.

GALL Report AMP XI.S4 recommends a containment leak rate testing program as an effective 

method for detecting degradation of containment shells, liners, and components that 

compromise the containment pressure boundary, including seals and gaskets. It also states 

that this would be achieved with the additional implementation of an acceptable containment ISI

program as described in GALL Report AMPs XI.S1 and XI.S2. In addition, GALL Report 

AMP XI.S4 recommends a general inspection of internal and external surfaces of the 

containment prior to a Type A test. However, during its audit, the staff found that the applicant 

inspected containment surfaces prior to the most recent Type A test using its “Complex 

Procedure” for reactor containment integrated leakage rate testing. Based on a review of the 

procedure, the staff noted that the containment inspection section of the procedure does not 

specify examination methods for conducting internal and external inspections that are consistent 

with ASME Code Section XI, Subsections IWE and IWL requirements.

By letter dated December 14, 2010, the staff issued RAI B.2.1.30-1 requesting that the 

applicant:

• Describe the methods and procedures used to conduct a general inspection of internal 

and external surfaces of the containment prior to the most recent Type A test.

• Indicate whether these methods and procedures are consistent with the containment ISI

programs described in GALL Report AMPs XI.S1 and XI.S2.

• Describe the method being used to ensure that internal and external containment 

inspections are being implemented as described in GALL Report AMPs XI.S1 and XI.S2 

and consistent with element 4, “Detection of Aging Effects,” of GALL Report AMP XI.S4.

In its response to RAI B.2.1.30-1, item 1, dated January 13, 2011, the applicant stated that the 

Type A test conducted in 2008 was performed using the “Reactor Containment Integrated 

Leakage Rate Test - Type A” complex procedure. According to the applicant, this procedure 

contains a prerequisite which states: “A general inspection of the accessible interior and exterior 
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surfaces of the containment structure and components is complete.” The inspection requires 

that: 

The structural integrity shall be determined by a visual inspection of the exposed 

accessible interior and exterior surfaces of the containment vessel. The inspection shall 

be performed to verify no apparent changes in appearance of the surfaces or other 

abnormal degradation. Any abnormal degradation of the containment vessel detected 

during the above required inspections shall be reported to the Commission in a Special 

Report pursuant to T.S. 6.8.2 within 15 days. 

The applicant further stated that the general inspection of the accessible interior and exterior 

surfaces of the containment structure is a requirement from 10 CFR Part 50, Appendix J, 

Subsection V.A, and is in addition to, and totally separate from, the inspection requirements of 

ASME Code Section XI, Subsections IWE and IWL.

In response to RAI B.2.1.30-1, item 2, the applicant stated that the Seabrook Appendix J 

Program is consistent with the requirements of GALL Report AMP XI.S4 and that the 

containment inspection required by 10 CFR Part 50, Appendix J is in addition to and separate 

from the requirements of GALL Report AMP XI.SI and XI.S2. In response to item 3, the 

applicant stated that its XI.SI and XI.S2 programs are consistent with NUREG-1801 and that the 

inspections conducted as part of the 10 CFR Part 50, Appendix J Program are consistent with 

GALL Report AMP XI.S4, “10 CFR Part 50, Appendix J.”

The staff finds the applicant’s response to the RAI B.2.1.30-1 acceptable because the applicant 

did not credit the IWE/IWL visual inspections towards Appendix J general visual examinations 

between and prior to Type A tests. The applicant performed a different set of inspections to 

meet the 10 CFR Part 50, Appendix J general visual inspection requirements prior to and 

between Type A tests. Therefore, visual inspections, conducted independent and separate from 

those recommended by GALL Report AMPs XI.S1 and XI.S2, are not required to be consistent 

with ASME Code Section XI, Subsections IWE and IWL requirements. The staff’s concerns in 

RAI B.2.1.30-1 are resolved.

GALL Report AMP XI.S4 states that Appendix J provides two options, A and B, either of which 

can be chosen to meet the requirements of a containment leak rate testing program. Under 

Option A, all of the testing must be performed on a periodic interval. Option B is a 

performance-based approach. In LRA Section B.2.1.30, the applicant states that the Seabrook 

Station Containment Leakage Rate Testing Program, required by Seabrook Station Technical 

Specification (TS), implements Option B, and the Seabrook Station Leakage Test Reference is 

based on the guidance provided in NEI 94-01 and ANSI/ANS-56.8-1994 with the restrictions 

identified in RG 1.163.

During the audit of element 4, the staff reviewed the “Complex Procedure” for reactor 

containment integrated leakage rate testing and qualification guidance for personnel who 

conducted visual examinations of concrete containment surfaces. The staff concluded that the 

qualification of personnel who conduct visual examinations of concrete containment surfaces 

should be consistent with qualification provisions in IWA-2300 as required by 10 CFR 50.55a.

By letter dated December 14, 2010, the staff issued RAI B.2.1.30-2 requesting the applicant to 

provide plans and a schedule that will ensure that personnel who perform visual examinations of 

concrete containment surfaces to comply with the applicant's commitment to implement 

Option B for integrated leakage rate tests are qualified in accordance with IWA-2300 
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requirements, and that the applicant's 10 CFR Part 50, Appendix J AMP is consistent with GALL 

Report AMP XI.S4, “10 CFR Part 50, Appendix J.”

In its response dated January 13, 2011, the applicant stated that personnel performing the 

visual examinations of concrete surfaces prior to an integrated leak rate test are not qualified in 

accordance with IWA-2300 and that there is no requirement in 10 CFR 50.55a that Appendix J 

general visual inspection personnel be qualified per IWA-2300. The applicant further explained 

that this is a general inspection of the containment surface for any apparent degradation that 

would cause failure of the integrated leak rate test and because there are no requirements for 

inspector qualifications, the Appendix J AMP is consistent with GALL Report AMP XI.S4. The 

applicant also stated that personnel performing the visual examinations required by the ASME 

Code Section XI, Subsections IWE and IWL are qualified to the requirements of IWA-2300.

The staff reviewed the applicant’s response to RAI B.2.1.30-2 and noted that the applicant did 

not provide any information about the qualification of the personnel performing the visual 

examination. In addition, the response did not provide any specific acceptance criteria for 

inspection of the containment interior and exterior surfaces. The lack of qualification 

requirements for personnel performing general visual examinations may impact the structure 

integrity and leak tightness of the concrete containment during the period of extended operation. 

Therefore, in a teleconference dated November 8, 2011, that staff discussed draft followup 

RAI B.2.1.30-2, requesting the applicant provide information about the qualification of the 

personnel performing the general visual inspection of the accessible interior and exterior 

surfaces of the containment system for structural deterioration which may affect the containment 

leak-tight integrity conducted prior to each Type A test, and at a periodic interval between the 

Type A tests. In addition, the staff requested the applicant provide the acceptance criteria used 

for these inspections.

In its formal response to draft followup RAI B.2.1.30-2 by letter dated November 17, 2011, the 

applicant stated that:

Personnel performing the Type A pretest general visual inspection utilize the 

Containment and Containment Enclosure Surface Inspection procedure, and are 

qualified in accordance with the Qualification Guide, Engineering Support 

Personnel Training Program for Appendix J Engineer. The procedure provides 

qualitative criteria needed to detect structural problems that may affect either the 

containment structure leakage integrity or the performance of the Type A test. 

The applicant also initiated a change to this procedure to clarify the current inspection practices 

as follows:

During refueling outages when Subsection IWE inspections and the ILRT 

[Integrated Leakrate Test] are to be performed, both of the IWE and Appendix J 

examinations will be performed prior to the ILRT. The Appendix J Engineer will 

review the results of the most recent Subsection IWL inspections as well as any 

issues identified from the IWE inspections prior to conducting the Appendix J 

general visual inspection.

During refueling outages when a Subsection IWE inspection is not performed, 

and the Appendix J general visual inspection is required, the Appendix J 

Engineer will review the results of the most recent Subsection IWE and IWL 

inspections and then perform a separate general visual inspection in accordance 

with the Containment and Containment Enclosure Surface Inspection procedure.
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The staff finds the applicant’s response to followup RAI B.2.30-2 acceptable because the 

personnel performing the visual examination of the containment as a part of Appendix J, Type A 

test program are qualified and trained to discover any evidence of structural deterioration which 

may affect structural integrity or leak tightness. Both 10 CFR 50, Appendix J and NEI 94-01 do 

not have any specific personnel qualification requirements for these inspections but state that 

the objective of the inspection is to identify structural deterioration that may affect containment 

leak-tight integrity. In addition, visual examination of the containment conducted for Appendix J, 

Type A test program will be complemented and informed by the detailed examinations 

performed in accordance with ASME Code Subsection IWE and IWL requirements.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.30-1 and B.2.1.30-2, 

the staff finds that elements one through six of the applicant’s 10 CFR Part 50, Appendix J AMP

are consistent with the corresponding program elements of GALL Report AMP XI.S4 and, 

therefore, acceptable.

Operating Experience

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately incorporated and evaluated operating experience related 

to this program.

. LRA Section B.2.1.30 summarizes operating experience related to the 

10 CFR Part 50, Appendix J AMP. The applicant indicated that implementation of Option B for 

testing frequency is consistent with plant operating experience and described results of Types B 

and C local leak rate tests performed during Refueling Outages 9, 10, 11, and 12. Although 

these tests identified leakage from various isolation valves and containment on-line purge 

penetrations that required repair or replacement, the applicant stated that no major issues were 

found and that all as-left local leak rate test results for Refueling Outages 9, 10, 11, and 12 were 

acceptable. During the audit, the staff found that the most recent Type A test was completed in 

2008 and that the results of this test were within acceptable limits.

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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking appropriate corrective actions. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 

and, therefore, the staff finds it acceptable.

UFSAR Supplement

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 3.5-2. The staff determined that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

. LRA Section A.2.1.30 provides the UFSAR supplement for the 

10 CFR Part 50, Appendix J AMP.
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Conclusion

3.0.3.1.12 Electrical Cables and Connections Not Subject To 10 CFR 50.49 Environmental 

Qualification Requirements Program

. On the basis of its review of the applicant’s 10 CFR Part 50, Appendix J AMP, 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 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 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).

Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the new 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

(EQ) Requirements Program as consistent with GALL Report AMP XI.E1, “Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The 

applicant stated that the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ

Requirements Program will manage the aging effects of embrittlement, cracking, discoloration,

or surface contamination leading to reduced insulation resistance or electrical failure of 

accessible cables and connections due to exposure to an adverse localized environment 

caused by heat, radiation, or moisture in the presence of oxygen. The applicant also stated that 

accessible electrical cables and connections exposed to adverse localized environments or 

ambient conditions in excess of 60-year service limiting environments will be visually inspected 

for signs of accelerated age-related degradation.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.E1. As discussed in the audit report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL Report AMP XI.E1. 

Based on its audit, the staff finds that elements one through six of the applicant’s Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Program are 

consistent with the corresponding program elements of GALL Report AMP XI.E1 and, therefore, 

are acceptable.

. 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.

Operating Experience

• the shared experiences of plant operators in the NEI License Renewal Working Group

. LRA Section B.2.1.32 summarizes operating experience related to the 

new Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements 

Program. The applicant claimed that both plant-specific and industry-wide operating experience 

was considered in the development of the program, and these considerations ensure that the 

program would be an effective AMP for the period of extended operation. The following 

particular observations were cited by the applicant, including the operating experience cited in 

NUREG-1801, Chapter XI, Section E1:

• the results from Seabrook’s Corrective Action Program, in particular with respect to 

degraded cable insulation from localized areas of overheating

• Seabrook plant engineering guidelines for system walkdowns that prompt engineers to 

observe the condition of cable and connections
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Furthermore, in a condition report, the applicant stated that a project was undertaken in 1998 

and 1999 to reduce the infiltration of groundwater into plant buildings by injecting a hydrophobic 

material through to the outside of the building walls. The effort was only partially successful and 

was terminated when, tritium contamination above background was found in groundwater 

leaking into the containment annulus. The applicant performed a root cause evaluation and 

installed dewatering points in three locations around the plant. The staff noted that no recent 

events of water intrusion in cable trays and tunnels were identified. The staff performed an 

inspection of the -26 ft electrical tunnel cable tray room and observed no water on cable tray or 

cables.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program. Further, 

the staff performed a search of regulatory operating experience for the past 10-year period 

through April 2010. Databases were searched using various key word searches and then 

reviewed by technical auditor staff.

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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental 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. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the 

staff finds it acceptable.

UFSAR Supplement

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

. LRA Section A.2.1.32 provides the UFSAR supplement for the Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements 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 3.6-2. The 

staff also noted that the applicant committed (Commitment No. 34) to implement the new 

Electrical Cables and Connections Not Subject To 10 CFR 50.49 EQ Requirements Program 

prior to entering the period of extended operation for managing aging of applicable components.

Conclusion. On the basis of its review of the applicant’s Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 EQ Requirements Program, the staff finds all program elements 

consistent with the GALL Report. The staff concludes that the applicant 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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3.0.3.1.13 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.2.1.33 describes the new 

Electrical Cables and Connections Not Subject To 10 CFR 50.49 EQ Requirements Used in 

Instrumentation Circuits Program as consistent with GALL Report AMP XI.E2, “Electrical Cables 

and Connections Not Subject To 10 CFR 50.49 Environmental Qualification Requirements Used 

in Instrumentation Circuits.” The applicant stated that the Electrical Cables and Connections 

Not Subject To 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program will 

manage the aging effects of reduced insulation resistance due to exposure to adverse localized 

environments caused by heat, radiation, or moisture in the presence of oxygen, causing 

increased leakage currents. The applicant also stated that this program applies to sensitive 

instrumentation cable and connection circuits with low-level signals in the in-scope portions of

in-core neutron flux monitoring cable in the nuclear instrumentation system.

Staff Evaluation

During its review, the staff confirmed that high-voltage, low-level radiation monitoring system 

cables that are usually in-scope of GALL Report AMP XI.E2 are included in the EQ Program by 

reviewing EQ equipment data sheets. The staff compared elements one through six of the 

applicant’s program to the corresponding elements of GALL Report AMP XI.E2. As discussed 

in the audit report, the staff confirmed that these elements are consistent with the corresponding 

elements of GALL Report AMP XI.E2. Based on its audit, the staff finds that elements one 

through six of the applicant’s Electrical Cables and Connections Not Subject To 10 CFR 50.49 

EQ Requirements Used in Instrumentation Circuits Program are consistent with the 

corresponding program elements of GALL Report AMP XI.E2 and, therefore, are acceptable.

. 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.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program. Further, 

the staff performed a search of regulatory operating experience for the past 10-year period 

through April 2010. Databases were searched using various key word searches and then 

reviewed by technical auditor staff.

. LRA Section B.2.1.33 summarizes operating experience related to the 

Electrical Cables and Connections Not Subject To 10 CFR 50.49 EQ Requirements Used in 

Instrumentation Circuits Program. In the LRA, the applicant stated that Seabrook considers 

plant-specific and industry-wide operating experience. The applicant also stated that, in 2008, 

testing was performed on all in-core neutron flux monitoring cables and connections. The test 

results documented a less-than-expected insulation resistance reading between the inner and 

outer shield. The low insulation resistance reading was attributed to the connector design. The 

applicant further stated that the design issue was resolved, and retesting found the cable and 

connection to be acceptable.

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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental 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. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the 

staff finds it acceptable.

UFSAR Supplement

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

. LRA Section A.2.1.33 provides the UFSAR supplement for the Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used in 

Instrumentation Circuits 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 3.6-2. The staff also noted that the applicant committed 

(Commitment No. 35) to implement the new Electrical Cables and Connections Not Subject To 

10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program prior to entering the 

period of extended operation for managing aging of applicable components.

Conclusion

3.0.3.1.14 Metal Enclosed Bus Program

. On the basis of its review of the applicant’s Electrical Cables and Connections Not 

Subject To 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program, the staff 

finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant 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).

Summary of Technical Information in the Application

• loosening of bolted connections due to thermal cycling and ohmic heating

. LRA Section B.2.1.35 describes the new 

Metal Enclosed Bus (MEB) Program as consistent to GALL Report AMP XI.E4, “Metal Enclosed 

Bus.” The applicant stated that the MEB Program is a new program that will manage the 

following aging effects of in-scope MEBs: 

• hardening and loss of strength due to elastomer degradation

• loss of material due to general corrosion

• embrittlement, cracking, melting, swelling, or discoloration due to overheating or aging 

degradation

The applicant further stated that this new program will be implemented prior to entering the 

period of extended operation and inspection will be conducted at least once every 10 years after 

the period of extended operation. Aging management of the exterior housing and elastomers of 

the in-scope MEBs is included in the Structures Monitoring Program.

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.
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The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.E4. 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.E4, with the exception of the “detection of aging effects” program element. For 

this element, the staff determined the need for additional clarification, which resulted in the 

issuance of an RAI.

In Seabrook basis document LRAP-E4, under the "detection of aging effect" element, the 

applicant states that the MEB Program will perform thermography inspections external to the 

MEBs to determine if the in-scope MEBs have loose connections due to thermal cycling and 

ohmic heating. The inspections will be performed on all accessible bus sections while the bus is 

energized. Normally, windows are installed on the MEB to facilitate these thermography 

inspections. The metal enclosed cover may mask the heat created by loosening of bus 

connections, and the temperature differences between bus connections may not be detected if 

windows are not installed on MEBs. During the LRA onsite audit in the week of 

October 21, 2010, the staff asked the applicant to clarify how the MEB connection inspections at 

Seabrook are effective in detecting loosening of bus connections using external thermography 

measurements. In a letter dated November 15, 2010, the applicant revised the MEB Program 

description to clarify that, if thermography is used to identify loose connections, the applicant will 

use inspection techniques that will provide accurate readings. In addition, the applicant added 

connection resistance measurements as an alternate method to determine if MEB connections 

are loose. The applicant revised LRA Appendix B, Section B.2.1.35 as follows:

The internal portions of the in-scope metal enclosed bus enclosures will be 

visually inspected for aging degradation of insulating material and for cracks, 

corrosion, foreign debris, excessive bust buildup, and evidence of moisture 

intrusion. The bus insulation will be visually inspected for signs of embrittlement, 

cracking, melting, swelling, or discoloration, which may indicate overheating or 

aging degradation. The isolated phase bus conductor is not insulated. The 

internal bus supports will be visually inspected for structural integrity and signs of 

cracks. The accessible bus section will be inspected for loose connections using 

a thermography inspection technique that will provide accurate temperature 

readings of the bus bolted connection temperatures, such as through view ports. 

As an alternative to thermography, connection resistance measurements may be 

used to determine if the in-scope MEBs have loose connections due to thermal 

cycling and ohmic heating. The program requires that bolted connections be 

below the maximum allowed temperature for the application, and free of 

unacceptable visual defects.

The staff finds the applicant’s supplement to LRA Section B.2.1.35 acceptable because it will be 

performing thermography (such as through view ports) that will provide accurate temperature 

readings of the bus bolted connections temperature compared to using thermography external 

to the MEB metal enclosed cover. The staff also finds that the connection resistance 

measurement, as an alternative to thermography, is acceptable to determine if the bus 

connections are loosening due to thermal cycling and ohmic heating because high resistance 

measurement will indicate that the bus connections are loosening. The inspection technique 

(thermography or resistance measurements) is consistent with that in GALL Report AMP XI.E4.

Based on its audit and review of the applicant’s response in letter dated November 15, 2010, 

the staff finds that elements one through six of the applicant’s MEB Program are consistent with 
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the corresponding program elements of GALL Report AMP XI.E4 and, therefore, are 

acceptable.

Operating Experience

The staff reviewed the operating experience, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program. Further, 

the staff performed a search of regulatory operating experience for the past 10-year period 

through March 2010. Databases were searched using various key word searches and then 

reviewed by technical auditor staff.

. LRA Section B.2.1.35 summarizes operating experience related to the 

MEB Program. The applicant stated that plant-specific and industry-wide operating experience 

was considered in the development of this program. The applicant also stated that the Institute 

of Nuclear Plant Operation (INPO) issued a Special Event Report, SER 5-09, “6.9-kV 

Non-segregated Bus Failure and Complicated Scram.” The event report documents the 

catastrophic failure of a 6.9-kV non-segregated bus. The cause of the event was attributed to 

the overheating of the center bus bar at the flex connection. Seabrook performs periodic visual 

inspections and infrared thermography tests on all in-scope non-segregated buses and the 

isolated phase buses. In 2005, during the inspection of a non-segregated phase bus, white 

corrosion was found on a bolted connection surface near a flat washer. In addition, a green 

residue was noted on the surface area of the bus near the connection area. The applicant also 

stated that the connection was broken to facilitate a complete inspection of the connection for 

additional corrosion. The connection was remade and successfully tested. The same duct was 

also noted to have an expansion joint that was not sealing. The applicant corrected the 

deficiency.

During its review, the staff found no additional 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 operating experience related 

to the applicant’s program demonstrates that the program can adequately manage the 

detrimental 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. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment No. 37) to implement the new 

MEB Program inspections once every 10 years, with the first inspection to be performed prior to 

entering the period of extended operation, in order to manage aging of applicable components.

. LRA Section A.2.1.35 provides the UFSAR supplement for the MEB 

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 3.6-2.

The staff determined that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).
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Conclusion

3.0.3.1.15 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program

. On the basis of its audit and review of the applicant’s MEB Program, the staff finds 

all program elements consistent with the GALL Report. The staff concludes that the applicant 

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).

Summary of Technical Information in the Application. LRA Section B.2.1.37 describes the new 

Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program as 

consistent with GALL Report AMP XI.E6, “Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements,” as modified by LR-ISG-2007-02. 

The applicant stated that the Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Program is a new, one-time testing program that will be used to verify that the 

aging effect of loosened bolted connections due to thermal cycling, ohmic heating, electrical 

transients, vibration, chemical contamination, corrosion, and oxidation on the metallic portion of 

electrical cable connections does not require management. The applicant further stated that a 

representative sample of cable connections within the scope of license renewal will be selected 

for one-time testing prior to the period of extended operation.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of the GALL Report AMP XI.E6. As discussed in the audit report, the staff confirmed 

that each element of the applicant’s program is consistent with the corresponding element of the 

GALL Report AMP XI.E6, with the exception of the “parameters monitored or inspected” 

program element. For this element, the staff determined that the need for additional clarification 

was required.

. 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.

GALL Report AMP XI.E6, under the “parameters monitored or inspected” program element,

states that a representative sample of electrical cable connections is tested. The technical 

basis for the sample selected is to be documented. The implementing document for the 

program will provide the technical basis for the sample selection with respect to both sample 

size and inspection locations. In the basis document, LRAP-E6, under the same program 

element, the Seabrook program performs tests on a representative sample of electrical cable 

connections. The monitoring includes loosening of bolted connections due to thermal cycling, 

ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. 

The applicant developed the technical basis for selecting samples of cable connections and 

documented it as Technical Report, LRTR-E6, “Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Sample Selection,” Revision 1. 

During the audit, the staff found that the sample size was not included in LRTR-E6 Revision 1. 

During the break-out meeting, the staff discussed with the applicant its concerns that the sample 

size is not being included in the technical report. The applicant revised the technical report

(LRTR-E6 Revision 2) to include the sample size such that the sample set shall include at least 

20 percent of the connections for each category listed below or a minimum of 25 connections of 

each of the following categories:
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• power (4.160 kV and 13.8 kV) crimped/bolted

• power (460 V and 480 V) crimped/bolted

• control (120 VAC [volts-alternating current] and 125 VDC [volts-direct current]) 

crimped/terminal board connection

• instrument (low voltage) crimped/terminal board connection

The staff reviewed the technical report revision and found that the sample size is consistent with 

current staff positions.

Based on its audit, and review of LRA Section B.2.1.37 and LRTR-E6, Revision 2, the staff finds 

that elements one through six of the applicant’s Electrical Cable Connections Not Subject To 

10 CFR 50.49 EQ Requirements Program are consistent with the corresponding program 

elements of GALL Report AMP XI.E6, as modified by final LR-ISG-2007-02 and, therefore, are

acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in accordance with the GALL Report. As 

discussed in the audit report, the staff conducted walkdowns, interviewed the applicant’s staff, 

and reviewed onsite documentation provided by the applicant. The staff also conducted an 

independent search of the applicant’s operating experience information to determine if the

applicant adequately incorporated and evaluated operating experience related to this program. 

Further, the staff performed a search of regulatory operating experience for the period 2000

through April 2010. Databases were searched using various key word searches and then 

reviewed by technical auditor staff.

. LRA Section B.2.1.37 summarizes operating experience related to the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program. 

Although a new program, the applicant stated that plant-specific operating experience and 

industry-wide operating experience was considered in the development of this program. The 

applicant further stated that a review of plant-specific and industry-wide operating experience 

ensures that the one-time inspection corresponding to GALL Report AMP XI.E6, will confirm the 

absence or presence of age-related degradation of cable connections caused by thermal 

cycling, ohmic heating, corrosion, and oxidation. The applicant stated that Seabrook routinely 

performs infrared thermography tests on numerous pieces of equipment, including electrical 

connections, as part of the Preventive Maintenance Program. In 2002, during an infrared 

thermography inspection of a 480 volt circuit breaker, a hot connection was found. The 

connection was approximately 150 °F hotter than similar connections. Seabrook procedures 

required that the connection be corrected within 1 week. Infrared thermography was used to 

monitor the connection on a daily basis until corrective action could be taken. The applicant 

further stated that, in 2005, an infrared thermography inspection identified heating on three 

connections in a control panel. The connections were 30–50 °F higher than expected. 

Seabrook procedures require that this condition be corrected in 12 weeks. The hot connections 

were repaired. The connections were found to be tight, and the hot spot was attributed to 

defective connectors.

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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental 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. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the 

staff finds it acceptable.

UFSAR Supplement

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 3.6-2, as modified by the applicant’s implementation of LR-ISG-2007-02.

. LRA Section A.2.1.37 provides the UFSAR supplement for the Electrical 

Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program.

The staff also noted that the applicant committed (Commitment No. 39) to implement the new 

Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program prior to 

entering the period of extended operation for managing aging of applicable components.

The staff determined that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.1.16 Environmental Qualification of Electric Components Program

. On the basis of its audit and review of the applicant’s Electrical Cable Connections 

Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that those 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent with the GALL Report and LR-ISG-2007-02. The staff concludes that the applicant 

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).

Summary of Technical Information in the Application. LRA Section B.2.3.2 describes the 

existing EQ of Electric Components Program as consistent with GALL Report AMP X.E1, 

“Environmental Qualification (EQ) of Electric Components.” The applicant also stated that the 

EQ Program manages component thermal, radiation, and cyclic aging through the use of 

10 CFR 50.49(f) qualification methods. The applicant also stated that qualified lives are 

determined for equipment within the scope of the EQ Program, and appropriate actions such as 

replacement, refurbishment, or reevaluation are taken prior to the end of the qualified life of the 

equipment so that the aging limit is not exceeded. The applicant further stated that all EQ 

equipment is included within the scope of license renewal.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by 

the conditions for which the GALL Report was evaluated. As part of a power uprate to increase 

generating capacity by 5.2 percent and as part of license renewal, the applicant updated EQ 

calculations for EQ electrical equipment. The staff reviewed a sample of these calculations to 

ensure that the design change adequately accounted for the power uprate and the extended 

qualified life for license renewal.
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The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP X.E1. 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 X.E1. Based on its audit, the staff finds that elements one through six of the 

applicant’s EQ of Electric Components Program are consistent with the corresponding program 

elements of GALL Report AMP X.E1 and, therefore, are acceptable.

Operating Experience

The applicant listed samples of condition reports in LRA Section B.2.3.2 such as those listed 

below: 

. LRA Section B.2.3.2 summarizes operating experience related to the 

EQ of Electric Components Program. The applicant stated its program is an existing program 

and has been maintained by onsite engineering personnel since its inception. The applicant 

also stated that Seabrook has a comprehensive operating experience program that monitors 

industry issues/events and assesses these for applicability to its own operations.

• reducing solenoid qualified lives based on temperature monitoring

• potential loss of the environmental seal due to the twisting of a transmitter’s electronics 

housing

• potentially different greases being used on EQ fan motor bearings

The applicant stated the operating experience of the EQ Program did not show any adverse 

trend in performance. The applicant further stated the key elements of the EQ Program are 

being monitored and effectively implemented.

The staff reviewed the operating experience in the application and during the audit to determine 

if the applicable aging effects and industry and plant-specific operating experience were 

reviewed by the applicant and evaluated in the GALL Report. As discussed in the audit report, 

the staff conducted an independent search of the plant operating experience information to 

determine if the applicant adequately incorporated and evaluated operating experience related 

to this program. Further, the staff performed a search of regulatory operating experience for the 

past 10-year period through April 2010. Databases were searched using various key word 

searches and then reviewed by technical auditor staff.

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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental 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. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the 

staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.3.2 provides the UFSAR supplement for the EQ of 

Electric Components Program. The staff reviewed this UFSAR supplement description of the 

program and noted that, in conjunction with LRA Section 4.4, it conforms to the recommended 

description for this type of program, as described in SRP-LR Tables 4.4-1 and 4.4-2.
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The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2 Aging Management Programs Consistent with the GALL Report with 

Exceptions or Enhancements 

. On the basis of its review of the applicant’s EQ of Electric Components Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant 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).

In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with 

the GALL Report, with exceptions or enhancements:

• Reactor Head Closure Studs Program

• Steam Generator Tube Integrity Program

• Open-Cycle Cooling Water System Program

• Closed-Cycle Cooling Water System Program

• Inspection of Overhead Heavy Load Handling Systems Program

• Compressed Air Monitoring Program

• Fire Protection Program

• Fire Water System Program

• Aboveground Steel Tank Program

• Fuel Oil Chemistry Program

• Reactor Vessel Surveillance Program

• Selective Leaching of Materials Program

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program

• External Surfaces Monitoring Program

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program

• Lubricating Oil Analysis Program

• ASME Code Section XI, Subsection IWL Program

• Structures Monitoring Program

• Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements 

Program

• Protective Coating Monitoring and Maintenance Program

• Metal Fatigue of Reactor Coolant Pressure Boundary Program
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For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s) or

enhancement(s) or both, 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, 

were indeed consistent. The staff also reviewed the exception(s) or enhancement(s) to the 

GALL Report to determine if they were acceptable and adequate. The results of the staff’s 

audits and reviews are documented in the following sections.

3.0.3.2.1 Reactor Head Closure Studs Program

Summary of Technical Information in the Application. LRA Section B.2.1.3 describes the 

existing Reactor Head Closure Studs Program as consistent, with an exception, with GALL 

Report AMP XI.M3, “Reactor Head Closure Studs.” The applicant stated that the aging effects 

of reactor vessel flange stud hole threads, reactor head closure studs, nuts, and washers are 

detected through visual or volumetric examination in accordance with the applicant’s ASME 

Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program to manage 

cracking and loss of material. The applicant also stated that the program implements the 

guidance outlined in RG 1.65, “Materials and Inspections for Reactor Vessel Closure Studs,” for 

preventive measures including material selection, appropriate coatings, and lubricants. The 

applicant further stated that reactor head closure studs are manufactured from SA-540, Class 3, 

Grade B24 material. The applicant stated that these reactor head closure studs are coated with 

an anti-galling metallic coating (PlasmaBond), and a station-approved lubricant is used during 

installation and removal of the studs that does not contain molybdenum disulfide.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M3. 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.M3, with the exception of the “preventive actions” program element. For this 

element, the staff determined the need for additional clarification, which resulted in the issuance 

of RAIs.

. 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.

In its review, the staff noted that RG 1.65 was originally issued in 1973. The staff also noted 

that RG 1.65, Revision 1, was issued in April 2010 and includes using bolting material for 

closure studs that has a measured yield strength less than 150 ksi, which is resistant to stress 

corrosion cracking. The staff further noted that LRA Section B.2.1.3 states that the applicant’s 

reactor head closure studs are manufactured from SA-540, Class 3, Grade B24 material, and 

the maximum tensile strength of the material is less than 170 ksi, as recommended in the GALL 

Report and RG 1.65 issued in 1973. However, the staff noted that the applicant’s program does 

not include the preventive action using stud materials with a measured yield strength level less 

than 150 ksi in comparison with RG 1.65, Revision 1. By letter dated December 14, 2010, the 

staff issued RAI B.2.1.3-1 requesting that the applicant clarify whether the measured yield 

strength of the reactor head closure stud material exceeds 150 ksi and clarify whether there are 

program provisions that would preclude use of materials with yield strength greater than 150 ksi. 

The staff also requested that, if the program does not include provisions that would preclude 

use of materials with yield strength greater than 150 ksi or if the reactor head closure stud 

material has a yield strength level greater than or equal to 150 ksi, the applicant justify why the 

Reactor Head Closure Studs Program is adequate to manage stress corrosion cracking in the 

high-strength material.
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In its response dated January 13, 2011, the applicant committed (Commitment No. 53) to 

replace the reactor head closure stud(s) manufactured from the bar that has a yield strength 

greater than 150 ksi with ones that do not exceed 150 ksi prior to the period of extended 

operation. The applicant also stated that the yield strength from the test coupon for one of the 

bars, from which the studs were manufactured, was measured at 151.75 ksi, which is slightly 

higher than 150 ksi. The applicant further stated that the studs, which have yield strength 

measured at 151.75 ksi, are presently in storage. In addition, the applicant stated that its 

Reactor Head Closure Studs Program is revised to implement the guidance outlined in RG 1.65, 

Revision 1, such that its program includes the preventive action using stud materials with a 

measured yield strength not exceeding 150 ksi.

Based on its review, the staff finds the applicant’s response to RAI B.2.1.3-1 acceptable for the 

following reasons:

• The applicant’s Reactor Head Closure Studs Program is revised to implement the 

guidance of RG 1.65, Revision 1, for the use of material with yield strength not 

exceeding 150 ksi.

• The applicant committed (Commitment No. 53) to replace the reactor head closure studs 

with yield strength greater than 150 ksi, which are presently in storage, with the ones 

that do not exceed 150 ksi measured yield strength, consistent with the guidance in 

RG 1.65, Revision 1.

• The applicant’s inspection, in accordance with the ASME Code Section XI, is adequate 

to detect and manage cracking due to stress corrosion cracking of the studs.

The staff’s concern described in RAI B.2.1.3-1 is resolved.

The staff noted that the program description of GALL Report AMP XI.M3 states that the 

recommended program includes ISI to detect cracking, loss of material, and coolant leakage 

from reactor head closure studs. The staff also noted that the “preventive actions” program 

element of GALL Report AMP XI.M3 includes using manganese phosphate or other acceptable 

surface treatments and stable lubricants. LRA Section B.2.1.3 indicates that a station-approved 

lubricant is used during the installation and removal of the studs that does not contain 

molybdenum disulfide. The staff noted that the applicant’s operating experience indicates that 

discoloration was reported on some of the reactor head closure studs during RFO 8 in 2002, 

and the discoloration on the PlasmaBond coating was determined to be the lubricant used for 

stud removal and was not considered an indication of stud degradation. By letter dated 

December 14, 2010, the staff issued RAI B.2.1.3-2, requesting that the applicant clarify the root 

cause for the discoloration on the closure studs. The staff also requested that the applicant 

provide the service temperature range of the lubricant in comparison with the operating 

temperatures of the reactor head closure studs. The staff further requested that the applicant 

clarify whether the lubricant is stable at the operating temperatures and is compatible with the 

stud and vessel materials and with the surrounding environment.

In its response dated January 13, 2011, the applicant stated that a condition report from 2002 

identified slight surface rust and discoloration on the PlasmaBond metallic coating on the 

reactor head closure studs. The applicant also stated that the PlasmaBond vendor indicates 

that the discoloration was due to tarnishing of the silver in the metallic coating, that the rust was 

limited to a small area near the top of the threaded portion of the stud that threads into the 

reactor vessel flange, and that the slight coating of rust identified in 2002 appears to have come 

from the reactor vessel stud hole. The applicant stated that during RFOs when the reactor head 
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closure studs are removed, the stud holes are cleaned to remove any particles or deposits that 

may have accumulated in the stud holes. The applicant also stated that the inspection of the 

studs revealed no thread damage, and the small amount of surface rust and discoloration on the 

PlasmaBond coating is not considered an aging effect that requires management during the 

period of extended operation. The applicant stated that the lubricant (WD-40) applied on the 

studs has an operating temperature range from -10 °F to 200 °F and the operating temperature 

of the reactor head closure studs is estimated to approach 500 °F. In addition, the applicant 

stated that according to the manufacturer of the lubricant, when the lubricant is exposed to the 

reactor vessel metal temperature at operating condition, it would carbonize and any carbonized 

deposits would have no adverse effect on the PlasmaBond coating or reactor vessel stud or 

flange materials.

The staff noted that the applicant’s lubricant is also used to clean the reactor head closure studs 

during RFOs and later to protect potential corrosion of the stud material. The staff further noted 

that the applicant claimed that its review of plant-specific operating experience indicates no 

adverse effect on the aging of reactor head closure stud or vessel flange materials. However, 

the staff finds the applicant’s response unacceptable because the operating temperature range 

of the lubricant (-10 °F to 200 °F) is significantly lower than the operating temperature of the 

reactor head closure studs that is estimated by the applicant to approach 500 °F. Additionally, 

the lubricant carbonizes at the operating temperature of the closure studs and the carbonization 

by-products may accumulate on the stud threads and cause bolting material degradations. The 

staff also noted that the applicant’s use of the lubricant is not consistent with the guidance in 

RG 1.65, that lubricants for the stud bolting are permissible provided they are stable at 

operating temperatures of the reactor head closure stud bolting. In addition, the staff was 

concerned that the carbonization of the lubricant and accumulation of carbonization by-products 

on the studs and flange threads degrade the lubrication process of the bolting such that the 

removal operation of the studs may cause sticking, galling, or thread damage of the reactor 

head closure bolting.

By letter dated February 24, 2011, the staff issued RAI B.2.1.3-2 followup. The staff asked the 

applicant to justify why the use of the lubricant, the operating temperature of which is 

significantly lower than that of the reactor head closure studs, is consistent with the guidance in 

RG 1.65 and the GALL Report, which state that lubricants for the stud bolting are permissible 

provided they are stable at operating temperatures of the reactor head closure stud bolting. The 

staff also requested that the applicant justify the use of the lubricant, which has an operating 

temperature range from -10 °F to 200 °F, on the reactor head closure studs, which has an 

operating temperature that is estimated to approach 500 °F. The staff further requested that, if 

a justification for the use of this lubricant cannot be provided, the applicant state the lubricant it 

will use that will remain stable at operating temperatures of the reactor head closure stud 

bolting. In addition, the staff requested that the applicant justify why the carbonization of the 

lubricant and accumulation of carbonization by-products on the studs and flange threads do not 

cause sticking, galling, or thread damage of the studs and flange threads and, as part of the 

justification, clarify whether the applicant’s operating experience is in agreement with the 

justification.

In its response dated March 22, 2011, the applicant stated that the LRA and its response to 

RAI B.2.3-2 incorrectly referred to WD-40 as a “lubricant” when, in fact, its intended use is to 

clean the reactor head closure studs and stud holes and protect them against rust and corrosion 

that can form at ambient temperatures, specifically, during installation and removal of the studs. 

The applicant also stated that the WD-40 product has been evaluated for use as an expendable 

product on external surfaces at its site with no restrictions. In addition, once the WD-40 is 
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elevated to normal operating temperature of approximately 500 °F, the carbonized deposits 

have no adverse effect on the PlasmaBond coating, reactor vessel stud, or flange materials. 

The applicant further stated that it has not experienced sticking, galling, or thread damage of the 

studs or flange threads due to carbonization by-products associated with WD-40.

Based on its review, the staff finds the applicant’s responses to RAIs B.2.1.3-2 and B.2.1.3-2 

followup acceptable for the following reasons:

• The applicant’s inspection results did not indicate thread damage on the reactor head 

closure studs associated with the discoloration, which was a result of tarnishing from the 

silver in the PlasmaBond coating.

• Any particle or deposit that may have accumulated in the stud holes will be removed 

during RFOs, so the potential of contamination or material accumulation is minimized on 

the stud and flange thread surfaces.

• The applicant clarified that WD-40 is only used to clean and protect the exposed areas 

of the studs and stud holes from corrosion that can form at ambient temperatures.

• The plant-specific operating experience indicates no occurrence of sticking, galling, or 

thread damage due to the use of WD-40.

The staff’s concerns described in RAIs B.2.1.3-2 and B.2.1.3-2 followup are resolved.

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with the exception to determine if the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of this exception follows.

Exception 1

The staff noted that the “detection of aging effects” program element of GALL Report 

AMP XI.M3 recommends surface and volumetric examinations for the reactor head closure 

studs when removed, which are based on the requirements in Table IWB-2500-1 of the 1995 

Edition through the 1996 addenda of the ASME Code Section XI. The staff also noted that the 

applicant clarified that the later version of the ASME Code referenced by GALL Report 

AMP XI.M3 (ASME Code 2001 edition including the 2002 and 2003 addenda) has been updated 

to include the Code Case N-307-3 allowance that the surface examination may be eliminated. 

In its review, the staff also noted that RG 1.65, Revision 1, issued in April 2010, indicates that 

the use of Code Case N-307-3 was approved by RG 1.147, Revision 15, “Inservice Inspection 

Code Case Acceptability, ASME Section XI, Division 1,” issued in October 2007.

. LRA Section B.2.1.3 states an exception to the “detection of aging effects” 

program element. The LRA states that the reactor head closure studs are removed from the 

reactor vessel during each RFO, and its ISIs are performed with the studs removed and consist 

of a volumetric examination only as allowed by Code Case N-307-3 and current version of the 

ASME Code Section XI.

Based on its review, the staff finds this exception to the “detection of aging effects” program 

element acceptable because the applicant performs volumetric examination of reactor head 

closure studs consistent with RG 1.65, Revision 1, and the 2001 edition of the ASME Code

Section XI, including the 2002 and 2003 addenda. Additionally, the inspection, in accordance 

with the ASME Code Section XI requirements, is adequate to detect and manage loss of 

material due to wear and cracking due to stress corrosion cracking.
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Based on its audit and review of the applicant’s response to RAIs B.2.1.3-1, B.2.1.3-2 and 

B.2.1.3-2 followup, the staff finds that elements one through six of the applicant’s Reactor Head 

Closure Studs Program, with acceptable exception, are consistent with the corresponding 

program elements of GALL Report AMP XI.M3 and, therefore, are acceptable.

Operating Experience

The applicant’s operating experience also addressed the final post-tensioned elongation values 

of reactor head studs. The applicant stated that one reactor head closure stud was found out of 

specified elongation range by 0.002 in. during RFO 10 in 2005. The applicant also stated that 

an engineering evaluation was performed and that the preload induced by post-tensioning was 

below the designed range but was adequate to carry the reactor vessel pressure design loads. 

During the audit, the applicant further stated that the out-of-specification condition was a 

one-time operational occurrence and was not associated with aging of reactor head closure 

studs.

. LRA Section B.2.1.3 summarizes operating experience related to the 

Reactor Head Closure Studs Program. The applicant stated that one reactor head closure stud 

was stuck due to galling during RFO 5 in 1997. The applicant also stated that the stud was cut 

out, and appropriate repairs and retests were performed per the requirements of the ASME 

Code Section XI. The applicant further stated that this operating experience prompted an 

investigation into suitable anti-galling compounds, which resulted in the application of an 

anti-galling metallic coating on the reactor head closure studs.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated 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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental 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. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the 

staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.1.3 provides the UFSAR supplement for the Reactor 

Head Closure Studs 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 3.1-2. The staff determined 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 applicant’s Reactor Head Closure Studs 

Program, the staff determined that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determined that the AMP, with the exception, is adequate to manage the 

aging effects for which the LRA credits it. The staff concludes that the applicant 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 
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concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.2.2 Steam Generator Tube Integrity Program

Summary of Technical Information in the Application

• cracking due to intergranular attack, outer diameter stress corrosion cracking, PWSCC, 

and stress corrosion cracking

. LRA Section B.2.1.10 describes the 

existing Steam Generator Tube Integrity Program as consistent, with exceptions, with GALL 

Report AMP XI.M19, “Steam Generator Tube Integrity.” The applicant stated that the program 

manages the following aging effects:

• loss of material due to general, crevice and pitting corrosion, erosion, fretting, and wear

• reduction of heat transfer due to fouling and wall thinning from flow-accelerated 

corrosion of the steam generator (SG) components

The applicant stated that the program manages the aging of steam generator (SG) tubes, tube 

plugs, and tube supports. The tubing material for the Seabrook SGs is thermally treated Alloy 

600 material. The applicant reported that the current dominant degradation mode for thermally 

treated Alloy 600 tubing is wear.

The applicant stated that the program is based on NEI 97-06, Revision 2, “Steam Generator 

Program Guidelines,” the response and commitment to GL 97-06, “Degradation of Steam 

Generator Internals,” and Seabrook Technical Specifications (TS) 3/4.4.5, “Steam Generators,” 

which ensure that the performance criteria for structural integrity, accident-induced leakage, and 

operational leakage are not exceeded. The applicant also stated that Seabrook has 

implemented the operational leakage limits found in NUREG-1431, “Standard Technical 

Specifications for Westinghouse Pressurized Water Reactors.”

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M19. As discussed in the audit report, the staff confirmed 

that these elements are consistent with the corresponding elements of GALL Report 

AMP XI.M19.

. 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 also reviewed the portions of the “scope of program” program element associated with 

the exception to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of this exception follows.

Exception 1. LRA Section B.2.1.10 states an exception to the “scope of program” program 

element. The GALL Report recommends that the applicant implement the SG degradation 

management program described in NEI 97-06, “Steam Generator Program Guidelines,” 

Revision 1, to manage effects of aging on the SG tubes, plugs, sleeves, and tube supports. 

Alternatively, this program element states that the Steam Generator Tube Integrity Program is 

based on NEI 97-06, Revision 2. The applicant states that Revision 2 of NEI 97-06 does not 

reduce the functional requirements of Revision 1. In addition, the applicant states that 

NEI determined that Revision 2 is consistent with Technical Specification Task Force 

(TSTF)-449, Revision 4, “Steam Generator Tube Integrity.” The applicant states that Seabrook 
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implemented TSTF-449 with License Amendment 115 to the technical specifications in June 

2007.

The staff reviewed this exception and the guidance document NEI 97-06, Revision 1, 

recommended by the GALL Report AMP. The staff has reviewed NEI 97-06, Revision 2, and 

has found the guidance document consistent with the GALL Report because it does not reduce 

the fundamental requirements found in Revision 1. In addition, Revision 2 contains updated 

operating experience relevant to ensure that tube integrity is maintained.

The staff finds this program exception acceptable and consistent with the one described in the 

GALL Report Section XI.M19 because NEI 97-06, Revision 2, does not reduce the fundamental 

requirements of Revision 1, which is recommended by the GALL Report AMP, and Revision 2 

was determined to be acceptable since it is consistent with TSTF-449.

Based on its audit, the staff finds that elements one through six of the applicant’s Steam 

Generator Tube Integrity Program, with acceptable exception, are consistent with the 

corresponding program elements of GALL Report AMP XI.M19 and, therefore, are acceptable.

Operating Experience

The staff reviewed the following regarding operating experience:

. LRA Section B.2.1.10 summarizes experience related to the Steam 

Generator Tube Integrity Program. The staff reviewed this information and interviewed the 

applicant’s technical personnel to confirm that the applicable aging effects and industry and 

plant-specific operating experience have been reviewed by the applicant and are evaluated in 

the GALL Report. During the audit, the staff independently confirmed that the applicant had 

adequately incorporated and evaluated operating experience related to this program.

(1) Through Refueling Outage 13 (Fall of 2009), Seabrook Station has plugged a total of 

173 tubes in the steam generators (A-34 tubes, B-25 tubes, C-50 tubes, and D-64

tubes).

(2) The Steam Generator degradation assessment for RFO 13 in the fall of 2009 identified 

operating experience at Vogtle Unit 1 where axial and circumferential outside diameter 

stress corrosion cracking was reported at the top of the hot leg tubesheet. Vogtle has 

Westinghouse Model F Steam Generators with Alloy 600 thermally treated tubing similar 

to Seabrook Station. Vogtle Unit 1 was the first U.S. plant to report axial outside 

diameter stress corrosion cracking at the top of the tube sheet in a Model F Steam 

Generator. Accordingly, this operating experience was incorporated into the 

implementation plan for RFO 13 as part of the steam generator inspections.

Subsequently, an axial outside diameter stress corrosion cracking indication was found 

on one tube in Steam Generator “C” hot leg. The indication was approximately 0.2 

inches below the top of the tube sheet and was 0.10 inches long. The tube was plugged 

on both the hot leg and cold leg sides.

(3) During RFO 12 in the spring of 2008, foreign objects were discovered in steam 

generator “B” during the inspection of the steam drum area. The root cause evaluation 

was performed, which concluded that the cause of the foreign objects being in the steam 

generator was inadequate foreign material exclusion controls of material used in steam 

generator “B” steam drum inspection. The root cause evaluation’s recommended 

corrective action to prevent re-occurrence by revising the job plan for steam generator

inspection to include a pre-use inspection of all materials brought into the steam 
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generators for concealed/loose foreign material. This corrective action has been 

implemented.

During its review of the LRA, the staff also identified operating experience that indicates the 

potential for degradation of the SG tube-to-tubesheet welds that could impact the applicant’s 

program in adequately managing aging effects during the period of extended operation. By 

letter dated December 14, 2010, the staff issued RAI B.2.1.10-1 requesting that the applicant 

clarify whether the tube-to-tubesheet welds are included in the RCPB or if alternate repair 

criteria have been permanently approved. It also requested the applicant to provide a 

plant-specific AMP, along with the Primary Water Chemistry Program, or justify an alternative 

method to manage cracking due to PWSCC on the primary coolant side of steam generator 

tube-to-tubesheet welds since they are made from a nickel alloy.

In its response dated January 13, 2011, the applicant stated that its SG tube-to-tubesheet welds 

are not included in the RCPB because NRC has approved an alternate repair criteria for 

Seabrook. However, the applicant further stated that NRC has not yet permanently approved

the alternate repair criteria. In the event that the NRC does not grant a permanent approval of 

the alternate repair criteria through a license amendment, the applicant's RCPB would revert 

back to include the tube-to-tubesheet welds. For such a scenario, the applicant also stated in 

its response that, unless an alternate repair criteria changing the ASME Code boundary is 

permanently approved by the NRC, or the applicant's SGs are replaced to eliminate 

PWSCC-susceptible tube-to-tubesheet welds, the applicant will submit a plant-specific AMP to 

manage the potential aging effect of cracking due to PWSCC at least 24 months prior to 

entering the period of extended operation. The plant-specific program will do one of the 

following:

(1) perform a one-time inspection of a representative sample of tube-to-tubesheet welds in 

all SGs to determine if PWSCC cracking is present and, if cracking is identified, resolve 

the condition through engineering evaluation justifying continued operation or repair the 

condition, as appropriate

(2) perform an analytical evaluation showing that the structural integrity of the SG 

tube-to-tubesheet interface is adequately maintaining the pressure boundary in the 

presence of tube-to-tubesheet weld cracking and ensure that the tube-to-tubesheet 

welds are not required to perform a reactor coolant pressure boundary function

After reviewing the applicant’s response to RAI B.2.10-1, the staff finds that the approved 

temporary alternate repair criteria appropriately excludes the tube-to-tubesheet welds from 

RCPB on a temporary basis. The staff also noted that the applicant has submitted a license 

amendment request on April 10, 2012, to gain permanent approval from the NRC for an 

alternate RCPB that does not include the tube-to-tubesheet welds. The staff is currently 

reviewing this request; approval of such a request would eliminate the need to manage aging of 

the welds.

However, by teleconference on May 29, 2012, the staff requested that the applicant either 

provide the aging management program for the tube-to-tubesheet welds (which would address 

the 10 attributes of an aging management program) as part of its license renewal application or 

include the management of the tube-to-tubesheet welds as part of the steam generator aging 

management program. In addition, the staff requested that the applicant include the specific 

actions to be taken to address this issue (i.e., as identified in (1) and (2) above) as commitments 

in the UFSAR supplement. The staff also requested the applicant to clarify its plans for 

submitting the analytical evaluation in (2) above as a license amendment for NRC review and 
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approval prior to redefining the pressure boundary and to include this action as part of its

commitment in the UFSAR supplement.

The applicant indicated that it would provide additional information in a subsequent submittal. 

This issue is identified as Open Item OI 3.0.3.2.2-1. 

By letter dated December 14, 2010, the staff issued RAI B.2.10-2 requesting that the applicant 

address foreign operating experience in SGs with similar design to that of Seabrook SGs, where 

cracking due to PWSCC has been identified in SG divider plate assemblies made with Alloy 

600.

In addition, the staff requested that the applicant discuss the materials of construction of the 

Seabrook SG divider plate assemblies and an appropriate program to manage the potential 

aging effect if the divider plate assembly is made of Alloy 600 material.

In its response date January 13, 2011, the applicant stated that the Seabrook Westinghouse 

Model F SG divider plate and weld materials are Inconel (ASME-SB-168) Alloy 600/82/182. 

The applicant also stated that Seabrook will perform an inspection of each SG prior to entering 

the period of extended operation to assess the condition of the divider plate assembly unless 

operating experience or analytical results or both show that crack propagation into the RCS 

pressure boundary is not possible, then the inspections need not be performed. The applicant 

indicated that any evidence of cracking will be documented and evaluated under the Corrective 

Action Program.

After reviewing the applicant’s response to RAI B.2.10-2, the staff finds that it appears to give 

Seabrook the option of performing a one-time inspection or performing an analytical evaluation 

to assess potential crack propagation into the RCS pressure boundary. The staff discussed this 

concern with the applicant, and the applicant revised its response. In a letter dated 

March 22, 2011, the applicant amended its response to RAI B.2.10-2 by stating that Seabrook 

will perform a one-time inspection of the divider plate assembly and that any evidence of 

cracking will be documented and evaluated under the Corrective Action Program. The applicant

also indicated that any inspection techniques used will be capable of detecting PWSCC in the 

SG divider plate assemblies and their associated welds. The staff finds the applicant’s plans to 

perform a one-time inspection of each SG to assess the condition of the divider plate assembly 

acceptable because any crack present in the assembly will be detected, evaluated, and entered 

into the Corrective Action Program. Additionally, the applicant committed to performing the 

inspection prior to the period of extended operation. However, the staff requested that the 

applicant also provide information regarding its one-time inspection of the divider plate 

assembly in its UFSAR Supplement.

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

the staff finds that, pending resolution of OI 3.0.3.2.2-1, operating experience related to the 

applicant’s program demonstrates that it can adequately manage the detrimental effects of 

aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking appropriate corrective actions. The staff confirmed that, pending 

resolution of OI 3.0.3.2.2-1, the “operating experience” program element satisfies the criterion in 

SRP-LR Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.1.10 provides the UFSAR supplement for the Steam 

Generator Tube Integrity Program.
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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 3.1-2. The staff also noted that the applicant committed (Commitment Nos. 54 and 55) to 

enhance the Steam Generator Tube Integrity Program prior to entering the period of extended 

operation. Specifically, the applicant committed to the following:

• Commitment No. 54: Unless an alternative repair criteria changing the ASME Code 

boundary is permanently approved by the NRC, or the Seabrook steam generators are 

changed to eliminate PWSCC-susceptible tube-to-tubesheet welds, the applicant will 

submit a plant-specific AMP to manage the potential aging effect of cracking due to 

PWSCC at least 24 months prior to entering the period of extended operation.

• Commitment No. 55: Seabrook will perform an inspection of each steam generator to 

assess the condition of the divider plate assembly.

As discussed in the Operating Experience section above, the staff requested that additional 

information be included in the applicant's UFSAR Supplement to capture future actions 

associated with Commitments Nos. 54 and 55. The staff's finding regarding the adequacy of 

the UFSAR supplement, as required by 10 CFR 54.21(d), is pending resolution of 

OI 3.0.3.2.2-1.

Conclusion

3.0.3.2.3 Open-Cycle Cooling Water System Program

. The staff's finding and conclusion regarding the applicant’s Steam Generator Tube 

Integrity Program is pending resolution of OI 3.0.3.2.2-1.

Summary of Technical Information in the Application

• surveillance and control of aging mechanisms

. LRA Section B.2.1.11 describes the 

existing Open-Cycle Cooling Water System Program as consistent, with an exception, with 

GALL Report AMP XI.M20, “Open-Cycle Cooling Water System.” The applicant stated that the 

Open-Cycle Cooling Water System Program manages elastomer degradation, reduction of heat 

transfer, and loss of material due to erosion, corrosion, and fouling. The applicant also stated 

that the program relies on the implementation of the recommendations of NRC GL 89-13, 

“Service Water System Problems Affecting Safety-Related Equipment.” The applicant stated 

that the program includes the following:

• tests to verify heat transfer

• routine inspection and maintenance of plant components

• system walkdowns to ensure compliance with the station’s licensing basis

• a review of maintenance, operating, and training practices and procedures to ensure the 

effectiveness of established programs

The applicant stated that the micro- and macro-biological fouling is controlled by its Chlorine 

Management Program. The applicant further stated that a variety of inspection and testing 

methods are used including visual, eddy current, and ultrasonic tests on plant heat exchangers 

and piping.

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.
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The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M20. 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.M20, with the exception of the “scope of program” program element. For 

this element, the staff determined the need for additional clarification, which resulted in the 

issuance of an RAI.

GALL Report AMP XI.M20 recommends that the program address the aging effects of material 

loss and fouling due to micro- or macro-organisms and various corrosion mechanisms. During 

its audit, the staff found that the applicant will manage hardening and loss of strength due to 

elastomer degradation. During onsite discussions, the applicant stated that this aging effect 

would be managed by visual inspections. However, the staff considers the detection of 

hardening or loss of strength due to elastomer degradation to be impractical without some type 

of physical manipulation of the components being managed. It was unclear how the 

Open-Cycle Cooling Water System Program would manage this aging effect by visual 

inspections only.

By letter dated December 14, 2010, the staff issued RAI B.2.1.11-1, requesting that the 

applicant provide the technical basis for how hardening and loss of strength due to elastomer 

degradation will be managed by the Open-Cycle Cooling Water System Program. 

In its response dated January 13, 2011, the applicant provided changes to LRA

Section B.2.1.11, which included physical or manual manipulation of elastomers to detect 

hardening and loss of strength due to elastomer degradation. The staff finds this response 

acceptable because the applicant’s modification to its program includes new techniques that are 

appropriate for detecting the hardening and loss of strength of elastomers. The staff’s concern 

described in RAI B.2.1.11-1 is resolved.

The staff also reviewed the portions of the “preventive actions” program element associated with 

the exception to determine if the program will be adequate to manage the aging effects for 

which it is credited. The staff’s evaluation of this exception follows.

Exception

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because it has unlined piping in the open-cycle cooling water system. The staff noted 

that GALL Report AMP XI.M20 states that components are lined or coated to protect the 

underlying metal surfaces. The staff evaluated the materials used in the unlined portions of 

open-cycle cooling water system. The staff reviewed the corrosivity of the materials in seawater 

using the American Society for Metals (ASM) international data and noted that the cited 

materials have low corrosion susceptibility in seawater. The staff finds the program’s exception 

acceptable because the materials used by the applicant are resistant to the aggressive cooling 

water environment and preclude the need for being lined or coated to protect the metal surface.

. LRA Section B.2.1.11 states an exception to the “preventive actions” program 

element. The LRA states that the open-cycle cooling water system includes both unlined and 

lined piping. The applicant stated that the unlined materials used in the system include Inconel, 

copper-nickel, aluminum-bronze, and stainless steels, which were specifically selected for their 

resistance to the effects of salt water. The applicant stated that, because of the material 

resistance, the Open-Cycle Cooling Water System Program will be able to manage unlined 

piping as well as lined piping.

Based on its audit and review of the applicant’s response to RAI B.2.1.11-1, the staff finds that 

elements one through six of the applicant’s Open-Cycle Cooling Water System Program, with 
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acceptable exception, are consistent with the corresponding program elements of GALL Report 

AMP XI.M20 and, therefore, are acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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.

. LRA Section B.2.1.11 summarizes operating experience related to the 

Open-Cycle Cooling Water System Program. The applicant stated that because of leakage 

problems, it had replaced the 90-10 CuNi tubing in the primary component cooling water system 

heat exchangers with titanium. According to the applicant, followup eddy current inspections 

have shown that the leakage problems had been resolved. The applicant also stated that it 

identified seawater intrusion through gaps in the service water cement-lined joints. The 

applicant stated it refurbished the joints with flexible rubber leak seals and that followup 

inspections had confirmed that the seals had been effective in preventing further corrosion.

The Operating Experience section for this program noted that the aboveground cement-lined 

piping associated with the diesel generator heat exchangers had been replaced with Plastisol 

polyvinyl chloride (PVC)-lined carbon steel piping and that follow-up examinations had 

confirmed that the engineering design change was effective in preventing loss of material. 

However, based on information provided by Regional staff in late 2011, the PVC lining had 

degraded to the extent that it was missing in certain portions of the piping and, according to the 

applicant, pieces of the lining had detached and partially restricted flow to a diesel generator 

heat exchanger. As part of the normal Reactor Oversight Process, Regional staff followed up 

on the applicant’s operability evaluation, root cause determination, and corrective actions 

associated with this event. The Regional staff subsequently documented a violation of very low 

safety significance (Green) for a violation of 10 CFR 50, Appendix B, Criterion III, “Design 

Control,” for several aspects of the design change 93DCR003, which installed the PVC-lined 

piping. The Regional staff’s inspection activities associated with this event are documented in 

Inspection Reports (IR) 443/2011004, dated November 4, 2011, and IR 443/2011005, dated 

February 14, 2012.

By letter dated December 12, 2011, the staff issued RAI B.2.1.11-2, requesting the applicant to 

describe the recent PVC lining degradation and to discuss any previous aging management 

activities that were performed to manage liner degradation prior to the event. In addition, the 

staff requested the applicant to describe corrective actions taken in response to this event and 

to provide any enhancements made to the AMP to ensure components’ intended functions will 

not be impacted during the period of extended operation.

In its response dated February 7, 2012, the applicant described the PVC lining degradation 

event, including its associated root cause evaluation, discussed the previous aging 

management activities for this portion of the piping, and described the corrective actions taken 

as a result of this event. The applicant’s evaluation identified two root causes for this event.

(1) A limited life design change was implemented in 1994 with no provisions to formally 

track the periodic verification of the coating condition. The PVC lining material had a 

15-year service life.
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(2) Oversight of the service water system was not adequate due to a lack of compliance 

with the system performance monitoring guideline requirements associated with the 

PVC-lined pipe.

With respect to previous aging management activities, the applicant stated that following its 

installation in 1994, the PVC-lined piping was inspected in each outage from 1996 through 2003 

with no significant indications of liner degradation. However, inspection notes in 2002 stated 

there was a lack of adhesion of the liner to the pipe surface. After 2003, periodic inspection of 

the PVC-lined piping was discontinued in favor of a new long-term inspection strategy, which 

focused on the service water system as a whole, and the PVC-lined piping was not singled out 

for more frequent inspections. The next inspection of the PVC-lined piping was scheduled for 

the refueling outage in 2012.

With respect to corrective actions taken in response to this event, the applicant stated that a 

design change will be developed to replace the PVC-lined piping in 2012 with a 

corrosion-resistant, unlined material, and that the associated service water piping will be 

periodically inspected to verify adequate pipe wall thickness. In addition, as part of the extent of 

condition evaluation, the applicant assigned actions to evaluate the concrete-lined piping in the 

screen wash and circulating water systems to determine liner adequacy and to determine if 

other coatings used in the service water system have service life limitations. Further, the 

applicant stated that corrective actions have been assigned to revise the design control process 

to utilize the preventive maintenance process for inspections and replacement activities and to 

establish a process to ensure that monitoring and inspection programs comply with system 

performance monitoring guidelines and that long-term strategies comply with regulatory 

commitments such as GL 89-13, “Service Water System Problems Affecting Safety-Related 

Equipment.” The applicant concluded that since the AMP has provision for managing protective 

coatings, enhancements are not required. 

The staff reviewed the applicant’s response and noted that several corrective actions have not 

been implemented. With regard to the Open-Cycle Cooling Water System Program, the staff 

noted that the replacement of the PVC-lined piping is scheduled for later in 2012, and activities 

associated with the following items are still pending: 

• implement a process to ensure that monitoring and inspection programs comply with 

performance monitoring guidelines 

• implement a process to ensure that long-term strategies comply with GL 89-13, 

• determine liner adequacy in the screen wash and circulating water systems 

• determine if other coatings in the service water system have service life limitations 

The staff considered completion of these activities as providing reasonable assurance that the

program can adequately manage the detrimental effects of aging on SSCs within the scope of 

the program. As discussed above, the applicant’s corrective action activities are being 

addressed through the Reactor Oversight Process; however, because these activities directly 

affect the Open-Cycle Cooling Water System Program, the staff considers that these activities 

should be captured in a commitment. During a teleconference on April 10, 2012, the applicant 

agreed to complete the above activities prior to the period of extended operation. 

In fact, by letter dated April 26, 2012, the applicant revised its response to RAI B.2.1.11-2 by 

stating that it had completed implementation of the process to ensure that monitoring and 

inspection programs comply with system performance guidelines and that long-term strategies 
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comply with commitments made for GL 89-13. Regarding the adequacy of the liner in the 

screen wash and circulating water systems, the applicant stated that both systems have cement 

lining similar to the service water system and that inspections of the lining are conducted 

through the Open-Cycle Cooling Water System program for those portions that are within the 

scope of GL 89-13, or otherwise, through the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program.

Regarding other coatings in the service water system that may have service life limitations, the 

applicant stated that an engineering evaluation in 1993 had determined Belzona products, 

which are polymeric materials used for lining and liner repairs, have an expected service life of 

15 years. The applicant added that it had reviewed its operating experience database and had 

not identified failures of Belzona products due to exceeding its service life. The applicant stated 

that the extent of use of Belzona and polyurethane coatings has been identified and is being 

tracked in the Service Water Inspection and Repair Trending Program, and that preventive 

maintenance activities ensure that inspections are scheduled and tracked. 

Regarding the replacement of the PVC-lined piping, the applicant added Commitment No. 69 to 

LRA Section A.3, “License Renewal Commitment List,” to replace the PVC-lined diesel 

generator heat exchanger service water piping with pipe fabricated from AL6XN material, prior 

to the period of extended operation. The applicant noted that this material is treated as 

stainless steel and is included in the existing AMR item to be managed for aging for piping and 

fittings in LRA Table 3.3.2-37 for the service water system.

The staff finds the applicant’s response to RAI B.2.1.11-2 acceptable because the applicant 

provided sufficient details of its corrective actions for process improvements and program 

changes that address the failure of PVC-lined piping. In addition, the applicant’s commitment to 

replace the PVC-lined piping prior to the period of extended operation resolves the specific 

operating experience issue, because the replacement piping is not lined, the replacement 

material has low corrosion susceptibility to seawater, and the piping will be managed in the 

same manner as other stainless steel components in the system. The staff’s concern described 

in RAI B.2.1.11-2 is resolved.

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

RAI B.2.1.11-2, the staff finds that operating experience related to the applicant’s program 

demonstrates that it can adequately manage the detrimental 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. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.1.11 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 conforms to the recommended description for this 

type of program, as described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. The staff also noted 

that the applicant committed (Commitment No. 69) to replace the PVC-lined service water 

piping for the diesel generator heat exchanger prior to the period of extended operation. 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 applicant’s Open-Cycle Cooling Water 

System Program, the staff determined that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exception and its justification and determined that the AMP, with the exception, is adequate to 
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manage the aging effects for which the LRA credits it. The staff concludes that the applicant 

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 Closed-Cycle Cooling Water System Program

Summary of Technical Information in the Application. LRA Section B.2.1.12 describes the 

existing Closed-Cycle Cooling Water System Program as consistent, with exceptions and an 

enhancement, with GALL Report AMP XI.M21, “Closed-Cycle Cooling Water System.” The 

applicant stated that this program manages the aging effects of cracking due to stress corrosion 

cracking (SCC), loss of material due to general, crevice, pitting, and galvanic corrosion, and 

reduction of heat transfer due to fouling. The applicant also stated that the program scope 

includes the primary component cooling water system, emergency diesel generator jacket water 

cooling system, fire pump diesel engine glycol coolant system, control building air handling 

glycol coolant system, and thermal barrier cooling water system. The applicant stated that it 

uses either a hydrazine chemistry or a mixed glycol chemistry to control aging in the various 

closed-cycle systems. The applicant further stated that it implements EPRI 1007820, “Closed 

Cooling Water Chemistry Guideline, Revision 1,” to monitor and control the cooling water 

chemistry. The applicant stated that it uses corrosion test coupons to check the effectiveness of 

the inhibitor and corrosion rates.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M21. 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.M21, with the exception of the “preventive actions” and “acceptance 

criteria” program elements. For these elements, the staff determined the need for additional 

clarification, which resulted in the issuance of RAIs.

. 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 GALL Report AMP XI.M21 states that the closed-cycle cooling water system corrosion 

inhibitor concentrations should be maintained within the specified limits of the EPRI guideline. 

However, during its audit, the staff found that the applicant’s diesel generator cooling water 

jacket system, (a blended glycol formulation) only has a pH Action Level 2, and does not identify 

an Action Level 1 for pH. Action levels are actions to be taken upon reaching a chemistry range 

level that is above the normal range level. It was not clear to the staff why the applicant’s onsite 

guidelines for the diesel generator cooling water jacket is not consistent with the EPRI guideline 

by having two action levels for pH. By letter dated December 14, 2010, the staff issued 

RAI B.2.1.12-2 requesting that the applicant justify why the pH action levels for the diesel 

generator cooling water jacket are not consistent with those found in the EPRI guideline. In its 

response dated January 13, 2011, the applicant added Commitment No. 57 in LRA Appendix A, 

to revise the program documents to reflect the EPRI guideline’s operating ranges and action 

level values for the diesel generator cooling water jacket pH. The staff finds this response 

acceptable because adding the pH Action Level 1, in accordance with the EPRI guideline, will 

ensure that the identification of pH levels outside the normal operating range will initiate 

appropriate actions. The staff’s concern described in RAI B.2.1.12-2 is resolved.
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The GALL AMP XI.M21 recommends that acceptance criteria for performance tests be based 

on system and component design basis requirements under the “acceptance criteria” program 

element. However, the applicant stated that it does not plan to use performance tests to confirm 

the effectiveness of the program and instead will rely upon corrosion coupons and internal 

visual inspections. The staff noted that the applicant’s “acceptance criteria” program element 

did not include criteria to evaluate the results from the corrosion coupon surveillances and visual 

inspections. By letter dated December 14, 2010, the staff issued RAI B.2.1.12-4 requesting that 

the applicant provide the acceptance criteria that will be used for the corrosion coupon and 

visual inspection surveillance activities. 

Prior to responding to RAI B.2.1.12-4, the staff guidance in GALL Report Revision 2, 

AMP XI.M21A on conducting performance tests for the Closed-Cycle Cooling Water Program 

was removed. The current staff guidance in the GALL Report states that the Closed-Cycle 

Cooling Water Program includes (a) water treatment, including the use of corrosion inhibitors, to 

modify the chemical composition of the water such that the function of the equipment is 

maintained and such that the effects of corrosion are minimized, (b) chemical testing of the 

water, and (c) inspections to determine the presence or extent of corrosion and/or cracking. 

The “parameters monitored/inspected” program element of GALL AMP XI.M21A state that the 

program monitors water chemistry and the visual appearance of surfaces exposed to the water, 

and that corrosion monitoring by coupon testing may be included. The “detection of aging 

effects” program element of GALL AMP XI.M21A states that if visual inspections identify 

adverse conditions, additional examinations are conducted. In its response dated 

January 13, 2011, the applicant revised LRA Section B.2.1.12 to state that personnel 

completing inspections under the Closed-Cycle Cooling Water System Program will be trained 

to identify parameters associated with the aging effects being monitored by the program. The 

revised section referred to the EPRI training program, “Identification and Detection of Aging 

Issues,” and stated that it is supplemented with the EPRI “Aging Assessment Field Guide,” and 

“Aging Identification and Assessment Checklists for Mechanical Components.” The applicant 

stated that the nuclear industry has collected information on how to identify if an aging effect is 

occurring and has developed training programs on how to correlate the observed condition to a 

possible aging effect. The applicant also stated that this training will ensure that these 

inspections will adequately address potential aging effects and associated acceptance criteria 

for the in-scope material. The applicant further stated that adverse or potentially adverse 

conditions identified during the visual inspections will be documented and evaluated in 

accordance with the corrective actions program and that system components must meet design 

requirements such as minimum wall thickness. The staff finds this response acceptable 

because:

• the Closed-Cycle Cooling Water Program includes visual inspections,

• inspectors are trained to observe for visual indications of adverse or potentially adverse 

conditions using industry standard guidelines,

• adverse or potentially adverse conditions will be evaluated under the corrective action 

program,

• the acceptance criterion for the evaluations is that system components must meet 

design requirements such as minimum wall thickness, and

• as allowed by SRP-LR A.1.2.3.6, it is not necessary to discuss CLB design loads if the 

acceptance criteria of the inspections do not permit degradation.
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Given that GALL Report Revision 2, AMP XI.M21A recommends that corrosion coupon testing 

is an option in addition to visual inspections and the applicant’s response is consistent with 

GALL AMP XI.M21A and the SRP-LR, the staff’s concern described in RAI B.2.1.12-4 is 

resolved.

The GALL Report AMP XI.M21 states that the Closed-Cycle Cooling Water System Program 

includes preventive measures, testing, and inspection to both minimize and monitor corrosion. 

The GALL Report indicates that closed-cycle cooling water systems can undergo aging due to 

loss of material from microbiologically-influenced corrosion. The applicant’s program states that 

it manages cracking due to SCC; loss of material due to general, crevice, pitting, and galvanic 

corrosion; and reduction of heat transfer due to fouling. However, it was not clear if the 

applicant uses the Closed-Cycle Cooling Water System Program to manage aging from 

microbiologically-influenced corrosion. By letter dated January 21, 2011, the staff issued 

RAI B.2.1.12-7 requesting that the applicant justify why the Closed-Cycle Cooling Water System 

Program does not need to manage microbiologically-influenced corrosion in the closed-cycle

cooling water systems. The applicant was further requested to identify what preventive actions, 

parameters monitored or inspection techniques are being conducted if 

microbiologically-influenced corrosion is being managed by the Closed-Cycle Cooling Water 

System Program. In its response dated February 18, 2011, the applicant stated that the GALL 

Report, Revision 1 and Revision 2, did not include any items for PWRs; therefore, it did not 

consider microbiologically-influenced corrosion to be an aging effect requiring management. 

The applicant reiterated that the Closed-Cycle Cooling Water System Program does not 

manage loss of material for this mechanism. However, the applicant also stated that its 

closed-cycle cooling chemistry control procedure does include biological activity as a 

recommended parameter in keeping with the EPRI guideline. In addition, the applicant stated 

that its review of plant-specific operating experience did not identify any 

microbiologically-influenced corrosion issues in the close-cycle cooling water systems.

In its review of the applicant’s response, the staff noted that microbiologically-influenced

corrosion is a stated concern in the EPRI guideline for closed-cycle cooling systems using glycol 

formulations, and since these systems can be found in both boiling-water reactors (BWRs) and 

PWRs, the applicant’s determination that this aging mechanism was not applicable to PWRs is 

without merit. The staff noted that the applicant’s lack of plant-specific operating experience 

associated with microbiologically-influenced corrosion may be attributable to the existing 

additives that mitigate this mechanism. However, SRP-LR Section A.1.2.1, “Applicable Aging 

Effects,” states the following:

An aging effect should be identified as applicable for license renewal even if 

there is a prevention or mitigation program associated with that aging effect. For 

example, water chemistry, a coating, or use of cathodic protection could prevent 

or mitigate corrosion, but corrosion should be identified as applicable for license 

renewal, and the AMR should consider the adequacy of the water chemistry, 

coating, or cathodic protection as an aging management program.

Given this basis, the applicant did not provide reasonable assurance that loss of material due to 

microbiologically-influenced corrosion does not need to be included as part of the Closed-Cycle 

Cooling Water System Program. By letter dated May 23, 2011, the staff issued RAI B.2.12-9 

requesting that the applicant provide plant-specific data to demonstrate that the lack of 

microbiologically-influenced corrosion cannot be attributed to the existing chemical treatment in 

the closed cooling water systems.
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In its response dated June 2, 2011, the applicant stated that its program complies with the 

EPRI 1007820, “Closed Cooling Water Chemistry Guideline.” The applicant also stated that it 

takes no exception relative to testing for microbiological activity and that its operating 

procedures include testing for biological activity as a diagnostic parameter. The applicant 

revised LRA Sections A.2.1.12 and B.2.1.12 to state that glycol containing systems within the 

scope of the Closed-Cycle Cooling Water System Program are monitored for the presence of 

microbiological activities in accordance with the EPRI Closed Cooling Water Chemistry 

Guideline. The staff finds this response acceptable because the applicant has modified its 

program documents to clarify that glycol systems are being managed for 

microbiologically-influenced corrosion, consistent with EPRI guidelines. The staff’s concerns

described in RAIs B.2.1.12-7 and B.2.1.12-9 are 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 exceptions and 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 

these exceptions and an enhancement follows.

Exception 1

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because the GALL Report is based on the earlier version of the EPRI guideline rather 

than the one used by the applicant. The staff finds the program exception acceptable because 

the updated EPRI guideline for the closed cooling water chemistry accounts for more recent 

operating experience and specifies equivalent guidance for corrosion inhibitor concentrations as 

those specified in TR-107396.

. LRA Section B.2.1.12 states an exception to the “preventive actions,” “monitoring 

and trending,” and “acceptance criteria” program elements. The applicant stated that it took an 

exception to the use of the EPRI TR-107396, “Closed Cooling Water Chemistry Guideline,” that 

was issued in 1997, because it uses the updated version, EPRI 1007820, “Closed Cooling 

Water Chemistry Guideline, Revision 1,” which was issued in 2004. The applicant stated that 

the updated version meets the same requirements of EPRI TR-107396 for maintaining 

conditions to minimize corrosion and microbiological growth.

Exception 2

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because an ongoing operational problem had caused more frequent chemical 

additions, resulting in increased worker radiation exposure. However, the applicant’s technical 

basis documents did not discuss how copper corrosion was evaluated or the basis for why it is 

appropriate to have a higher hydrazine levels in its thermal barrier system than recommended in 

the EPRI guideline. The staff noted that the EPRI guideline discussed the susceptibility to SCC 

of some copper alloys exposed to ammonia, which can occur when hydrazine is exposed to air. 

By letter dated December 14, 2010, the staff issued RAI B.2.1.12-1 requesting that the applicant 

. LRA Section B.2.1.12 states an exception to the “preventive actions,” “monitoring 

and trending,” and “acceptance criteria” program elements. The applicant stated that instead of 

limiting the normal operating range for hydrazine to the EPRI guidance maximum concentration 

of 200 ppm, the thermal barrier cooling water system is specified with a maximum of 300 ppm. 

The applicant also stated that this higher limit was established to minimize radiation exposure, 

which resulted from an ongoing hydrazine consumption issue apparently due to an unvented air 

problem. The applicant further stated it had determined that the higher concentration level was 

acceptable, based on a review of the potential effects on components, which included corrosion 

rate monitoring through corrosion coupons in the system.
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provide justification for the higher hydrazine levels in the thermal barrier system compared to 

what is recommended in the EPRI guideline and why these higher levels will not lead to 

enhanced degradation. In addition, the staff requested that the applicant provide information of 

the effect on aging if hydrazine concentrations were to increase above the normal operating 

range in the EPRI guideline during the period of extended operation.

In its response dated January 13, 2011, the applicant added Commitment No. 56 to LRA 

Appendix A, to revise the program documents to reflect the EPRI guideline operating ranges 

and action level values for hydrazine. Consequently, the applicant deleted Exception 2 from this 

AMP in the LRA, since an exception was not being taken. The applicant also stated that it 

evaluated the significance of allowing the system to operate with the higher hydrazine levels 

and determined it to be acceptable. Similarly, the applicant stated that it routinely monitored the 

operation during elevated ranges, and there were no indications of system of component 

degradation. In its review of this response, the staff did not consider that there was sufficient 

information regarding how the monitoring during elevated hydrazine levels had determined there 

were minimal long-term aging effects of copper components in the thermal barrier system. 

By letter dated March 7, 2011, the staff issued RAI B.2.1.12-8 requesting that the applicant 

provide the technical information that describes why the elevated levels of hydrazine will not 

have caused accelerated aging of the components in the thermal barrier system that could 

affect component functions during the period of extended operation. The applicant was also 

asked to provide information on the AMP that will be used to manage the accelerated aging if it 

is determined that the elevated levels of hydrazine may have caused accelerated aging.

In its response, dated April 5, 2011, the applicant stated the higher sulfate and hydrazine levels 

were not expected to increase the corrosion rate of any copper alloys because the thermal 

barrier system is an all ferrous design. The applicant stated that the increased level of 

hydrazine and sulfate would not lead to an increased corrosion rate for either stainless steel or 

carbon steels because the higher level of hydrazine would lead to a low oxygen concentration 

and low electrochemical potential for stainless steel components. The staff finds this response 

acceptable because the applicant clarified that there are no copper components that could have 

an increased corrosion rate due to the higher level of ammonia. In addition, the staff noted that 

the higher levels of hydrazine will decrease the concentration of oxygen, which will lead to a 

decreased corrosion rate for carbon alloys. The staff further noted that a lower oxygen level will 

also reduce the electrochemical potential of any stainless steel components, which will reduce 

the likelihood of SCC even at the higher levels of sulfate for the temperature normally observed 

in the thermal barrier system. The staff’s concern described in RAIs B.2.1.12-1 and B.2.1.12-8 

is resolved.

Exception 3

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception regarding the higher limit to the sulfate operating range because the previous EPRI 

guideline did not specify this value. The applicant further stated that it evaluated the 

significance of operating the system at the higher concentration level and determined it to be 

acceptable because of lower oxygen levels, alkaline pH, and absence of sulfides in the thermal 

barrier cooling water system. However, the applicant’s technical basis documents did not justify 

why it is appropriate to have higher sulfate levels in its thermal barrier system than is 

. LRA Section B.2.1.12 states an exception to the “preventive actions” and 

“monitoring and trending” program elements. The applicant stated that the EPRI guideline 

specifies Action Level 1 for sulfates as a concentration greater than 150 ppb. The applicant 

further stated that the thermal barrier cooling water system has an Action Level 1 of 500 ppb.
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recommended by the EPRI guideline. By letter dated December 14, 2010, the staff issued 

RAI B.2.1.12-1 requesting that the applicant justify the higher sulfate levels in the thermal barrier 

system compared to those recommended in the EPRI guideline, and to discuss why these 

higher levels will not lead to enhanced degradation. In addition, the staff requested that the 

applicant provide information for the effects on aging if sulfate concentrations were increased 

above the action level in the EPRI guideline during the period of extended operation.

In its response dated January 13, 2011, the applicant added Commitment No. 56 to LRA 

Appendix A, to revise the program documents to reflect the EPRI guideline operating ranges 

and action level values for sulfates. Consequently, the applicant deleted Exception 3 to this 

AMP in the LRA, since an exception was no longer being taken. The evaluation of the potential 

for elevated sulfate levels in the past to have accelerated aging effects was included in 

RAIs B.2.1.12-1 and B.2.1.12-8, and the staff’s findings are discussed above in the evaluation 

for Exception 2.

Exception 4

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because the thermal barrier cooling water system is located inside containment, and 

monitoring monthly would reduce the radiation exposure. The staff reviewed the hydrazine and 

pH data trends during the audit, which showed that these parameters are stable and 

predictable. The staff finds this program exception acceptable because the hydrazine data 

trends indicate that a monthly measurement rate is frequent enough to maintain the hydrazine 

within acceptable bounds.

. LRA Section B.2.1.12 states an exception to the “parameters monitored or 

inspected” and “monitoring and trending” program elements. The applicant stated that the EPRI 

guideline indicates that hydrazine concentrations and pH should be monitored weekly. In 

contrast, the applicant stated that, for the thermal barrier cooling water system, it would monitor 

hydrazine and pH monthly to reduce worker radiation exposure. The applicant further stated 

that recent system data trends show that hydrazine concentration and pH remained stable 

between the monthly samples, which demonstrates that monthly monitoring frequency is 

sufficient.

Exception 5

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because it considered the performance and functional testing to fall under the 

maintenance rule. However, it was not clear to the staff whether the applicant was crediting 

maintenance rule activities to manage aging effects in the closed-cycle cooling water system 

during the period of extended operation and, if so, how these activities are captured in an AMP. 

By letter dated December 14, 2010, the staff issued RAI B.2.1.12-3 requesting that the applicant 

explain how the maintenance rule activities are included in the aging management of the 

closed-cycle cooling water systems during the period of extended operation.

. LRA Section B.2.1.12 states an exception to the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements. The applicant stated that it does not rely on performance and functional 

testing to verify the effectiveness of chemistry controls and managing aging effects, as stated in 

the GALL Report. Instead, the applicant stated that it monitors program effectiveness through 

internal inspections of opportunity and through corrosion monitoring by trending normal plant 

periodic samples and by evaluating system corrosion coupons.

In its response dated January 13, 2011, the applicant stated that the maintenance rule activities 

are not being credited to manage aging effects in the closed-cycle cooling water system during 

the period of extended operation. The applicant stated that it modified its program to remove 
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the reference to the maintenance rule and that the performance monitoring is part of the 

engineering program that verifies the component active functions. The staff finds this response 

acceptable because the applicant modified its program to remove documentation that reports 

the maintenance rule is part of the activities for managing aging in the closed-cycle cooling 

water systems. The staff’s concern described in RAI B.2.1.12-3 is resolved.

The staff also examined the use of corrosion coupons, and it was not clear from the basis 

documents that the corrosion coupons would be placed in a condition representative of the most 

detrimental environment for a given closed-cycle system (highest temperature, stagnant 

conditions, etc.). In addition, it was not clear if the corrosion coupons would be stressed, which 

is necessary to evaluate SCC. By letter dated December 14, 2010, the staff issued 

RAI B.2.1.12-5 requesting justification on how the corrosion coupons will represent high 

susceptible material and environmental conditions observed in a closed-cycle cooling water 

system. The applicant was also asked to provide additional information on why the corrosion 

coupons are adequate to evaluate SCC susceptibility.

In its response dated January 13, 2011, the applicant stated corrosion coupon monitoring will be 

used to assess the effectives of the corrosion inhibitors by quantifying the corrosion rates of the 

coupons. The applicant stated that the current location in the coupons in the closed-cycle 

cooling water system is appropriate for monitoring the effectiveness of corrosion inhibitors. The 

applicant further stated that the corrosion coupons are not pre-stressed and are not used for 

monitoring SCC. The applicant stated that SCC will be evaluated by conducting visual 

inspection of individual components for evidence of pitting, general corrosion film presence, 

biological activities, deposits, and SCC. The staff finds the response and program exception 

acceptable because the applicant has modified the program to indicate that SCC will be 

managed by visual inspections, and the corrosion coupons are placed in the appropriate 

locations to evaluate the effectiveness of corrosion inhibitors. The staff’s concern described in 

RAI B.2.1.12-5 is resolved.

Enhancement 1

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M21. The staff noted that the GALL Report AMP states that the extent and 

schedule of inspections and testing should assure detection of corrosion or SCC before the loss 

of the intended function of the component. The staff finds the applicant’s enhancement 

acceptable because it provides an alternative technique to verify the effectiveness of the control 

of water chemistry to manage aging in the closed-cycle cooling water systems.

. LRA Section B.2.1.12 states an enhancement to the “detection of aging 

effects” program element. The applicant stated that the program will be enhanced to include 

visual inspections for cracking, loss of material, and fouling in the primary component cooling 

water system, thermal barrier cooling water system, diesel generator jacket water cooling 

system, fire water pump diesel engine coolant system, and control building air handling coolant 

system.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.12-1, B.2.1.12-2, 

B.2.1.12-3, B.2.1.12-4, B.2.1.12-5, B.2.1.12-7, B.2.1.12-8 and B.2.1.12-9, the staff finds that 

elements one through six of the applicant’s Closed-Cycle Cooling Water System Program, with 

acceptable exceptions and an enhancement, are consistent with the corresponding program 

elements of GALL Report AMP XI.M21 and, therefore, acceptable.

Operating Experience. LRA Section B.2.1.12 summarizes operating experience related to the 

Closed-Cycle Cooling Water System Program. The applicant stated that, in 2003, the chemistry 

department identified that the hydrazine consumption in the thermal barrier cooling water 
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system had significantly increased since the fall of 2000. The applicant stated that an 

investigation identified potential air entrapment in the thermal barrier cooling water system. The 

applicant stated that it statically and dynamically vented the thermal barrier cooling water 

system, which resolved the issue. In addition to this one operating experience, the applicant 

stated that, in 2003, it reviewed industry operating experience about an issue with cracking of 

brass bolting in the diesel generator jacket water cooling system. The applicant further stated 

that this evaluation showed that Seabrook uses a glycol mixture, which is similar in constituents 

to the industry operating experience conditions but that Seabrook uses a much higher 

concentration. The applicant stated that this evaluation concluded that Seabrook’s tolytriazole 

dosage levels are sufficient to minimize brass degradation. The applicant also stated that this 

evaluation shows it uses industry experience to challenge existing program practices and 

validates existing program procedures through experiences or standards applied at other 

nuclear power plants.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated operating 

experience related to this program. During its review, the staff identified operating experience,

which could indicate that the applicant’s program may not be effective in adequately managing 

aging effects during the period of extended operation. The staff determined the need for 

additional clarification, which resulted in the issuance of an RAI.

In LRA Section B.2.1.12, the applicant stated that it had addressed operating experience related 

to the closed-cycle cooling water systems. However, the staff found that the applicant had not 

addressed a recurring condition in the primary component cooling water system, where loss of 

material downstream of valves was causing cavitation erosion from throttling. The applicant 

stated it had conducted flow rebalancing to alleviate the concern. However, it was unclear to 

the staff how the applicant has re-evaluated these areas after flow rebalancing was conducted 

to determine whether loss of material due to cavitation erosion remains an issue in the primary 

component cooling water system. By letter dated December 14, 2010, the staff issued 

RAI B.2.1.12-6 requesting that the applicant provide additional information on how the loss of 

material due to cavitation erosion was confirmed to have been eliminated (i.e., inspection, etc.). 

If loss of material for this mechanism is still an applicable aging issue, the applicant was asked 

to provide information on how this aging effect is being managed.

In its response dated January 13, 2011, the applicant stated that it will conduct an inspection for 

loss of material prior to entering the period of extended operation. The applicant stated that the 

inspection will be performed during the 10-year period prior to the period of extended operation. 

The staff finds this response acceptable because the applicant will conduct an inspection to 

determine if the flow rebalancing has eliminated the cavitation-induced wear. However, the staff 

considers that these activities should be captured in a commitment, and during a teleconference 

on April 10, 2012, the applicant agreed to revise its response to RAI B.2.1.12-6. By letter dated 

April 26, 2012, the applicant added a new commitment (Commitment No. 70) to inspect the 

piping downstream of valves CC-V-444 and CC-V-446 within 10 years prior to the period of 

extended operation to determine whether the loss of material due to cavitation-induced erosion 

has been eliminated. The staff’s concern described in RAI B.2.1.12-6 is resolved.

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

RAI B.2.1.12-6, the staff finds that operating experience related to the applicant’s program 
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demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking appropriate corrective actions. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

The staff also notes that the applicant committed (Commitment Nos. 2, 56, 57, and 70) to 

enhance and revise the Closed-Cycle Cooling Water System Program prior to entering the 

period of extended operation. Specifically, the applicant committed to enhance the program to 

include visual inspection for cracking, loss of material, and fouling when the in-scope systems 

are opened for maintenance; to revise program documents to reflect EPRI Guideline operating 

ranges and action levels for hydrazine, sulfates, and diesel generator cooling water jacket pH;

and to confirm that loss of material due to cavitation erosion has been eliminated in the system. 

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).

. LRA Section A.2.1.12 provides the UFSAR supplement for the 

Closed-Cycle Cooling Water System 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 Tables 3.1-2, 3.2-2, 3.3-2, and 3.4-2.

Conclusion

3.0.3.2.5 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program

. On the basis of its audit and review of the applicant’s Closed-Cycle Cooling Water 

System Program, the staff determined that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exceptions and their justifications and determined that the AMP, with the exceptions, is 

adequate to manage the aging effects for which the LRA credits it. Also, the staff reviewed the 

enhancement and confirmed that its implementation through Commitment Nos. 2, 56, 57, and 

70 prior to the period of extended operation would make the existing AMP consistent with the 

GALL Report AMP to which it was compared. 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).

Summary of Technical Information in the Application. LRA Section B.2.1.13 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 applicant stated that the program manages the aging effects of loss of material due to 

general corrosion on structural steel members, components, and rails of the in-scope cranes 

and the aging effects of loss of material due to wear on the rails in the rail system. The 

applicant also stated that the program conducts visual inspections to identify aging effects prior 

to loss of function in accordance with its Lifting System Manual. The applicant further stated 

that these inspections are conducted yearly and documented on work orders.
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Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M23. As discussed in the audit report, the staff confirmed 

that these elements are consistent with the corresponding elements of GALL Report 

AMP XI.M23.

. 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 also reviewed the portions of the “scope of program,” “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.

Enhancement 1

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M23 and noted that GALL Report AMP XI.M23 recommends that the program 

manage general corrosion on the crane and trolley structural components and the effects of 

wear on the rails in the rail system. The staff finds the program enhancement acceptable 

because, when implemented, the program elements will be consistent with the 

recommendations in GALL Report AMP XI.M23.

. LRA Section B.2.1.13 states an enhancement to the “scope of program” and 

“parameters monitored or inspected” program elements. The LRA states that the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program’s

Lifting System Manual will be enhanced to include monitoring of general corrosion on the crane 

and trolley structural components and the effects of wear on the rails in the rail system.

Enhancement 2

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M23. During the audit, the staff reviewed the applicant’s AMP basis document 

for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program and noted that the Lifting System Manual will be enhanced to list all in-scope 

cranes for periodic inspections. This enhancement will ensure that the effects of aging will be 

managed, consistent with the CLB, for the period of extended operation. The staff finds the 

program enhancement acceptable because, when implemented, the program elements will be 

consistent with the recommendations in GALL Report AMP XI.M23.

. LRA Section B.2.1.13 states an enhancement to the “scope of program” and 

“detection of aging effects” program elements. The LRA states that the Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program’s Lifting System 

Manual will be enhanced to list additional cranes related to the refueling handling system.

Based on its audit the staff finds that elements one through six of the applicant’s Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, with 

acceptable enhancements, are consistent with the corresponding program elements of GALL 

Report AMP XI.M23 and, therefore, are acceptable.

Operating Experience. LRA Section B.2.1.13 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program. The applicant stated that there has been no history of corrosion-related degradation 

that has impaired cranes, and preventive maintenance work orders are used for tracking, 

identifying, and maintaining crane structural components of lifting systems and crane rail 

systems. During the audit, the staff reviewed an operating experience example described in a 
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condition report, indicating that the bus work track of the filter cask monorail hoist system was 

severely pitted from excessive corrosion. The staff reviewed the applicant’s inspection findings 

and found that, during the inspection, corrosion was not observed on the rails and structural 

components of the system, which are the portions of the system within the scope of this 

program. The applicant initiated a preventive maintenance work order, conducted a root cause 

analysis, and replaced the bus track with a corrosion-resistant material, thus demonstrating 

proper management and implementation of the program.

The staff reviewed operating experience information during the audit to determine if the 

applicable aging effects and industry and plant-specific operating experience were reviewed by 

the applicant and are evaluated in the GALL Report. As discussed in the audit report, the staff 

conducted an independent search of plant operating experience to determine if the applicant 

adequately incorporated and evaluated 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 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

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 3.3-2.

. LRA Section A.2.1.13 provides the UFSAR supplement for the Inspection 

of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program.

The staff also noted that the applicant committed (Commitment Nos. 3 and 4) to enhance the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program prior to entering the period of extended operation. Specifically, the applicant 

committed to enhance the program to monitor general corrosion on the crane and trolley 

structural components and the effects of wear on the rails in the rail system and to enhance the 

program to list additional cranes for monitoring.

The staff determined 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 applicant’s Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff 

determined 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 through Commitment Nos. 3 and 4 prior to the period of extended 

operation would make the existing AMP consistent with the GALL Report AMP to which it was 

compared. The staff concludes that the applicant 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 
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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 Compressed Air Monitoring Program

Summary of Technical Information in the Application. LRA Section B.2.1.14 describes the 

existing Compressed Air Monitoring Program as consistent, with an enhancement, with GALL 

Report AMP XI.M24, “Compressed Air Monitoring.” The applicant stated that the program 

manages the aging effects of hardening and loss of strength due to elastomer degradation; loss 

of material due to crevice, general, galvanic, and pitting corrosion; and reduction of heat transfer 

due to fouling of the plant compressed air system components. The applicant also stated that 

the program includes continuous dew point measurements, and sampling for other 

contaminants in the compressed air system is conducted on an annual basis.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M24. 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.M24, with the exception of the “parameters monitored or inspected” 

program element. For this element, the staff determined the need for additional clarification, 

which resulted in the issuance of an RAI.

. 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.

GALL Report AMP XI.M24 states that the program’s inspections need to ensure that the 

intended function of the air system is maintained under the “parameters monitored or inspected” 

program element description. The applicant’s AMP states that the program specifies 

inspections to be conducted in accordance with the New Hampshire State inspection 

requirements; however, the program does not clarify the extent of the inspection or explain 

whether they are adequate to assure that the intended function of the compressed air system is 

maintained. By letter dated November 18, 2010, the staff issued RAI B.2.1.14-1 requesting that 

the applicant provide information on how the in-scope components in the compressed air 

system will be inspected, consistent with the recommendations defined in GALL Report 

AMP XI.M24.

In its response dated December 17, 2010, the applicant stated that the program description will 

explicitly include that visual inspections are to be performed during routine maintenance 

procedures, and opportunistic inspections will be performed to identify instances of corrosion 

and the presences of contaminants in the compressed air system, containment compressed air 

system, and diesel generator compressed air system. Furthermore, the applicant removed the 

reference to the State of New Hampshire air receiver tank inspection, which is not relied on to 

meet the recommendations of GALL Report AMP XI.M24. The in-scope components were 

tabulated in the applicant’s response and are found by staff to be comprehensive.

The staff finds the applicant’s response acceptable because the program description was

modified to explicitly state adherence to the GALL Report recommendations. The staff’s 

concern described in RAI B.2.1.14-1 is resolved.

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects," and “acceptance criteria” program 

elements associated with the enhancement to determine if the program will be adequate to 
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manage the aging effects for which it is credited. The staff’s evaluation of this enhancement 

follows.

Enhancement 1

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M24. The staff noted that the applicant’s program appropriately addresses the 

detection of aging effect by combined air monitoring method so that compressed air quality is 

confirmed, and corrective actions can be initiated if indicated. The staff finds the applicant’s 

enhancement acceptable because, when conducted in addition to the continuous moisture 

monitoring of the compressed air system, the annual air quality testing provides adequate 

monitoring of compressed air quality.

. LRA Section B.2.1.14 states an enhancement to the “scope of program,” 

“preventive actions,” “parameters monitored or inspected,” “detection of aging effects,” and 

“acceptance criteria” program elements. The applicant stated that annual air quality testing for 

particulate content and volatile oil will be conducted to ensure compliance with air quality 

standards.

Based on its audit, and review of the applicant’s response to RAI B.2.1.14-1, the staff finds that 

elements one through six of the applicant’s Compressed Air Monitoring Program, with an 

acceptable enhancement, are consistent with the corresponding program elements of GALL 

Report AMP XI.M24 and, therefore, are acceptable.

Operating Experience

The applicant also stated that a minor secondary plant transient occurred due to an air leak in 

the tubing to a heater drain system level control valve. A material change from copper to 

stainless steel for smaller instrument lines was conducted to remove the material that was 

determined to be more susceptible to leakage, and inspections were conducted of critical 

air-operated valves in high risk systems to evaluate the condition of similar component and 

material combinations.

. LRA Section B.2.1.14 summarizes operating experience related to the 

Compressed Air Monitoring Program. The applicant stated that actions were taken in response 

to detected rust in an air compressor. The applicant described the detection as being part of an 

inspection during a repair of the subject compressor. The affected components were replaced, 

and the engineering analysis led to procedure modifications that isolate susceptible 

down-stream components from potentially reduced quality compressed air during compressor 

shutdowns.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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 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. The staff confirmed that the “operating experience” 
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program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment No. 5) to enhance the 

Compressed Air Monitoring Program prior to entering the period of extended operation. 

Specifically, the applicant committed to conduct annual air quality testing for particulate content 

and volatile oil. In addition, the applicant committed (Commitment No. 61) to replace the flexible 

hoses associated with the diesel generator air compressor on a frequency of every 10 years, 

beginning within 10 years prior to entering the period of extended operation.

. LRA Section A.2.1.14 provides the UFSAR supplement for the 

Compressed Air Monitoring 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 3.3-2.

The staff determined that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.7 Fire Protection Program

. On the basis of its audit and review of the applicant’s Compressed Air Monitoring 

Program, the staff determined 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 through Commitment No. 5 prior to the period of extended 

operation would make the existing AMP consistent with the GALL Report AMP to which it was 

compared. The staff concludes that the applicant 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).

Summary of Technical Information in the Application. LRA Section B.2.1.15 describes the 

existing Fire Protection Program as consistent, with enhancements, with GALL Report 

AMP XI.M26, “Fire Protection.” The applicant stated that the Fire Protection Program manages 

aging of penetration seals, fire barrier walls, ceilings, floors, and all fire-rated doors that perform 

a fire barrier function as well as the aging effects on the intended function of the fuel supply line 

to the diesel fire pumps. The applicant also stated that the program conducts detailed 

inspections and tests in accordance with its surveillance test procedures, including regular 

inspections of fire barriers, penetration seals, and fire-rated doors, and performance tests and 

flushes on fire pumps. The applicant further stated that it does not use a CO2 fire suppression 

system, and the halon fire suppression system is used in a nonsafety-related computer room in 

the control building; therefore, it is not within the scope of license renewal.

Staff Evaluation

The staff also reviewed the portions of the “parameters monitored or inspected” and “detection 

of aging effects” program elements associated with the enhancements to determine if the 

. 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 one 

through six of the applicant’s program to the corresponding elements of GALL Report 

AMP XI.M26. As discussed in the audit report, the staff confirmed that these elements are 

consistent with the corresponding elements of GALL Report AMP XI.M26.
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program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these enhancements follows.

Enhancement 1

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M26 and noted that the GALL Report recommends that penetration seals be 

visually inspected by fire protection qualified inspectors. The staff finds the program 

enhancement acceptable because, when implemented, the program element will be consistent 

with the recommendations in GALL Report AMP XI.M26.

. LRA Section B.2.1.15 states an enhancement to the “detection of aging 

effects” program element. The LRA states that the Fire Protection Program implementing 

documents will be enhanced to include visual inspection of penetration seals by a fire protection 

qualified inspector.

Enhancement 2

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M26 and noted that the GALL Report recommends that fire barrier walls, 

ceilings, and floors be visually inspected for cracking, spalling, and loss of material caused by 

freeze-thaw, chemical attack, and reaction with aggregates and that those inspections be 

performed by a fire protection qualified inspector. The staff finds the program enhancement 

acceptable because, when implemented, the program element will be consistent with the 

recommendations in GALL Report AMP XI.M26.

. LRA Section B.2.1.15 states an enhancement to the “parameters monitored or 

inspected” and “detection of aging effects” program elements. The LRA states that the Fire 

Protection Program implementing documents will be enhanced to include additional age-related 

degradation inspection criteria such as spalling and loss of material caused by freeze-thaw, 

chemical attack, and reaction with aggregates. This enhancement will also include visual 

inspection of fire-rated exposed barrier walls, floors, and ceilings by a fire protection qualified 

inspector.

Enhancement 3

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M26 and noted that the GALL Report recommends that fire-rated doors be 

visually inspected by fire protection qualified inspectors. The staff finds the program 

enhancement acceptable because, when implemented, the program element will be consistent 

with the recommendations in GALL Report AMP XI.M26.

. LRA Section B.2.1.15 states an enhancement to the “detection of aging 

effects” program element. The LRA states that the Fire Protection Program implementing 

documents will be enhanced to include visual inspection of fire-rated doors by a fire protection 

qualified inspector.

Based on its audit, the staff finds that elements one through six of the applicant’s Fire Protection 

Program, with acceptable enhancements, are consistent with the corresponding program 

elements of GALL Report AMP XI.M26 and, therefore, are acceptable.

Operating Experience. LRA Section B.2.1.15 summarizes operating experience related to the 

Fire Protection Program. The applicant stated that leakage was identified on the diesel fire 

pump casing vent during the surveillance testing in September 2002, and it took appropriate 

corrective actions and repaired the leak using a preventive maintenance work order. The 

applicant also stated that it identified two degraded fire barriers in October 2002, and work 

orders were issued to repair the two barriers. The applicant further stated that it identified a 
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broken fire-door handle in April 2003, and it repaired and retested the door by issuing a work 

order, which demonstrates that the Fire Protection Program satisfactorily identifies deficiencies.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated 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 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

• include the performance of visual inspections of penetration seals by a fire protection 

qualified inspector

. LRA Section A.2.1.15 provides the UFSAR supplement for the Fire 

Protection 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 3.3-2. The staff also noted that the applicant committed (Commitment Nos. 6, 7, 

and 8) to enhance the Fire Protection Program prior to the period of extended operation. 

Specifically, the applicant committed to enhance the program to do the following:

• add inspection requirements such as spalling, loss of material caused by freeze-thaw, 

chemical attack, and reaction with aggregates

• include the performance of visual inspections of fire-rated doors by a fire protection 

qualified inspector

The staff determined 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 applicant’s Fire Protection Program, the 

staff determined that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the enhancements and their 

justifications and confirmed that their implementation through Commitment Nos. 6, 7, and 8 prior 

to the period of extended operation would make the existing program consistent with the GALL 

Report AMP to which it was compared. The staff concludes that the applicant 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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3.0.3.2.8 Fire Water System Program

Summary of Technical Information in the Application

• loss of material due to general, pitting, crevice, galvanic, and 

microbiologically-influenced corrosion

. LRA Section B.2.1.16 describes the 

existing Fire Water System Program as consistent, with enhancements, with GALL Report 

AMP XI.M27, “Fire Water System.” The applicant stated that this program manages the 

following:

• fouling

• reduction of heat transfer due to fouling for fire water system components using detailed 

inspections in accordance with station surveillance test procedures

The applicant also stated that the SSCs included within the scope of this program include both 

fire suppression and fire mitigation components. The applicant further stated that the program 

includes regular inspections, periodic flushing, chemical additions, and performance testing,

which are conducted to ensure no corrosion, microbiologically-influenced corrosion, or 

biofouling has occurred.

Staff Evaluation

The staff also reviewed the portions of the “parameters monitored or inspected” and “detection 

of aging effects” 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.

. 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 one 

through six of the applicant’s program to the corresponding elements of GALL Report 

AMP XI.M27. As discussed in the audit report, the staff confirmed that each element of the 

applicant’s program is consistent with the corresponding elements of GALL Report 

AMP XI.M27.

Enhancement 1

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M27. The staff noted that the GALL Report recommends that sprinkler heads 

be inspected before the end of the 50-year sprinkler head service life and at 10-year intervals 

thereafter during the period of extended operation to ensure that signs of degradation, such as 

corrosion, are detected in a timely manner. The staff finds the applicant’s enhancement 

acceptable because, when implemented, the program element will be consistent with the 

recommendations in GALL Report AMP XI.M27.

. LRA Section B.2.1.16 states an enhancement to the “detection of aging 

effects” program element. The applicant stated that it will enhance its program to include the 

National Fire Protection Association (NFPA) 25 criteria, which states that “where sprinklers have 

been in place for 50 years, they will either be replaced or a representative sampling from one or 

more sample areas will be submitted to a recognized testing laboratory for field service testing.” 

The applicant further stated that sampling will be performed every 10 years after the initial field 

service testing.

Enhancement 2. LRA Section B.2.1.16 states an enhancement to the “parameters monitored or 

inspected” program element. The applicant stated that it will enhance its program to include 
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performance of periodic flow testing of the fire water system in accordance with NFPA 25 

guidelines.

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M27. The staff noted that the GALL Report recommends that periodic flow 

testing of the fire water system be performed using the guidelines of NFPA 25. The staff finds 

the applicant’s enhancement acceptable because, when implemented, the program element will 

be consistent with the recommendations in GALL Report AMP XI.M27.

Enhancement 3

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M27. GALL Report AMP XI.M27 recommends that wall thickness evaluations of 

fire protection piping be performed on system components using non-intrusive techniques and 

that these inspections be performed before the end of the current operating term and at 

plant-specific intervals thereafter during the period of extended operation. LRA Section B.2.1.16 

states that “the Fire Water System Program will be enhanced to perform periodic visual 

inspection or volumetric inspection, as required, of the internal surface of the fire protection 

system,” and that “this inspection will be performed no earlier than 10 years before the period of 

extended operation.” The LRA only indicates when the inspections will not be conducted and 

does not indicate whether the inspections will be implemented prior to or during the period of 

extended operation. It is not clear to the staff if the intent of the enhancement is to have the 

inspections conducted prior to the period of extended operation, as recommended by the GALL 

Report. By letter dated November 18, 2010, the staff issued RAI B.2.1.16-1 requesting that the 

applicant confirm whether the inspection activities are planned to start before or during the 

period of extended operation. If inspections will be not be conducted prior to entering the period 

of extended operation, the staff asked the applicant to provide technical justification for not 

conducting the inspections until after entering the period of extended operation.

. LRA Section B.2.1.16 states an enhancement to the “detection of aging 

effects” program element. The applicant stated that it will enhance its program to include the 

performance of periodic visual inspections or volumetric inspections of the internal surface of 

the fire protection system upon each entry to the system for routine or corrective maintenance to 

evaluate wall thickness and inner diameter of the fire protection piping. The applicant further 

stated that this inspection will be performed within a 10-year period prior to the period of 

extended operation.

In its response dated December 17, 2010, the applicant stated that it clarified the inspection 

commitment requirements in LRA supplement 2, dated November 15, 2010, to state that the 

inspection will be performed within a 10-year period prior to the period of extended operation. 

The staff reviewed LRA supplement 2 and noted that the applicant revised LRA

Section B.2.1.16 to clarify that the inspections will be performed within 10 years prior to the 

period of extended operation. The staff finds the applicant’s response acceptable because the 

applicant’s inspection commitment is clearly identified as being implemented prior to the period 

of extended operation, which is consistent with the recommendations in the GALL Report. The 

staff’s concern described in RAI B.2.1.16-1 is resolved.

GALL Report AMP XI.M27 states that, as an alternative to non-intrusive testing, the plant 

maintenance process may include a visual inspection of the internal surface of the fire 

protection piping upon each entry to the system for routine or corrective maintenance, as long 

as it can be demonstrated that inspections are performed on a representative number of 

locations on a reasonable basis. Neither the applicant’s Fire Water System Program description 

in LRA Section B.2.1.16 nor the program basis documentation provide any indication of how the 
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inspections will be conducted on a representative number of locations on a reasonable basis. 

By letter dated November 18, 2010, the staff issued RAI B.2.1.16-3 requesting that the applicant 

explain how the Fire Water System Program inspects a representative number of locations on a 

reasonable basis, including both opportunistic and directed inspections.

In its response dated December 17, 2010, the applicant revised the LRA to state that the 

inspections will be documented and trended to determine if a representative number of 

inspections have been performed prior to the period of extended operation and to conduct 

focused inspections if a representative number of inspections have not been performed. The 

staff finds the applicant’s response acceptable because the applicant will ensure that a 

representative number of inspections have been performed prior to entering the period of 

extend operation, which is consistent with the recommendations in the GALL Report. The 

staff’s concern described in RAI B.2.1.16-3 is resolved.

Based on its audit and review of the applicant’s responses to RAIs B.2.1.16-1 and B.2.1.16-3,

the staff finds that elements one through six of the applicant’s Fire Water System Program, with 

acceptable enhancements, are consistent with the corresponding program elements of GALL 

Report AMP XI.M27 and, therefore, are acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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.

. LRA Section B.2.1.16 summarizes operating experience related to the 

Fire Water System Program. The applicant stated that, in July 2003, a surveillance activity 

identified a failure to develop required discharge pressure for the fire protection booster pump. 

The applicant also stated it determined the pump was not sized correctly and replaced the 

impeller. The applicant further stated that, in July 2004, a maintenance mechanic observed 

pipe corrosion in the fire pump recirculation header and that a work order was written and the 

pipe was replaced. The applicant stated that these examples provide evidence of how its 

routine system maintenance is able to identify deficient conditions and correct them with its 

Corrective Action Program.

Based on its audit and review of the application, the staff finds that 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement. LRA Section A.2.1.16 provides the UFSAR supplement, as amended, for 

the Fire Water System 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 3.3-2. The staff noted that it does not indicate that periodic full-flow flush tests and 

system performance testing are performed or that the visual inspections included in the program 

will be able to detect wall thickness and the inner diameter of the piping. The licensing basis for 

the period of extended operation may not be adequate if the applicant does not incorporate this 
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information in its UFSAR supplement. By letter dated November 18, 2010, the staff issued 

RAI B.2.1.16-2 to request that the applicant justify why it did not indicate that periodic full-flow 

flush tests and system performance testing are performed and that the visual inspections in the

program will be able to detect wall thickness and the inner diameter of the piping.

In its response dated December 17, 2010, the applicant stated that it revised LRA

Section A.2.1.16 to state that the Fire Water System Program includes periodic full-flow flush 

tests and system performance testing per the guidance of NFPA 25. The applicant also revised 

the UFSAR supplement to state that the program also includes visual inspection of the internal 

surface of the fire protection piping upon each entry into the system for routine or corrective 

maintenance that will look for material loss or changes to the inner diameter of the piping. The 

staff finds the applicant’s response acceptable because the applicant revised its UFSAR 

supplement to include periodic flushing and internal visual inspections, which is consistent with 

the recommended description for this type of program, as described in SRP-LR Table 3.3-2. 

The staff’s concern described in RAI B.2.1.16-2 is resolved.

The staff noted that the applicant committed (Commitment Nos. 9, 10, and 11) to enhance the 

Fire Water System Program prior to entering the period of extended operation. Specifically, the 

applicant committed to enhance the program to do the following:

• include NFPA 25 guidance for where sprinklers have been in place for 50 years, that 

they shall be replaced or representative samples from one or more sample areas shall 

be submitted to a recognized testing laboratory for field service testing

• include the performance of periodic flow testing of the fire water system in accordance 

with the guidance of NFPA 25

• include the performance of periodic visual or volumetric inspections of the internal 

surface of the fire protection system upon each entry to the system for routine or 

corrective maintenance

• document and trend performance of the periodic visual or volumetric inspections to 

determine if a representative number of inspections have been performed prior to the 

period of extended operation

• conduct focused inspections if a representative number of inspections have not been 

performed

The staff determined that the information in the UFSAR supplement, as amended, 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 applicant’s Fire Water System Program, 

the staff determined that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. The staff reviewed the enhancements and confirmed that 

their implementation through Commitment Nos. 9, 10, and 11 prior to the period of extended 

operation would make the existing AMP consistent with the GALL Report to which it was 

compared. The staff concludes that the applicant 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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3.0.3.2.9 Aboveground Steel Tanks Program

Summary of Technical Information in the Application. LRA Section B.2.1.17 describes the 

existing Aboveground Steel Tanks Program as consistent, with enhancements, with GALL 

Report AMP XI.M29, “Aboveground Steel Tanks.” The applicant stated that the Aboveground 

Steel Tanks Program manages the aging effects of loss of material due to general, pitting, and 

crevice corrosion. The applicant also stated that the program includes preventive measures to 

mitigate corrosion and periodic inspections to validate the effectiveness of the preventive 

actions. The applicant further stated that the preventive measures include the application of 

protective coatings on the exterior surfaces of the tanks and caulking and flashing at the 

auxiliary boiler fuel oil storage and fire protection water storage tank’s ground interface. The 

applicant stated that the two diesel fire pump fuel oil tanks are raised on steel supports clear of 

their concrete foundations. The applicant also stated that ultrasonic thickness measurements of 

the tank bottom surface will be performed from inside the tank to detect any exterior material 

degradation.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M29. 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.M29, with the exception of the “parameters monitored or inspected,” 

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria” program 

elements. For these elements, the staff determined the need for additional clarification, which 

resulted in the issuance of RAIs.

. 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.

GALL Report AMP XI.M29 recommends that the program use periodic system walkdowns to 

monitor degradation of the protective paint or coating under the “parameters monitored or 

inspected” program element description. However, LRA Section B.2.1.17 states that visual 

inspection of the external surface of the protective coatings on exterior surface of the in-scope 

tanks will be conducted in accordance with its Structures Monitoring Program. The staff noted 

that this program does not state that coating inspections of aboveground steel tanks is within its 

scope. By letter dated November 18, 2010, the staff issued RAI B.2.1.17-1 requesting that the 

applicant confirm that its Structures Monitoring Program includes coating inspection of 

aboveground steel tanks.

In its response dated December 17, 2010, the applicant stated that its Structures Monitoring 

Program is revised to include an external inspection of the aboveground steel tanks to inspect 

the paint or coating for cracking, flaking, or peeling. The staff finds the applicant’s response 

acceptable because the applicant’s Structures Monitoring Program includes coating inspection 

of the aboveground steel tanks to monitor degradation of the coatings. The staff’s concern 

described in RAI B.2.1.17-1 is resolved.

GALL Report AMP XI.M29 recommends that periodic system walkdowns be conducted to 

confirm that the sealant and caulking at the interface edge between the tank and concrete are 

intact under the “parameters monitored or inspected” and “detection of aging effects” program 

element descriptions. The staff noted that LRA Section B.2.1.17 states that visual inspection 

will be performed to detect drying, cracking, or missing sealant and caulking applied along the 

tank and ground interface. The staff believes that to detect hardening and loss of strength in 
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elastomeric materials it is necessary to supplement the visual inspection with physical 

manipulation of the sealant and caulking. By letter dated November 18, 2010, the staff issued

RAI B.2.1.17-3 requesting that the applicant confirm that its Aboveground Steel Tanks Program 

includes manual manipulation of elastomeric sealant and caulking material to detect hardening 

and loss of strength.

In its response dated December 17, 2010, the applicant stated that its Aboveground Steel 

Tanks Program is revised to include a visual and tactile examination of the sealant and caulking 

on the exterior surfaces of the aboveground steel tanks. The applicant also stated that the 

examination consists of pressing on the sealant or caulking to detect a reduction in the 

resiliency and pliability. The staff finds the applicant’s response acceptable because the 

applicant’s Aboveground Steel Tanks Program includes visual inspections and physical 

manipulation, which are capable of detecting degradation of the sealant and caulking. The 

staff’s concern described in RAI B.2.1.17-3 is resolved.

GALL Report AMP XI.M29 recommends that “[a]ny degradation of paint, coating, sealant, and 

caulking is reported and will require further evaluation. Degradation consists of cracking, 

flaking, or peeling of paint or coatings, and drying, cracking or missing sealant and caulking” 

under the “acceptance criteria” program element description. The staff noted that LRA

Section B.2.1.17 states an enhancement to the Aboveground Steel Tanks Program by adding 

paint flaking and drying, cracking, or missing sealant and caulking as examples of minor 

structural deficiencies. The staff does not understand the context of the term “minor structural 

deficiencies” and how it relates to the need for further evaluation of the condition. By letter 

dated November 18, 2010, the staff issued RAI B.2.1.17-4 requesting that the applicant clarify 

whether the term “minor structural deficiency” implies that no further evaluation of the degraded 

condition will occur, and, if no further evaluation will occur, the staff asked the applicant to justify 

this as an exception to GALL Report AMP XI.M29.

In its response dated December 17, 2010, the applicant stated that the term “minor structural 

deficiency” in LRA Section B.2.1.17 is revised to “degradation.” The staff finds the applicant’s 

response acceptable because the applicant has changed the term “minor structural deficiency” 

to “degradation” in its Aboveground Steel Tanks Program; therefore, all degraded conditions will 

be entered into its Corrective Action Program. The staff’s concern described in RAI B.2.1.17-4 

is resolved.

GALL Report AMP XI.M29 recommends that, “[t]he effects of corrosion of the underground 

external surface are detectable by thickness measurement of the tank bottom and are 

monitored and trended if significant material loss is detected” under the “monitoring and 

trending” program element description. The staff noted that LRA Section B.2.1.17 states that,

for the two fire protection water storage tanks, the program will be enhanced to include the 

performance of a UT examination of the internal tank bottom surface within 10 years prior to the 

period of extended operation. The staff is not clear whether the UT examination is a one-time or 

periodic inspection. By letter dated November 18, 2010, the staff issued RAI B.2.1.17-5 

requesting that the applicant clarify whether the UT examination specified in LRA

Section B.2.1.17 is a one-time measurement or periodic inspection. If it is a one-time ultrasonic 

inspection, the staff asked the applicant to justify how the one-time measurement can be used 

for monitoring and trending of aging effects.

In its response dated December 17, 2010, the applicant stated that a one-time ultrasonic 

thickness measurement of the tank bottoms will be performed within 10 years prior to the period 

of extended operation (Commitment No. 13). The applicant also stated that any thickness 
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measurements indicating less than nominal thickness will require a condition report to ensure 

than an engineered evaluation is performed and any necessary monitoring and trending is 

identified. The staff finds the applicant’s response acceptable because the applicant will 

perform an engineering evaluation of any thickness measurements less than nominal thickness 

and the evaluation will identify any required monitoring and trending. The staff’s concern 

described in RAI B.2.1.17-5 is resolved.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

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

• include the fire protection fuel oil tanks, auxiliary boiler fuel oil storage tank, and fire 

protection water storage tanks as part of the scope of tanks

. LRA Section B.2.1.17 states an enhancement to the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements. The LRA, as updated by the applicant's response to 

RAI B.2.1.17-4 dated December 17, 2010, states that the Aboveground Steel Tanks Program 

implementing procedures will be enhanced to do the following:

• add paint flaking and drying, cracking, or missing sealant and caulking as examples of 

degradation

• add a requirement that discrepant conditions be reported through the applicant’s 

Corrective Action Program

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M29. The staff noted that the applicant’s program appropriately identifies 

specific components, aging effects, and the need for corrective actions to ensure that aging 

effects are managed. The staff’s evaluation of RAI B.2.1.17-4 related to the applicant changing

the term “minor structural deficiency” to “degradation” in its Aboveground Steel Tanks Program

is documented above. On the basis of its review, the staff finds this enhancement acceptable 

because, when it is implemented prior to the period of extended operation, it will make the 

program elements consistent with the recommendations in GALL Report AMP XI.M29.

Enhancement 2

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M29 and noted that the applicant’s program appropriately identifies thickness 

measurements of the tank bottoms and associated evaluation to detect degradation of the two 

fire protection water storage tanks. The staff’s evaluation of RAI B.2.1.17-5 related to whether 

the UT examination is a one-time measurement or periodic inspection is documented above. 

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented prior to the period of extended operation, it will make the program elements 

consistent with the recommendations in GALL Report AMP XI.M29.

. LRA Section B.2.1.17 states an enhancement to the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements. The LRA states that the Aboveground Steel Tanks 

Program implementing procedures will be enhanced to include the performance of an ultrasonic 

examination and evaluation of the internal bottom surface of the two fire protection water 

storage tanks within 10 years prior to the period of extended operation.
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Based on its audit and review of the applicant’s response to RAIs B.2.1.17-1, B.2.1.17-3, 

B.2.1.17-4, and B.2.1.17-5, the staff finds that elements one through six of the applicant’s 

Aboveground Steel Tanks Program, with acceptable enhancements, are consistent with the 

corresponding program elements of GALL Report AMP XI.M29 and, therefore, are acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program.

. LRA Section B.2.1.17 summarizes operating experience related to the 

Aboveground Steel Tanks Program. The applicant stated that degradation of coatings was 

reported on the fire protection fuel oil tanks in 1999. As a result, the applicant stated that the 

tanks were surface prepped and re-coated. The applicant also stated that, in response to a 

condition of chipped paint and rusting metal surface around the lower manways of the fire 

protection water storage tanks in 2001, it took appropriate corrective actions to have the tanks 

surface prepped and re-coated to maintain the structural integrity of the tanks.

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 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

The staff reviewed the applicant’s UFSAR supplement and found that it does not indicate that 

visual inspections of sealant and caulking inspections are included in the program. The 

example description for this program in SRP-LR Tables 3.3-2 and 3.4-2 include specific mention 

of this inspection. The licensing basis 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 November 18, 2010, the staff issued RAI B.2.1.17-2 requesting that the applicant 

justify why visual inspections of sealant and caulking are not included in the UFSAR supplement 

as part of the scope of the program.

. LRA Section A.2.1.17 provides the UFSAR supplement for the 

Aboveground Steel Tanks Program. The staff reviewed this UFSAR supplement description of 

the program against the recommended description for this type of program, as described in 

SRP-LR Tables 3.3-2 and 3.4-2.

In its response dated December 17, 2010, the applicant stated that it revised its UFSAR 

supplement, Section A.2.1.17, to include visual inspections of the sealant and caulking on the 

exterior surfaces of the aboveground steel tanks. The staff finds the applicant’s response 

acceptable because the applicant revised its Aboveground Steel Tanks Program UFSAR 

supplement to include visual inspections of the sealant and caulking in the program; therefore, 

the licensing basis is now adequate. The staff’s concern described in RAI B.2.1.17-2 is 

resolved.
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The staff noted that the applicant committed (Commitment No. 12) to enhance the Aboveground 

Steel Tanks Program to include in-scope components and aging effects prior to the period of 

extended operation.

The staff also noted that the applicant committed (Commitment No. 13) to enhance the 

Aboveground Steel Tanks Program prior to the period of extended operation. Specifically, the 

applicant committed to include an ultrasonic inspection and evaluation of the internal bottom 

surface of the two fire protection water storage tanks.

The staff determined that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.10 Fuel Oil Chemistry Program

. On the basis of its audit and review of the applicant’s Aboveground Steel Tanks 

Program, the staff determined 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 through Commitment Nos. 12 and 13 prior to the period 

of extended operation would make the AMP consistent with the GALL Report AMP to which it is 

compared. The staff concludes that the applicant 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).

Summary of Technical Information in the Application. LRA Section B.2.1.18 describes the 

existing Fuel Oil Chemistry Program as consistent, with exceptions and enhancements, with 

GALL Report AMP XI.M30, “Fuel Oil Chemistry.” The applicant stated that the existing Fuel Oil 

Chemistry Program manages the aging effects of loss of material due to general, pitting, 

crevice, galvanic, and microbiologically-influenced corrosion as well as loss of material due to 

fouling in the diesel fuel oil systems for the emergency diesel generators, diesel engine driven 

fire protection system pumps, and the auxiliary boiler fuel oil system. The program manages 

the aging effects through monitoring and maintenance of diesel fuel oil quality. The applicant 

further states that the program manages these aging effects for the diesel generator fuel oil 

storage tanks, the diesel generator fuel oil day tanks, the diesel fire pump fuel oil day tanks, the 

auxiliary boiler fuel oil storage tank and the associated piping, tubing, and valves. The program 

manages such aging by maintaining fuel oil chemistry, removing water, and cleaning and 

inspecting the tanks.

Staff Evaluation

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance 

criteria” program elements associated with exceptions and 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 exception and enhancements follows.

. 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.

Exception 1. LRA Section B.2.1.18 states an exception to the “preventive actions” program 

element. The GALL Report recommends maintaining the quality of fuel oil by additions of 

biocides to minimize biological activity, stabilizers to prevent biological breakdown of the diesel 
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fuel, and corrosion inhibitors to mitigate corrosion. Alternatively, the applicant stated that plant 

operating experience has shown that monthly testing for and removal of water along with the 

purchase of quality fuel oil negates the need for stabilizers or corrosion inhibitors. All new fuel 

shipments are sampled from the delivery tanker to verify they meet the applicable American 

Society for Testing and Materials (ASTM) standards prior to being offloaded into the associated 

storage tank. The applicant stated further that the fuel oil is used and topped off often enough 

to negate the need for stabilizers or corrosion inhibitors.

The staff reviewed this exception with the GALL Report and noted that the applicant took 

exception because stabilizers or corrosion inhibitors are not used in the diesel fuel oil. 

Additionally, biocide is added only to the diesel fuel oil storage tanks. The staff finds this 

exception acceptable and this program element consistent to the one described in the GALL 

because the applicant manages the aging effects of the components by maintaining fuel oil 

chemistry through monthly sampling, removal of any accumulated water if found, and cleaning 

and inspecting the associated fuel oil tanks. The applicant also ensures the quality of the fuel 

oil purchased by sampling each fuel oil shipment prior to being offloaded. These actions 

demonstrate the intent to minimize biological activity, prevent biological breakdown of the diesel 

fuel, and mitigate corrosion, as recommended in the GALL Report AMP XI.M30.

Exception 2

The staff reviewed this exception with the GALL Report and noted that the applicant took 

exception because the non-modified ASTM Standard D2276 is used for the analysis of 

particulates in fuel oil. The staff finds this exception acceptable because the analysis for 

particulates is based on the total weight of particulates captured; therefore, using a smaller pore 

sized filter will make the applicant’s analysis of particulates more conservative than what is 

recommended in the GALL Report AMP XI.M30.

. LRA Section B.2.1.18 states an exception to the “parameters monitored or 

inspected” and “acceptance criteria” program elements. The GALL Report recommends using 

the modified ASTM Standard D2276, Method A, for determination of particulates. The 

modification consists of using a filter with a pore size of 3.0 μm instead of 0.8 μm to filter the 

particulates from the fuel oil sample for subsequent analysis. Alternatively, the applicant stated 

that the non-modified ASTM Standard D2276, which uses the 0.8 μm filter, is used to sample 

particulates. The applicant further states that the small pore size of the 0.8 μm filter retains 

more particulates and, therefore, is conservative as the analysis for particulates is based on the 

total weight of particulates captured.

Exception 3

The staff noted that the applicant took exception to the GALL Report in that the applicant 

incorporates ASTM Standard D4176 versus D1796 for the use in detecting water and

particulates in fuel oil. The staff finds this exception acceptable because the detection limit of 

ASTM Standard D4176 for free water and particulate contamination, with an experienced 

. LRA Section B.2.1.18 states an exception to the “parameters monitored or 

inspected” and “acceptance criteria” program elements. The GALL Report recommends using 

the ASTM Standards D1796 and D2709 for determination of water and sediment contamination 

in diesel fuel. Alternatively, the applicant stated that ASTM Standard D4176 and D2709 would 

be used for determination of water and sediment contamination in diesel fuel. The applicant 

further stated that ASTM Standard D4176 is used to perform a clear and bright test of light fuel 

oil and can be performed in the field as well as in the lab and is an easy first screening to 

determine the quality of fuel oil. The applicant stated that using one lab test to analyze for water 

and particulate coupled with the field clear and bright test provides an acceptable approach for 

detecting water and particulates in the delivered diesel generator fuel oil.
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operator, is approximately 40 ppm and is not dependent on ambient temperature above the 

cloud point of the fuel. The detection limit for ASTM Standard D2709 is 50 ppm at 

21-32 °Celsius (C). The staff finds the use of ASTM Standard D4176 an acceptable substitute 

to ASTM Standard D1796 because it allows the applicant to have an immediate indication of 

any contamination in a fuel delivery prior to allowing the fuel to reach the fuel storage tanks. 

The use of ASTM Standard D4176 along with ASTM Standard D2709 allows two separate 

checks of the fuel oil using two different analyses with similar detection limits. The staff finds 

the use of these two standards consistent with the GALL Report AMP XI.M30.

Exception 4

The staff noted that the applicant took exception to the GALL Report in that the applicant uses 

ASTM Standard D2276-06 versus ASTM Standard D2276-00. The staff reviewed both revisions 

of the standard and finds that this exception is acceptable because the methodology for 

determining particulate in diesel fuel oil has not changed between the two revisions. The 

applicant’s use of ASTM Standard D2276-06 is consistent with the GALL Report AMP XI.M30.

. LRA Section B.2.1.18 states an exception to the “parameters monitored or 

inspected” and “acceptance criteria” program elements. The GALL Report recommends using 

ASTM Standard D2276-00 for determining particulate in diesel fuel oil. Alternatively, the 

applicant uses ASTM Standard D2276-06. The applicant stated that the basic methodology 

between the two revisions of the standards had not changed, and the 2006 version of the 

standard had updated figures and notes from previous revisions that were incorporated into the 

procedural steps. The applicant further stated that the figure and methodology for taking 

aviation jet fuel samples had changed but is not used by the applicant.

Enhancement 1

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.M30.

. LRA Section B.2.1.18 states an enhancement to the “scope of program,” 

“preventive actions,” “parameters monitored or inspected,” and “monitoring and trending” 

program elements. This enhancement expands on the existing program elements by adding the 

requirement to sample and analyze new fuel deliveries, including testing for biodiesel, prior to 

offloading to the auxiliary boiler fuel oil storage tank. Additionally, the enhancement will require 

that the auxiliary boiler fuel oil storage tank be sampled periodically.

Enhancement 2

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.M30.

. LRA Section B.2.1.18 states an enhancement to the “preventive actions” 

program element. This enhancement expands on the existing program element by adding the 

requirement to check for the presence of water in the auxiliary boiler fuel oil storage tank at least 

once per quarter to remove water as necessary.

Enhancement 3. LRA Section B.2.1.18 states an enhancement to the “scope of program,” 

“preventive actions,” “parameters monitored or inspected,” and “monitoring and trending” 

program elements. This enhancement expands on the existing program elements by adding the 

requirement to drain, clean, and inspect the diesel fire pump fuel oil day tanks on a frequency of 

at least once every 10 years.
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On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.M30.

Enhancement 4

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.M30.

. LRA Section B.2.1.18 states an enhancement to the “preventive actions” and 

“detection of aging effects” program elements. This enhancement expands on the existing 

program elements by adding the requirement to perform an ultrasonic thickness measurement 

of the tank bottom during the 10-year draining, cleaning, and inspection of the diesel generator 

fuel oil storage tanks, diesel generator fuel oil day tanks, diesel fire pump fuel oil day tanks, and 

auxiliary boiler fuel oil storage tank.

Enhancement 5

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.M30.

. LRA Section B.2.1.18 states an enhancement to the “parameters monitored or 

inspected” and “acceptance criteria” program elements. By letter dated December 14, 2010, the 

staff issued RAI B.2.1.18-2 requesting that the applicant clarify the revisions of ASTM standards 

used for the program. In its response dated January 13, 2011, the applicant amended this 

enhancement by updating the Technical Requirement Program 5.1 (Diesel Fuel Oil Testing 

Program) to use ASTM Standards D2709-96 and D4057-95, as required by GALL Report 

AMP XI.M30, Revision 1, prior to the period of extended operation. The current revision of the 

applicant’s Technical Requirement Program 5.1 uses ASTM Standards D2709-82 and 

D4057-81.

Based on its audit and review of the applicant’s response to RAI B.2.1.18-2, the staff finds that 

elements one through six of the applicant’s Fuel Oil Chemistry Program, with acceptable 

exceptions and enhancements, are consistent with the corresponding program elements of 

GALL Report AMP XI.M30 and, therefore, are acceptable.

Operating Experience

The staff reviewed the following information regarding operating experience:

. LRA Section B.2.1.18 summarizes operating experience related to the 

Fuel Oil Chemistry Program. The staff reviewed this information and interviewed the applicant’s 

technical personnel to confirm that the applicable aging effects and industry and plant-specific 

operating experience have been reviewed by the applicant and are evaluated in the GALL 

Report. During the audit, the staff independently confirmed that the applicant adequately 

incorporated and evaluated operating experience related to this program.

(1) In November 2000, a trend of increasing particulates was identified in diesel generator 

fuel oil storage tank, 1-DG-TK-26B. Test results from two samples showed particulate 

matter at 11.8 mg/L and 11.2 mg/L which exceeded the limit of 10 mg/L. As a corrective 

action, both diesel generator fuel oil storage tanks (1-DG-TK-26A and 26B) were filtered 

to a particulate matter of less than <0.3 mg/L, a condition report was written along with a 

work order to correct the issue, and a cause analysis was performed. The cause 

analysis determined that a combination of factors were potential contributors to the high 

particulate count. Corrective actions included cleaning of the diesel generator day tanks,

more frequent replacement of the associated fuel oil filters (every 6 months), reviewing
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the lube oil-fuel oil interfaces to rule out lube oil contamination of the fuel as a major 

contributor and planning for future potential particulate clean-up activities. The plant did 

not experience a loss of intended function of the diesel generator due to the high 

particulate count.

(2) A review of work orders associated with the cleaning and inspection of diesel generator 

fuel oil storage tanks and day tanks and the fire pump fuel oil day tanks indicate no 

degradation of the tanks. The "A" diesel generator fuel oil storage tank was drained and 

the bottom UT inspected in 1994 and 2003. The "B" diesel generator fuel oil storage 

tank was drained and the bottom UT examination was performed on the tank bottom in 

1994 and 2005. The "A" diesel generator fuel oil day tank was drained, cleaned and 

inspected in 2003. The "B" diesel generator fuel oil day tank was drained, cleaned and 

inspected in 2005.

(3) In June 2001, an inspection of the internal bottom surface of the auxiliary boiler fuel oil 

storage tank (AB-TK-29) was performed by certified personnel under a work order and in 

accordance with a Seabrook Station specification for cleaning, inspection and repair of 

the bulk fuel oil storage tank. Inspection results were captured in a technical inspection 

and engineering analysis report. The report indicated minimal thickness loss on the 

nominal 1

/4" thick floor after 26 years. No degradation of the tank floor was characterized 

as major.

(4) A review of Seabrook Station condition reports identified instances when the new fuel oil 

deliveries were rejected due to the presence of water. In December of 2004, a fuel 

shipment for the emergency diesel generators did not meet the acceptance criteria of the 

clear and bright test. Samples were analyzed for water, particulate, and haze. Visible 

water droplets could be seen at the bottom of the clear and bright bottle.

A second sample was taken, and it also had visible water droplets in the sample bottle 

and therefore, the tanker fuel oil shipment was rejected. In September of 2005, a fuel 

shipment for the emergency diesel generators did not meet the acceptance criteria for 

flashpoint. The flashpoint reading of 117°F was below the minimum requirement of 

125°F and therefore, the tanker fuel oil shipment was rejected. In these instances,

corrective actions were taken to correct the out of specification condition prior to 

offloading the fuel oil into the diesel generator fuel oil storage tank.

(5) Although not discussed in GALL Report AMP XI.M30, the NRC had recently issued 

Information Notice 2009-02, “Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine 

Performance.” This document indicates that No. 2 diesel fuel could contain up to a 

5 percent bio-diesel fuel (B5) blend without labeling the blend in accordance with ASTM 

D 975-08a, “Standard Specification for Diesel Fuel Oils.” Bio-diesel B5 blend: (a) can 

have a cleansing effect that can increase sediment that could plug filters, (b) could form 

“dirty water” which leads to algae growth, (c) is biodegradable such that long term 

storage is not recommended and (d) can be more susceptible to gel creation in the 

presence of brass, bronze and copper fittings, piping, and tanks. These effects could 

lead to plant-specific operating experience outside the bounds of industry operating 

experience. Existing Seabrook Station plant procedures test for bio-diesel prior to 

offload of fuel oil to the diesel generator fuel oil storage tanks and fire pump fuel oil day 

tanks. Acceptance criteria for bio-diesel is <2 percent (non-detectable).

The staff reviewed the operating experience information, in the application and during the audit,

to determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 
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audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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 operating experience 

related to the applicant’s program demonstrates that it can adequately manage the detrimental 

effects of aging on SSCs within the scope of the program and that implementation of the 

program has resulted in the applicant taking appropriate corrective actions. The staff confirmed 

that the “operating experience” program element satisfies the criterion in SRP-LR

Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement

By letter dated December 14, 2010, the staff issued RAI B.2.1.18-1 requesting that the applicant 

justify why it did not include the referenced ASTM standards. In its response dated 

January 13, 2011, the applicant amended the UFSAR supplement in LRA Section A.2.1.18. 

The amended UFSAR supplement states the following:

. LRA Section A.2.1.18 provides the UFSAR supplement for the Fuel Oil 

Chemistry Program. The staff reviewed the UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR

Table 3.3-2. The staff found that the description of the Fuel Oil Chemistry Program, as 

described in LRA Section A.2.1.18, does not indicate which ASTM standards the program 

implements but simply states the program will use the applicable ASTM standards. The 

example description for this program in SRP-LR Table 3.3-2 includes specific mention of ASTM 

Standards D1796, D4057, D2709, and D2276. The licensing basis for the period of extended 

operation may not be adequate if the applicant does not incorporate this information in its 

UFSAR supplement.

New fuel oil is sampled and verified to meet the requirements of applicable 

American Society for Testing and Materials (ASTM) standards D4057 and D2709 

prior to offloading to the storage tanks. Stored fuel oil is sampled and verified to 

meet the requirements of ASTM D2276 or ASTM D4057, and ASTM D2709. The 

program monitors fuel oil quality and levels of water in the fuel oil which may 

cause the loss of material of the tank internal surfaces. The program monitors 

water and sediment contamination in diesel fuel.

With this amendment, the staff finds the UFSAR supplement for the Fuel Oil Chemistry Program 

acceptable because it is consistent with the corresponding program description in SRP-LR

Table 3.3-2. The staff’s concern described in RAI B.2.1.18-1 is resolved.

The staff also noted that the applicant committed (Commitment Nos. 14, 15, 16, 17, and 58) to 

enhance the Fuel Oil Chemistry Program prior to entering the period of extended operation. 

Specifically, the applicant committed to do the following:

(1) Enhance program to add requirements to 1) sample and analyze new fuel 

deliveries for biodiesel prior to offloading to the auxiliary boiler fuel oil 

storage tank and 2) periodically sample stored fuel in the auxiliary boiler 

fuel oil storage tank.
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(2) Enhance the program to add requirements to check for the presence of 

water in the auxiliary boiler fuel oil storage tank at least once per quarter 

and to remove water as necessary.

(3) Enhance the program to require draining, cleaning and inspection of the 

diesel fire pump fuel oil day tanks on a frequency of at least once every 

ten years.

(4) Enhance the program to require ultrasonic thickness measurement of the 

tank bottom during the 10-year draining, cleaning and inspection of the 

diesel generator fuel oil storage tanks, diesel generator fuel oil day tanks, 

diesel fire pump fuel oil day tanks and auxiliary boiler fuel oil storage tank.

(5) Update Technical Requirement Program 5.1, (Diesel Fuel Oil Testing 

Program) ASTM standards to ASTM D2709-96 and ASTM D4057-95 

required by the GALL XI.M30 Rev 1.

The staff determined that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.11 Reactor Vessel Surveillance Program 

. On the basis of its audit and review of the applicant’s Fuel Oil Chemistry Program, 

the staff determined that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determined that the AMP, with the exceptions, is adequate to manage the 

aging effects for which the LRA credits it. Also, the staff reviewed the enhancements and 

confirmed that their implementation through Commitment Nos. 14, 15, 16, 17, and 58, prior to 

the period of extended operation, would make the existing AMP consistent with the GALL 

Report AMP to which it was compared. 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).

Summary of Technical Information in the Application

(1) The program will specify that all pulled and tested capsules, unless discarded before 

August 31, 2000, are placed in storage (Criteria 1).

. LRA Section B.2.1.19 describes the 

existing Reactor Vessel Surveillance Program as consistent, with enhancements, with GALL 

Report AMP XI.M31,” Reactor Vessel Surveillance.” The applicant included the following four 

enhancements:

(2) The program will specify that if plant operations exceed the bounds defined by the RV 

Surveillance Program, such as operating at a lower cold leg temperature or higher 

fluence, the impact of plant operation changes on the extent of reactor vessel 

embrittlement will be evaluated, and the NRC will be notified (Criteria 1).

(3) The program will ensure the appropriate withdrawal schedule for capsules remaining in 

the vessel such that one capsule will be withdrawn at an outage in which the capsule 

receives a neutron fluence that meets the regulatory requirements and that bounds the 

60-year fluence. The remaining capsule(s) will be removed from the vessel unless 

determined to provide meaningful metallurgical data (Criteria 5).
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(4) The program will ensure that any capsule removed without testing will be stored in a 

manner that maintains it in a condition, which would permit its future use, including 

during the period of extended operation (Criteria 5).

With these enhancements, the applicant stated that the existing Reactor Vessel Surveillance 

Program will provide reasonable assurance that loss of fracture toughness due to neutron 

irradiation embrittlement will be adequately managed so that the intended functions of 

components within the scope of license renewal will be maintained consistent with the CLB 

during the period of extended operation.

Staff Evaluation

The 10 CFR Part 50, Appendix H, capsule withdrawal schedule during the period of extended 

operation is addressed in accordance with the Section XI.M31 consideration of eight criteria for 

an acceptable reactor pressure vessel (RPV) surveillance program for 60 years of operation.

. 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 

Seabrook 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.2.1.19 with its four enhancements and the associated justifications to 

determine if the AMP is adequate to manage the aging effects for which it is credited. The 

enhancements address three of the eight AMP acceptance criteria (Criteria 3, 4, and 6) in GALL 

Report AMP XI.M31.

Enhancement 1. LRA Section B.2.1.19 states an enhancement to the program related to 

Criterion 4 in the GALL Report AMP XI.M31. The enhancement describes the storage 

requirements and the need to retain future pulled capsules. This enhancement meets the fourth 

criterion of GALL Report AMP XI.M31 and will keep used surveillance specimens for future use.

Enhancement 2. LRA Section B.2.1.19 states an enhancement to the program related to 

Criterion 3 in the GALL Report AMP XI.M31. The enhancement limits the RPV cold leg 

temperature and neutron fluence projections. This enhancement meets the third criterion of 

GALL Report AMP XI.M31 and will increase the quality of the surveillance data.

Enhancement 3. LRA Section B.2.1.19 states an enhancement to the program related to 

Criterion 6 in the GALL Report AMP XI.M31. The enhancement specifies capsule withdrawal 

schedule, meeting the sixth criterion of GALL Report AMP XI.M31 because the surveillance 

program consists of capsules with a projected fluence exceeding the 60-year fluence at the end 

of 40 years. The Seabrook Reactor Vessel Surveillance Program will withdraw one of the 

remaining capsules at an outage in which the capsule receives a neutron fluence that meets the 

schedule requirements of 10 CFR Part 50 Appendix H and ASTM E185-82 and that bounds the 

60-year fluence and test that capsule in accordance with the requirements of ASTM E185-82.

Enhancement 4. LRA Section B.2.1.19 states an enhancement to the program related to 

Criterion 6 in the GALL Report AMP XI.M31. The enhancement incorporates the requirements 

for withdrawing the remaining capsules and placing them in storage when the monitor capsule is 

withdrawn during the period of extended operation. This enhancement also meets the second 

part of the sixth criterion of GALL Report AMP XI.M31 and makes reinstituting an RPV 

Surveillance Program achievable under conditions such as change of the exposure conditions 

of the RPV.
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The staff's review of this Seabrook AMP against the remaining four criteria is discussed below.

Criteria 1 and 2 of GALL Report AMP XI.M31 regard evaluation of the 60-year upper-shelf 

energy (USE) and pressure-temperature (P-T) limits, using RG 1.99, Revision 2, “Radiation 

Embrittlement of Reactor Vessel Materials.” LRA Section B.2.1.19 states that Seabrook has 

documented the extent of embrittlement for USE and P-T limits for 60 years (55 effective full 

power years (EFPYs)), in accordance with RG 1.99, Revision 2, using both the chemistry tables 

and existing surveillance data as applicable. LRA Section B.2.1.19 further states that 

surveillance capsule data from all capsules withdrawn to date was used to obtain the 

relationship between the mean value of nil-ductility reference temperature (RTNDT) change due 

to fluence as discussed in Position 2.1 of RG 1.99, Revision 2. Since the Seabrook AMP 

evaluates the 60-year USE and P-T limits fully in accordance with RG 1.99,Revision 2, including 

the limitations specified in Criterion 2, Criteria 1 and 2 are satisfied.

Criterion 5 (for plants with a surveillance program that consists of capsules with a projected

fluence of less than the 60-year fluence at the end of 40 years) and Criterion 7 (for plants not 

having surveillance capsules) do not apply to the Seabrook AMP.

Criterion 8 asks for justification for not including nozzle specimens in the surveillance program. 

The applicant did not address this issue explicitly in LRA Section B.2.1.19. However, this item

was addressed indirectly in Section 4.2.3 of the LRA in which the applicant does not include 

nozzle materials that will not exceed the surface fluence value of 1.0x1017 neutrons per square 

centimeter (n/cm2

)(E > 1.0 MeV) at 55 effective full power years. The staff finds Criterion 8 is 

satisfied. The staff's evaluation of the RPV beltline and extended beltline materials for the 

period of extended operation meeting the requirements of 10 CFR 54.21(c)(1)(ii), in which the 

analyses have been projected for 60 years of operation are documented in SER Section 4.2.3.

Based on its audit, the staff finds that the eight criteria of the applicant’s Reactor Vessel 

Surveillance Program, with acceptable enhancements, are consistent with the corresponding 

program elements of GALL Report AMP XI.M31 and, therefore, are acceptable.

Operating Experience

Furthermore, the applicant demonstrated that the plant responded to industry operating 

experience related to damage that another similar facility found in the lower internals support 

flange and the surveillance capsule access plug in the lower internals flange. The applicant 

conducted an underwater-camera visual inspection to document that similar damage had not 

occurred at Seabrook.

. LRA Section B.2.1.19 summarizes operating experience related to the 

Reactor Vessel Surveillance Program. The applicant cited evaluation results of three 

surveillance capsules withdrawn from 1991–2005 to conclude that the materials met the 

requirements for continued safe operation. The cited evaluation results provide evidence that 

the existing Reactor Vessel Surveillance Program will be capable of monitoring the aging effects 

associated with the loss of fracture toughness due to 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 pressurized thermal shock evaluation and P-T limits, using 

information from all surveillance data in accordance with RG 1.99, Revision 2.

The staff reviewed operating experience information in the application to determine if the 

applicable aging effects and industry and plant-specific operating experience were reviewed by 

the applicant and are evaluated in the GALL Report. 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 operating experience 

related to the applicant’s program demonstrates that it can adequately manage the detrimental 

effects of aging on SSCs within the scope of the program and that implementation of the 

program has resulted in the applicant taking appropriate corrective actions. The staff confirmed 

that the “operating experience” program element satisfies the criterion in SRP-LR 

Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment Nos. 18-21) to implement the 

existing Reactor Vessel Surveillance Program with the enhancements listed below prior to 

entering the period of extended operation:

. The applicant provided its UFSAR supplement for the Reactor Vessel 

Surveillance Program in LRA Section A.2.1.19.

• The applicant will specify that all pulled and tested capsules, unless discarded before 

August 31, 2000, are placed in storage.

• The applicant will specify that if plant operations exceed the limitations or bounds 

defined by the Reactor Vessel Surveillance Program, such as operating at a lower cold 

leg temperature or higher fluence, the impact of plant operation changes on the extent of 

reactor vessel embrittlement will be evaluated, and the NRC will be notified.

• The applicant will ensure the appropriate withdrawal schedule for capsules remaining in 

the vessel, such that one capsule will be withdrawn at an outage in which the capsule 

receives a neutron fluence that meets the schedule requirements of 10 CFR 50,

Appendix H, and ASTM E185-82 and that bounds the 60-year fluence. The remaining 

capsules(s) will be removed from the vessel unless determined to provide meaningful 

metallurgical data.

• The applicant will ensure that any capsule removed, without the intent to test it, is stored 

in a manner that maintains it in a condition that would permit its future use, including 

during the period of extended operation.

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.12 Selective Leaching of Materials Program

. On the basis of its review of the applicant’s Reactor Vessel Surveillance Program, 

the staff determined that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed 

that their implementation prior to the period of extended operation supports the requirements of 

the AMP. The staff concludes that the applicant demonstrated that the effects of aging will be 

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

for the period of extended operation, as required by 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).

Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the new 

Selective Leaching of Materials Program as consistent, with an exception, with GALL Report 

AMP XI.M33, “Selective Leaching of Materials.” The applicant stated that the Selective 

Leaching of Materials Program will manage the aging effect of loss of material due to selective 

leaching in gray cast iron, copper alloys greater than 8 percent aluminum (e.g., 
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aluminum-bronze) and copper alloy (greater than 15 percent zinc) exposed to raw water, 

brackish water, treated water (including closed-cycle cooling), or groundwater.

The applicant also stated that the program will use one-time visual inspections and mechanical 

test techniques such as chipping, scraping, or hardness testing to determine if selective 

leaching is occurring. The applicant further stated that inspections will include a representative 

sample of the most susceptible locations selected from each material and environment 

combination with a sample size of 20 percent, not to exceed a sample size of 25 components. 

The applicant stated that if evidence of selective leaching is discovered, it will perform an 

engineering evaluation to determine acceptability of the affected components for continued 

service and implement an expansion of the inspection sample size and location.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M33. 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.M33, with the exception of the “parameters monitored or inspected” and 

“detection of aging effects” program elements. For these elements, the staff determined the 

need for additional clarification, which resulted in the issuance of an RAI.

. 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.

GALL Report AMP XI.M33 recommends a possible expansion of the inspection sample size and 

location if selective leaching is detected under the “parameters monitored or inspected” program 

element description. The “detection of aging effects” program element description also 

recommends the initiation of an engineering evaluation to determine the acceptability of the 

affected components if selective leaching has occurred. LRA Section B.2.1.21 states that 

Seabrook has experienced instances of de-aluminization of aluminum bronze components 

having an internal environment of raw seawater. Given that selective leaching of 

aluminum-bronze components has occurred, it is unclear how an expansion of the inspection 

sample sizes and locations are being implemented. By letter dated November 18, 2010, the 

staff issued RAI B.2.1.21-1 requesting that the applicant clarify if the Selective Leaching of 

Materials Program has implemented an expansion of the inspection sample size and location for 

aluminum bronze components given that selective leaching has occurred. The staff asked the 

applicant to describe the methodology and criteria for selecting a representative sample 

population that envelopes all plant systems and working conditions at locations most 

susceptible to selective leaching. If the expansion has not been implemented, the applicant was 

asked to describe any planned inspection and associated activities ahead and to justify the 

methodology, sample size, and location used for selecting components with different material 

and environment combinations for selective leaching inspections.

In its response dated December 17, 2010, the applicant stated that the Selective Leaching of 

Materials Program had been revised to expand the inspection sample size and location for 

aluminum-bronze components upon discovery of unacceptable inspection results. The revised 

program includes a one-time inspection of selected components where selective leaching has 

not been previously identified and periodic inspections of selected components where selective 

leaching has been identified. The applicant further stated that both visual and mechanical 

examination techniques (Brinell hardness testing or other mechanical examination techniques 

such as destructive testing, when appropriate, scraping, chipping, or other types of hardness 

testing) would be used to determine if selective leaching is occurring. The applicant further 
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stated that an initial inspection of the aluminum bronze components of a sample size of 

20 percent of the population with a maximum of 25 locations would be performed within 5 years 

prior to entering the period of extended operation. The selection of locations will consider time 

in service, severity of operating conditions, lowest design margin, and distribution of susceptible 

components across systems within similar material and environment combinations. The 

applicant further stated that followup of unacceptable inspection findings would include an 

evaluation using the Corrective Action Program and a possible expansion of the inspection size 

and location. The applicant also stated that it has previously identified selective leaching in 

aluminum bronze components in raw water; therefore, all in-scope aluminum bronze 

components in a raw water environment will be grouped separately from other copper-alloy

(greater than 15 percent zinc) components and be inspected periodically.

The staff finds the applicant’s response acceptable because the applicant’s revised Selective 

Leaching of Materials Program is consistent with the GALL Report AMP XI.M33 

recommendation of performing a one-time visual inspection of selected components susceptible 

to selective leaching, coupled with either hardness measurements or mechanical examination 

techniques. In addition, the staff noted that the applicant’s inspection selection criteria and 

methodology align with the GALL Report recommendation of 20 percent of the population with a 

maximum sample of 25 be in a representative sample. The staff’s concern described in 

RAI B.2.1.21-1 is resolved.

The staff noted that LRA Tables 3.4.2-1 and 3.4.2-3 list components made of gray cast iron and 

copper alloy (great than 15 percent zinc) that are exposed to steam (internal), which is not 

included in the B.2.1.21 program description. By letter dated January 21, 2011, the staff issued 

RAI B.2.1.21-2 requesting that the applicant clarify whether steam (internal) is an environment 

for the Selective Leaching Materials Program.

In its response dated February 18, 2011, the applicant stated that steam is regarded as a form 

of treated water and is an environment applicable to selective leaching. The applicant further 

stated that it had revised the scope of LRA Section B.2.1.21 to include steam as one of the 

environments applicable to selective leaching.

The staff finds the applicant’s response acceptable because the scope of the Selective 

Leaching of Materials Program has been expanded to envelope steam as one of the 

environments applicable to selective leaching, which aligns the program description of this AMP 

with the components in LRA Tables 3.4.2-1 and 3.4.2-3. The staff’s concern described in 

RAI B.2.1.21-2 is resolved.

The staff also reviewed the portion of the “detection of aging effects” program element 

associated with the exception to determine if the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of this exception follows.

Exception 1. LRA Section B.2.1.21 states an exception to the “detection of aging effects” 

program element. The GALL Report recommends visual inspections of the susceptible 

components and Brinell hardness testing on the inside surfaces of the selected set of 

components to determine if selective leaching has occurred. The applicant stated that it will use 

visual inspections and mechanical examination techniques, including Brinell hardness testing or 

other mechanical examination techniques such as scraping, chipping, or other types of 

hardness testing, or additional examination methods that become available to the nuclear 

industry, to determine if selective leaching is occurring on the surfaces of a selected set of 

components.
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The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because the form and configuration of many components do not physically allow 

access for Brinell hardness testing and that additional mechanical testing techniques are 

needed. The staff finds the program’s exception acceptable because the mechanical 

examination techniques proposed by the applicant, such as scraping, chipping, or other types of 

hardness testing, are capable to detecting the aging effect of loss of material due to selective 

leaching.

Regarding the additional examination methods that will become available, the staff does not

have sufficient information to evaluate the effectiveness of such methods. By letter dated 

January 21, 2011, the staff issued RAI B.2.1.21-3 requesting that the applicant state how the 

new process would be evaluated and qualified to detect selective leaching of material on the 

surfaces in components made of gray cast iron and copper alloys greater than 15 percent zinc 

exposed to the environment of interest.

In its response dated February 18, 2011, the applicant stated that the statement “additional 

examination methods that become available to the nuclear industry” was included in the LRA in 

anticipation of new technologies that may be available prior to the implementation of this AMP. 

The applicant further stated that this statement had been removed from the LRA in response to 

this RAI.

The staff finds the applicant’s response acceptable because deletion of such statement 

removes ambiguity from this AMP. The staff noted that the revised program description (i.e., 

visual examination and mechanical examination techniques (Brinell hardness testing or other 

mechanical examination techniques such as destructive testing, when appropriate, scraping, 

chipping, or other types of hardness testing)) is consistent with the GALL Report AMP XI.M33 

Selective Leaching of Materials recommendation of a one-time visual examination and hardness 

measurement of sample components. The staff’s concern described in RAI B.2.1.21-3 is 

resolved.

Based on its audit and review of the applicant’s response to RAIs B.2.1.21-1, B.2.1.21-2, and 

B.2.1.21-3, the staff finds that elements one through six of the applicant’s Selective Leaching of 

Materials Program, with acceptable exception, are consistent with the corresponding program 

elements of GALL Report AMP XI.M33 and, therefore, are acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated operating 

experience related to this program.

. LRA Section B.2.1.21 summarizes operating experience related to the 

Selective Leaching of Materials Program. The applicant stated that de-aluminization of 

aluminum-bronze pipe fittings, flanges, and unions exposed to raw seawater has occurred. The 

applicant also stated that appropriate corrective actions had been taken to replace the 

aluminum-bronze fittings with copper-nickel components for the piping systems. The applicant 

further stated that plant-specific guidance for evaluation, repair, or replacement is provided for 

locations where de-aluminization was found.
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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 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. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment No. 23) to implement the new 

Selective Leaching of Materials Program for managing aging of applicable components within 

5 years prior to the period of extended operation, as stated in the applicant’s supplement 2 to its 

LRA dated November 15, 2010. 

. LRA Section A.2.1.21 provides the UFSAR supplement for the Selective 

Leaching of Materials 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 Tables 3.1-2, 3.2-2, and 3.3-2.

The staff noted that the applicant did not include the recommended description in the SRP-LR, 

which states, “[f]or systems subjected to environments where water is not treated (i.e., the 

open-cycle cooling water system and the ultimate heat sink), the program also follows the 

guidance in NRC GL 89-13.” However, the staff noted that LRA Sections B.2.1.11 and A.2.1.11 

state that the Open-Cycle Cooling Water System Program relies on the recommendations of 

NRC GL 89-13. The staff finds the applicant’s commitment to GL 89-13 in its Open-Cycle 

Cooling Water System Program sufficient to ensure that the aging effects of selective leaching 

will be adequately managed.

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.13 One-Time Inspection of ASME Code Class 1 Small-Bore Piping

. On the basis of its audit and review of the applicant’s Selective Leaching of 

Materials Program, the staff determined that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exception and its justification and determined that the AMP, with the exception, is adequate to 

manage the aging effects for which the LRA credits it. The staff concludes that the applicant 

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).

Summary of Technical Information in the Application. LRA Section B.2.1.23 describes the new 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program as consistent, with an 

exception, with GALL Report AMP XI.M35, “One-Time Inspection of ASME Code Class 1 Small 

Bore Piping.” The applicant stated that this new program will manage the aging effects of 

cracking in stainless steel small-bore ASME Code Class 1 piping less than 4 in. nominal pipe 

size (NPS). The applicant further stated that cracking due to SCC, thermal fatigue, and 
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mechanical fatigue will be identified by performing volumetric examinations. The applicant 

stated that it will select a sample from the total population of ASME Code Class 1 piping based 

on susceptibility, inspectability, dose considerations, operating experience, and limiting locations 

as recommended in Materials Reliability Program (MRP)-146, “Materials Reliability Program: 

Management of Thermal Fatigue in Normally Stagnant Non-Isolable Reactor Coolant System 

Branch Lines.” The applicant also stated that this sample population will include both butt and 

socket welds and that, if non-destructive volumetric inspection techniques have not been 

qualified, it will have the option to remove the weld for destructive examination. The applicant 

further stated that cracking of small-bore ASME Code Class 1 piping has not been observed.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M35. 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.M35, with the exception of the “monitoring and trending” program 

element. For this element, the staff determined the need for additional clarification, which 

resulted in the issuance of an RAI.

. 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.

GALL Report AMP XI.M35 recommends that a one-time volumetric inspection is an acceptable 

method for confirming the absence of cracking in ASME Code Class 1 small-bore piping. The 

GALL Report also states that the inspection of small-bore piping should be performed at a 

sufficient number of locations to assure an adequate sample. The GALL Report further states 

that this number, or sample size, will be based on susceptibility, inspectability, dose 

considerations, operating experience, and limiting locations of the total population of ASME 

Code Class 1 small-bore pipes. Furthermore, MRP-146 provides guidelines for identifying 

piping susceptible to one subset of cracking, including thermal stratification or turbulent 

penetrations. During its audit, the staff found that the applicant will inspect for cracking in ASME 

Code Class 1 small-bore piping using available volumetric examination techniques. The 

applicant also stated that if non-destructive volumetric examination techniques have not been 

qualified, it will have the option to remove the weld for destructive examination. Furthermore,

the applicant stated during the onsite audit that it will inspect 10 percent of the butt welds and 

10 percent of the socket welds and that it may not inspect certain welds based on inaccessibility 

or high radiation exposure. 

It was not clear to the staff if the applicant will either conduct an acceptable volumetric 

inspection or plan to do destructive examination based on the applicant’s program basis 

document, which states that if an acceptable volumetric examination is not available before the 

period of extended operation, the applicant will have a choice to do destructive examinations. In 

addition, it is not clear to the staff if the applicant is proposing to inspect weld locations that are 

mainly susceptible to thermal loading because the applicant’s sampling methodology for the 

inspection was not presented. It was also not clear to the staff what area (base metal or weld 

metal) of the socket weld the examination would inspect. By letter dated December 14, 2010, 

the staff issued RAI B.2.1.23-1 requesting that the applicant do the following:

• clarify how the use of destructive examination is an “option” within the program and 

UFSAR supplement if an “acceptable” volumetric method isn’t available

• clarify what is meant by an “acceptable” volumetric inspection
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• describe the methodology for choosing the types of welds to inspect and how this 

methodology will ensure the AMP adequately manages the effects of all forms of 

cracking during the period of extended operation

• explain how inaccessible or high radiation exposure welds will be managed by the AMP

• clarify the proposed volumetric examination for socket welds

• justify that the examination volume is sufficient and capable of detecting cracking in the 

subject socket welds

In its response dated January 13, 2011, the applicant replied to all parts of the request. The 

applicant stated that, as a way to clarify the use of the word “optional,” the program has been 

modified to specify that, if no demonstrated method of non-destructive volumetric examination 

capable of detecting cracking in a socket weld is available, the applicant will remove selected 

weld(s) for destructive examination. The staff finds that a destructive examination is an 

acceptable alternative because it will provide direct evidence whether aging is occurring when 

compared to a non-destructive examination. The applicant stated that it modified the program 

to state that the volumetric inspection technique to be used should be “demonstrated” to have 

the capability of detecting cracking. The applicant stated that approximately 450 ASME Code 

Class 1 small-bore welds have been identified and approximately 150 of these are socket 

welds. The applicant further stated that its inspection will include at least 10 percent of the total 

number of these welds. The applicant also stated it modified its One-Time Inspection of ASME 

Code Class 1 Small-Bore Piping Program to state that the sample selection will give priority to 

location determined to be most susceptible to SCC and to cycling loading (including thermal, 

mechanical, and vibrational fatigue). The applicant stated that, for specific locations that are not 

selected because of accessibility or radiation exposures, a location with similar susceptibility will 

be identified to replace it in the sample selection. The staff finds that the inspection of one 

location to be representative of another location that is not accessible or has a higher radiation 

exposure is an acceptable technique because the surrogate inspection, with the same 

susceptibility to aging, will provide comparable results. Finally, the applicant stated that socket 

welds will be examined to the maximum extent possible using methods demonstrated to detect 

cracking in socket welds. The applicant stated that the target of the socket weld will be the weld 

and not the piping downstream, as described in MRP-146.

Based on its review, the staff finds the applicant’s response to RAI B.2.1.23-1 acceptable 

because the applicant’s modifications to the program, as described above, will evaluate an 

adequate number of welds to manage cracking with either a demonstrated non-destructive 

volumetric examination or destructive examination, which makes the applicant’s program 

consistent with the GALL Report AMP XI.M35. The staff’s concern described in RAI B.2.1.23-1 

is resolved.

The staff also reviewed the portions of the “scope of program” program element associated with 

an exception to determine if the program will be adequate to manage the aging effects for which 

it is credited. The staff’s evaluation of this exception follows.

Exception 1. LRA Section B.2.1.23 states an exception to the “scope of program” program 

element. The applicant stated that it plans to use the guidance in MRP-146, “Materials 

Reliability Program: Management of Thermal Fatigue in Normally Stagnant Non-Isolable 

Reactor Coolant System Branch Lines,” and supplemental guidance in MRP-146-S, “Materials 

Reliability Program: Management of Thermal Fatigue in Normally Stagnant Non-Isolable 

Reactor Coolant System Branch Lines—Supplemental Guidance,” to identify piping susceptible 

to potential effects of thermal stratification or turbulent penetration.
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The staff reviewed the “scope of program” program element of GALL Report AMP XI.M35,

which states that the program should include measures to verify that degradation does not 

occur for ASME Code Class 1 small-bore piping in components susceptible to cracking. The 

“scope of program” program element also states that locations that are susceptible to thermal 

stratification or turbulent penetration can be determined by MRP-24, “Interim Thermal Fatigue 

Management Guideline.” The staff noted that MRP-24 was an interim report that was meant to 

provide early feedback to PWR plant operators and that this report was later updated in the 

MRP-146 and MRP-146-S to expand on the interim guidelines and provide updated information.

Based on its review, the staff finds the program exception acceptable because the applicant is 

using updated reports, which expand upon the interim guidelines provided in MRP-24 by 

incorporating technical knowledge gained from thermal-hydraulic testing and model 

development, which will provide improved guidance on identifying locations susceptible to 

cracking from thermal fatigue.

Based on its audit and review of the applicant’s response to RAI B.2.1.23-1, the staff finds that 

elements one through six of the applicant’s One-Time Inspection of ASME Code Class 1 

Small-Bore Piping Program, with an acceptable exception, are consistent with the 

corresponding program elements of GALL Report AMP XI.M35 and, therefore, are acceptable.

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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.

. LRA Section B.2.1.23 summarizes operating experience related to the 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program. The applicant stated 

that this is a new program and that both plant and industrial operating experience will be used to

establish the program. The applicant further stated that during its second 10-year ISI period, 

the inspections included volumetric examination of twenty-seven 2-in. and 3-in. Class 1 butt 

welds with no cracking being identified. The applicant also stated that it conducted a search of 

condition reports and did not find degradation or failure in any Class 1 piping less than 4 in.

NPS.

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking appropriate corrective actions. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement

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 3.1-2. The 

staff also noted that the applicant committed (Commitment No. 25) to implement the new 

. LRA Section A.1.2.23 provides the UFSAR supplement for the One-Time 

Inspection of ASME Code Class 1 Small-Bore Piping Program.
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One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program within 10 years prior to 

the period of extended operation for managing aging of applicable components.

The staff determined that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.14 External Surfaces Monitoring Program

. On the basis of its audit and review of the applicant’s One-Time Inspection of 

ASME Code Class 1 Small-Bore Piping, the staff determined that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. In addition, the 

staff reviewed the exception and its justification and determined that the AMP, with an 

acceptable exception, is adequate to manage the aging effects for which the LRA credits it. The 

staff concludes that the applicant 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).

Summary of Technical Information in the Application

• hardening and loss of strength due to elastomer degradation

. LRA Section B.2.1.24 describes the 

existing External Surfaces Monitoring Program as consistent, with exceptions and an 

enhancement, with GALL Report AMP XI.M36, “External Surfaces Monitoring.” The applicant 

stated that the program manages the following aging effects:

• reduction of heat transfer due to fouling

• loss of material due to general, pitting, crevice, galvanic, and 

microbiologically-influenced corrosion and due to fouling

• loss of material due to wear

The applicant also stated that the program consists of periodic inspections of components made 

of aluminum, cast austenitic stainless steel (CASS), copper alloy, copper alloy with greater than 

15 percent zinc, elastomer, galvanized steel, gray cast iron, nickel-alloy, stainless steel, and 

steel. The applicant further stated that this program uses periodic inspections and walkdowns

to monitor material degradation and leakage. In addition, the applicant stated that it conducts 

visual inspection of component surfaces at least once per refueling cycle.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M36. 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.M36, with the exception of the “monitoring and trending” program 

element. For this element, the staff determined the need for additional clarification, which 

resulted in the issuance of an RAI.

. 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.

GALL Report AMP XI.M36 recommends periodic plant system inspections and walkdowns to 

monitor for material degradation under the “monitoring or trending” program element 
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description; however, during the onsite audit, staff identified that the applicant’s AMP has 

in-scope components that cannot be reached for hands-on inspection and, therefore, are not 

accessible for the tactile inspection as described in the LRA. By letter dated 

November 18, 2010, the staff issued RAI B.2.1.24-1 requesting that the applicant provide 

information as to how the tactile techniques would be applied for the in-scope components that 

are inaccessible for physical manipulation.

In its response dated December 17, 2010, the applicant stated that when an elastomer is 

inaccessible for tactile inspection, the tactile inspection results of an accessible elastomer of the 

same construction, in a similar environment, with an equivalent age will be used to assess the 

condition of the inaccessible elastomer. The applicant also stated that it will apply the same 

method for determining the condition of metallic components that are inaccessible for visual 

inspection.

The staff finds the applicant’s response acceptable because visual and tactile inspections are 

capable of identifying the aging effects managed by the program prior to loss of intended 

function. Also, inspection of accessible components with similar construction, age, and 

environment to that of inaccessible components is an acceptable method to project the 

condition of components with similar construction, age, and environment which cannot be 

inspected because they are inaccessible. The staff noted that this is an acceptable method 

used to assess the effects of aging for inaccessible components in other AMPs in the GALL 

Report. The staff’s concern described in RAI B.2.1.24-1 is resolved.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements associated with exceptions and enhancement to determine if the program will 

be adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

exceptions and enhancement follows.

Exception 1

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because additional materials are to be covered in the applicant’s AMP, which are 

beyond those recommended by the GALL Report. The staff evaluated the exception and 

determined the need for additional clarification, which resulted in the issuance of an RAI. GALL 

Report AMP XI.M36 states that the program consists of periodic visual inspections of steel 

components such as piping, piping components, ducting, and other components within the 

scope of license renewal under the “Program Description.” However, the applicant indicated 

that the program will be applied to materials other than steel, which is the material specified in 

GALL Report for this AMP. By letter dated November 18, 2010, the staff issued RAI B.2.1.24-2 

requesting that the applicant provide details on additional inspection methods to be used to 

ensure that the AMP will adequately address potential aging effects on the additional in-scope 

materials.

. LRA Section B.2.1.24 states an exception to the “scope of program” program 

element. The applicant stated that its program will manage aging of components made from 

additional materials such as aluminum, CASS, copper alloy, copper alloy with greater than 

15 percent zinc, elastomer, galvanized steel, gray cast iron, nickel alloy, and stainless steel 

whereas the GALL Report recommends the program for steel components.

In its response dated December 17, 2010, the applicant stated that the nuclear industry has 

developed programs to train plant staff on how to correlate an observed condition with possible 

aging effects. The applicant also stated that personnel who perform inspections as part of the 
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implemented license renewal program will be trained and qualified to identify aging effects in the 

additional in-scope materials.

The applicant’s response did not identify any additional inspection methods necessary to 

manage the aging effects for the additional in-scope materials because the External Surfaces 

Monitoring Program includes visual inspections of metallic components and visual inspections 

and tactile examinations of elastomeric components. The staff noted that visual inspection is an 

appropriate inspection method for detecting loss of material in metallic components and 

cracking due to SCC in stainless steel components exposed to outdoor air. The staff also noted 

that visual inspections coupled with tactile examinations are capable of detecting loss of 

material, hardening, and loss of strength in flexible elastomeric components.

The staff finds the applicant’s response acceptable because the visual inspections and tactile 

examinations performed as part of the External Surfaces Monitoring Program are capable of 

detecting the applicable aging effects for the metallic and elastomeric components in the scope 

of the program, and the personnel performing the inspections will be trained and qualified to 

identify the aging effects in the additional materials. The staff’s concern described in 

RAI B.2.1.24-2 is resolved.

Exception 2

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because additional aging effects are to be covered in the applicant’s AMP, which are 

beyond those recommended by the GALL Report. The staff evaluated the exception and 

determined that the exception is adequate because the additional aging effects being managed 

by the program are addressed with corresponding inspection methods. Specifically, the use of 

tactile inspection methods will be used to address the additional aging effects being managed 

for the in-scope elastomers. Additionally, the aging effects of hardening and loss of strength, 

reduction of heat transfer, and loss of material due to galvanic corrosion on the in-scope metallic 

components will be adequately covered by the visual inspections included in the program.

. LRA Section B.2.1.24 states an exception to the “scope of program” and 

“detection of aging effects” program elements. The applicant stated that the program will 

address the additional aging effects of hardening and loss of strength, reduction of heat transfer, 

and loss of material due to galvanic corrosion and wear, whereas the GALL Report 

recommends this program for managing the aging effect of loss of material.

Enhancement 1. LRA Section B.2.1.24 states an enhancement to the “scope of program,” 

“parameters monitored or inspected,” “monitoring and trending,” and “acceptance criteria” 

program elements. The applicant stated that the AMP will be enhanced to more specifically 

address the relevant degradation mechanisms and aging effects, and the inspections will be 

enhanced to address the detection of corrosion under insulation and the materials included in 

the program in addition to the materials for which the GALL Report recommends for this 

program. The applicant also stated that the training requirements for inspectors will be 

enhanced to address the aging effects that are observable on materials included in the program 

in addition to the materials for which the GALL Report recommends for this program. The staff 

evaluated the enhancement against the corresponding program element in GALL Report 

AMP XI.M36. The staff noted that the applicant’s program appropriately identified and 

addressed the additional inspection considerations required for the full set of in-scope materials 

and the concerns for detecting corrosion under insulation. The staff finds the program 

enhancement acceptable because, when implemented, the program elements will be consistent 

with the recommendations in GALL Report AMP XI.M36.
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Based on its audit, and review of the applicant’s responses to RAIs B.2.1.24-1 and 

RAI B.2.1.24-2, the staff finds that elements one through six of the applicant’s External Surfaces 

Monitoring Program, with acceptable exceptions and an enhancement, are consistent with the 

corresponding program elements of GALL Report AMP XI.M36 and, therefore, are acceptable.

Operating Experience

In another instance of operating experience, the applicant stated that corrosion was observed 

on the surface of diesel generator piping. The applicant also stated that ultrasonic 

measurements were taken of the pipe thickness as part of the engineering analysis conducted 

to determine the extent of corrosion. Although the pipe wall thickness was recorded to be below 

the original installation value, an engineering evaluation determined that the applicable design 

code requirements for all design conditions were satisfied; therefore, the measured reduced wall 

thickness was deemed acceptable by the applicant.

. LRA Section B.2.1.24 summarizes operating experience related to the 

External Surfaces Monitoring Program. The applicant stated an instance of operating 

experience in which heat exchanger outlet lines were observed to have corrosion products on 

the external surface, which was attributed to reaction with condensation. The applicant also 

stated that an engineering analysis was conducted after the removal of corrosion products, and 

the analysis indicated that there were no unacceptable levels of corrosion. The staff noted that 

an alternative anti-sweat insulation was used to replace the original insulation, which permitted 

the condensate to be retained on the metal surface of the heat exchanger line.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking appropriate corrective actions. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment No. 26) to enhance the External 

Surfaces Monitoring Program prior to entering the period of extended operation. Specifically, 

the applicant committed to address the scope of the program, relevant degradation mechanisms 

and effects of interest, the RFO inspection frequency, the inspections of opportunity for possible 

corrosion under insulation, the training requirements for inspectors, and the required periodic 

reviews to determine program effectiveness.

. LRA Section A.2.1.24 provides the UFSAR supplement for the External 

Surfaces Monitoring 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 Tables 3.2-2, 3.3-2, and 3.4-2.
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The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.15 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program

. On the basis of its audit and review of the applicant’s External Surfaces Monitoring 

Program, the staff determined that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions 

and their justifications and determined that the AMP, with the exceptions, is adequate to 

manage the aging effects for which the LRA credits it. Also, the staff reviewed the 

enhancement and confirmed that its implementation through Commitment No. 26 prior to the 

period of extended operation would make the existing AMP consistent with the GALL Report to 

which it was compared. The staff concludes that the applicant demonstrated that the effects of 

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 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).

Summary of Technical Information in the Application

• cracking due to SCC

. LRA Section B.2.1.25 describes the new 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as 

consistent, with exceptions, with GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components.” The applicant stated that the program will 

manage the following aging effects:

• loss of material due to general, pitting, crevice, galvanic and microbiologically-influenced 

corrosion and due to fouling

• loss of material due to erosion and wear

• reduction of heat transfer due to fouling

• hardening and loss of strength due to elastomer degradation

The applicant further stated that the program will include inspections of opportunity performed 

during pre-planned periodic system and component surveillances or during maintenance 

activities when the systems are opened and the surfaces made accessible for visual inspection.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.M38. 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.M38, with the exception of the “detection of aging effects,” “parameters 

monitored/inspected,” and “acceptance criteria” program elements. For these elements, the 

staff determined the need for additional clarification, which resulted in the issuance of RAIs.

. 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.

GALL Report AMP XI.M38 recommends periodic inspections for detection of aging effects prior 

to the loss of component function. The GALL Report AMP also recommends that locations be 
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chosen to include conditions likely to exhibit the aging effects under the “detection of aging 

effects” program element description. The applicant’s AMP has in-scope components that 

cannot be reached for hands-on inspection and, therefore, are not accessible for the tactile 

inspection described in the LRA. By letter dated November 18, 2010, the staff issued 

RAI B.2.1.25-1 requesting that the applicant provide information as to how the tactile techniques 

would be applied for the in-scope components that are inaccessible for physical manipulation.

In its response dated December 17, 2010, the applicant stated that when an elastomer is 

inaccessible for tactile inspection, the tactile inspection results of an accessible elastomer of the 

same construction, in a similar environment, with an equivalent age will be used to assess the 

condition of the inaccessible elastomer. The applicant also stated that it will apply the same 

method for determining the condition of metallic components that are inaccessible for visual 

inspection.

The staff finds the applicant’s response acceptable because visual and tactile inspections are 

capable of identifying the aging effects managed by the program prior to loss of intended 

function. Also, inspection of accessible components with similar construction, age, and 

environment to that of inaccessible components is an acceptable method to project the 

condition of components with similar construction, age, and environment which cannot be 

inspected because they are inaccessible. The staff noted that this is an acceptable method 

used to assess the effects of aging for inaccessible components in other AMPs in the GALL 

Report. The staff’s concern described in RAI B.2.1.25-1 is resolved.

GALL Report AMP XI.M38 recommends that the acceptance criteria be established in the 

maintenance and surveillance procedures or other established plant procedures under the 

“detection of aging effects” program element description. The applicant stated that the results of 

the program’s inspections will be used to establish acceptance criteria for the management of 

aging effects of in-scope components, but no specific information was provided on how this will 

be conducted. By letter dated November 18, 2011, the staff issued RAI B.2.1.25-2 requesting 

that the applicant explain how the establishment of new acceptance criteria will be done instead 

of having previously-established acceptance criteria consistent with the GALL Report 

recommendations.

In its response dated December 17, 2010, the applicant revised the LRA to remove the 

statement that acceptance criteria would be established based on results of the program’s 

inspections. The applicant stated that the acceptance criteria for indications of corrosion or 

fouling will be identified in the appropriate inspection procedures and will be part of the training 

and qualification program required for all personnel performing the inspections. The applicant 

also stated that acceptance criteria will include visual indications of corrosion, corrosion 

byproducts, coating degradation, surface discoloration, scale, deposits, pits, and surface 

discontinuities. The applicant further stated that personnel performing the inspections will be 

trained to identify when the as-found condition of the component requires further evaluation 

using the site corrective action program.

The staff finds the applicant’s response acceptable because the applicant will establish 

acceptance criteria in the inspection procedures, and the personnel performing the inspections 

will be trained and qualified to identify when the acceptance criteria have not been met and the 

component condition requires additional evaluation. The staff’s concern described in RAI 

B.2.1.25-2 is resolved.

GALL Report AMP XI.M38 recommends that the visible evidence of corrosion may indicate 

possible loss of materials. The applicant stated that a thin, light, even layer of oxidation 
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provides protection against further corrosion, which is not accurate for most of the in-scope 

materials and, when taken in general context, is not accurate. By letter dated 

November 18, 2011, the staff issued RAI B.2.1.25-3 requesting that the applicant provide 

technical clarification on the specific in-scope materials to which the subject statement is 

intended to describe. The applicant was also asked to explain how this statement pertains to 

monitoring of oxidation by the inspectors in this program.

In its response dated December 17, 2010, the applicant stated that the program will be modified 

to remove the statement that a thin, light, even layer of oxidation provides protection against 

further corrosion. The intent of this sentence was to not provide an inspection criterion but to 

convey that corrosion occurs differently for different materials and in a range of environments. 

The staff finds the applicant’s response acceptable because the applicant corrected a statement 

in the AMP that, although accurate for some in-scope materials, is not accurate for all of the 

materials in-scope for the AMP. The staff’s concern described in RAI B.2.1.25-3 is resolved.

The staff also reviewed the portions of the “scope of program,” and “parameters monitored or 

inspected” program elements associated with exceptions to determine if the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

exceptions follows.

Exception 1

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because additional materials are to be covered in the applicant’s AMP that are not 

covered by other AMPs. The staff evaluated the exception and determined that the exception is 

adequate because the inspection methods included in the program are standard methods that 

are adequate for the detection of age-related degradation that may occur in the materials coved 

by the applicant’s AMP.

. LRA Section B.2.1.25 states an exception to the “scope of program” program 

element. The applicant’s AMP includes components made from additional materials such as 

aluminum, CASS, copper alloy, copper alloy greater than 15 percent zinc, elastomer, galvanized 

steel, gray cast iron, nickel alloy, and stainless steel, whereas the GALL Report recommends 

the program for steel components.

Exception 2

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because additional aging effects is covered in the applicant’s AMP that are beyond 

those recommended by the GALL Report. The staff evaluated the exception and determined 

that the exception is adequate because the additional aging effects being managed by the 

program are addressed with corresponding standard inspection methods. Specifically, the use 

of tactile inspection methods and their correlation to inaccessible components will be used to 

address the additional aging effects being managed for the in-scope elastomers.

. LRA Section B.2.1.25 states an exception to the “parameters monitored or 

inspected” program element. The applicant stated that the program will include inspections for 

the aging effects of cracking, reduction of heat transfer, and hardening and loss of strength.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.25-1, B.2.1.25-2, and 

B.2.1.25-3, the staff finds that elements one through six of the applicant’s Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program, with acceptable 

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

AMP XI.M38 and, therefore, are acceptable.
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Operating Experience

In another instance of operating experience, the applicant described a case in which corrosion 

was found on an internal part of a screen wash system valve during a maintenance activity. 

The applicant stated that the valve was replaced and based on the knowledge of this instance of 

observed degradation, an extent of condition evaluation was performed, on valves in similar 

service environments that could potentially be subjected to the same corrosion effect. The 

applicant stated that preventive maintenance activities were developed for the disassembly and 

inspection of all similar valves with a frequency of every 6 years.

. LRA Section B.2.1.25 summarizes operating experience related to the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

applicant described one instance of operating experience in which corrosion was detected 

inside the shell of a storage tank heat exchanger. The applicant stated that the observation was 

followed by an engineering assessment during which it was determined that the corrosion was 

not significant and no further action was indicated at the time. The applicant further stated that,

during a followup inspection, an ultrasonic examination was performed, and parts of the heat 

exchanger were measured to be below the minimum wall thickness requirement. A base metal 

repair was performed prior to returning the heat exchanger to service.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking appropriate corrective actions. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.1.25 provides the UFSAR supplement for the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff 

reviewed this UFSAR supplement description of the program and noted that it conforms to the 

recommended description for this type of program, as described in SRP-LR Tables 3.2-2, 3.3-2, 

and 3.4-2. The staff also noted that the applicant committed (Commitment No. 27) to implement 

the new Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program prior to entering the period of extended operation for managing aging of applicable 

components. The staff determined 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 applicant’s Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program, the staff determined that 

those program elements for which the applicant claimed consistency with the GALL Report are 

consistent. In addition, the staff reviewed the exceptions and their justifications and determined 

that the AMP, with the exceptions, is adequate to manage the aging effects for which the LRA 

credits it. Also, the staff noted the program’s implementation via Commitment No. 27 prior to 

the period of extended operation. The staff concludes that the applicant demonstrated that the 
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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 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 Lubricating Oil Analysis Program

Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the 

existing Lubricating Oil Analysis Program as consistent, with an exception and enhancements, 

with GALL Report AMP XI.M39, “Lubricating Oil Analysis.” The applicant stated that the 

Lubricating Oil Analysis Program is an existing program that performs oil condition monitoring 

activities to manage the aging effects of loss of material due to galvanic, general, pitting, 

crevice, microbiologically-influenced corrosion, fouling, and heat transfer degradation due to 

fouling. The applicant further stated that the purpose of the Lubricating Oil Analysis Program is 

to obtain and analyze lubricating oil samples from plant equipment to ensure that the oil quality 

is maintained within established limits. The applicant also stated that the program includes 

sampling and analysis of lubricating oil for components within the scope of license renewal and 

subject to an AMR.

Staff Evaluation

The staff also reviewed the portions of the “parameters monitored or inspected” and “detection 

of aging effects” program elements associated with an exception and 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 exception and enhancements follows.

. 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.

Exception 1

The staff reviewed this exception to the GALL Report and noted that the applicant takes 

exception to the GALL Report in that Seabrook does not sample for flash point in lubricating oil 

samples. The staff determined that more information was needed. By letter dated 

December 14, 2010, the staff asked the applicant to discuss the method Seabrook uses to 

determine fuel dilution and explain how it compares to sampling for flash point. 

. LRA Section B.2.1.26 states an exception to the “parameters monitored or 

inspected” program element. The GALL Report recommends that for components that do not 

have regular oil changes, tests for viscosity, neutralization number, and flash point may be used 

to determine lubricating oil suitability for continued use. Alternatively, this program element in 

the LRA states that Seabrook does not sample for flash point in lubricating oil samples. Instead, 

the applicant stated that when there is a potential for lubricating oil contamination by fuel, 

Seabrook will test the samples for fuel dilution. The applicant further stated that testing for fuel 

dilution is equivalent to testing for flash point because either test will provide an indication of fuel 

in-leakage.

In its response by letter dated January 13, 2011, the applicant stated that Seabrook will add 

flash point testing as a requirement for in-scope diesel engine lube oil analysis. The applicant 

indicated that ASTM Standard D 6224-98, “Standard Practice for In-Service Monitoring of 

Lubricating Oil for Auxiliary Power Plant Equipment,” recommends flash point testing to diesel 

engine oils. As such, the applicant stated that flash point is of little significance for determining 
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the degree of degradation of used oil since normal degradation has little effect on the flash 

point.

The applicant stated that Seabrook will limit the flash point testing to those lube oil samples that 

have the potential for contamination by fuel. The applicant stated that potential for fuel 

contamination is limited to the two main emergency diesel generators and the two diesel fire 

pumps. 

The staff finds this exception acceptable and consistent with the one described in the GALL 

Report Section XI.M39 because the program will be enhanced to include flash point testing for 

lube oil samples that have the potential for fuel contamination, the potential for which is limited 

to the two main emergency diesel generators and the two diesel fire pumps. Flash point testing

is an acceptable method used to determine fuel contamination in lubricating oil for components 

that do not have regular oil changes such as the two main emergency diesel generators and the 

two diesel fire pumps.

On the basis of its review, that staff finds this program exception acceptable because this 

program will be enhanced to include flash point testing, which is recommended by the GALL 

Report AMP XI.M39.

Enhancement 1

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.M39.

. LRA Section B.2.1.26 states an enhancement to the “parameters monitored or 

inspected” program element. This enhancement expands on the existing program element by 

adding an attachment list that specifies the required equipment for the program, sampling 

frequency, discussion on the required periodic oil changes, and includes the associated lube oil 

analysis required. In a letter dated January 13, 2011, in response to RAIs by letter dated 

December 14, 2010, the applicant modified this enhancement to include flash point testing for 

lubricating oil that has the potential for contamination by fuel.

Enhancement 2

On the basis of its review, the staff finds this enhancement acceptable because periodic 

sampling and compliance with acceptance criteria ensures lube oil contaminants do not exceed 

acceptable levels, thereby preserving the environment that could lead to the aging effects of 

loss of material. Also, when it is implemented, prior to the period of extended operation, it will 

make the program consistent with the recommendations of GALL Report AMP XI.M39.

. LRA Section B.2.1.26 states an enhancement to the “detection of aging 

effects” program element. This enhancement expands on the existing program element by 

adding a requirement to sample the oil for the reactor coolant pump oil collection tanks.

Enhancement 3

On the basis of its review, the staff finds this enhancement acceptable because compliance with 

acceptance criteria ensures lube oil contaminants do not exceed acceptable levels, thereby 

preserving the environment that could lead to the aging effects of loss of material. Also, when it 

is implemented, prior to the period of extended operation, it will make the program consistent 

with the recommendations of GALL Report AMP XI.M39.

. LRA Section B.2.1.26 states an enhancement to the “detection of aging 

effects” program element. This enhancement expands on the existing program element by 

adding a requirement to perform a one-time ultrasonic thickness measurement of the lower 

portion of the reactor coolant pump oil collection tanks prior to the period of extended operation.
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Based on its audit, the staff finds that program elements one through six of the applicant’s 

Lubricating Oil Analysis Program, with acceptable exception and enhancements, are consistent 

with the corresponding program elements of GALL Report AMP XI.M39 and, therefore, are 

acceptable.

Operating Experience

The staff reviewed the operating experience information, in the application and during the audit,

to determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated operating 

experience related to this program.

. LRA Section B.2.1.26 summarizes operating experience related to the 

Lubricating Oil Analysis Program. The staff reviewed this information and interviewed the 

applicant’s technical personnel to confirm that the applicable aging effects and industry- and 

plant-specific operating experience have been reviewed by the applicant and are evaluated in 

the GALL Report. During the audit, the staff independently confirmed that the applicant 

adequately incorporated and evaluated operating experience related to this program.

During its review, the staff found no operating experience to indicate that the applicant’s 

program would be ineffective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the application taking appropriate corrective actions. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment Nos. 28, 29, and 30) to enhance 

the Lubricating Oil Analysis Program prior to entering the period of extended operation. 

Specifically, the applicant committed to do the following:

. LRA Section A.2.1.26 provides the UFSAR supplement for the Lubricating 

Oil Analysis Program. The staff reviewed the 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 Tables 3.2-2, 3.3-2, and 3.4-2.

(1) Enhance the program to add required equipment, lube oil analysis 

required, sampling frequency, and periodic oil changes. In addition, the 

program will be required to include flash point testing when there is a 

potential for contamination of the lubricating oil by fuel.

(2) Enhance the program to sample the oil for the Reactor Coolant pump oil 

collection tanks.

(3) Enhance the program to require the performance of a one-time ultrasonic 

thickness measurement of the lower portion of the Reactor Coolant pump 

oil collection tanks prior to the period of extended operation.

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).
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Conclusion

3.0.3.2.17 ASME Code Section XI, Subsection IWL Aging Management Program

. On the basis of its audit and review of the applicant’s Lubricating Oil Analysis 

Program, the staff determined that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determined that the AMP, with the exception, is adequate to manage the 

aging effects for which the LRA credits it. Also, the staff reviewed the enhancements and 

confirmed that their implementation through Commitment Nos. 28, 29, and 30 prior to the period 

of extended operation would make the existing AMP consistent with the GALL Report AMP to 

which it was compared. The staff concludes that the applicant demonstrated that the effects of 

aging will be adequately managed so that the intended function 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).

1

Summary of Technical Information in the Application. LRA Section B.2.1.28 describes the 

existing ASME Code Section XI, Subsection IWL AMP as consistent, with enhancements, with 

GALL Report AMP XI.S2, “ASME Code Section XI, Subsection IWL.” This program manages 

aging effects to the reinforced concrete containment building and complies with examination 

requirements in 10 CFR 50.55a. According to the applicant, the examinations are performed in 

accordance with ASME B&PV Code, Section XI, Subsection IWL, “Requirements for Class CC 

Concrete Components of Light-Water Cooled Power Plants.” The applicant further states that 

all accessible reinforced concrete containment components are within the scope of this 

program. In addition, the applicant will evaluate the acceptability of concrete in inaccessible 

areas of the containment when conditions exist in accessible areas that could indicate the 

presence of or result in degradation to such inaccessible areas.

Summary of Staff Evaluation. The staff has reviewed the various elements of the concrete 

containment aging management program and found them consistent with the corresponding 

program elements of GALL Report AMP XI.S2; however, based on the lack of understanding of 

alkali-silica reaction (ASR) and its impacts, the staff determined that the applicant needs to 

enhance the ASME Code Section XI, Subsection IWL aging management program to 

demonstrate the effects of ASR will be adequately managed. The enhancements are required 

to the program elements “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria.” The staff is concerned that the applicant 

has not performed adequate testing and evaluation of the cracked area in the containment to 

determine if the cracks are due to ASR in the concrete, which has affected other nearby 

structures. In addition, the staff is concerned that the applicant has not implemented permanent 

measures to dewater the annular space between the containment and containment enclosure 

buildings. The staff's concerns are tracked as Open Items OI 3.0.3.1.9-1 and OI 3.0.3.2.18-1. 

Until these open items are resolved, the staff will not be able to conclude that the effects of 

aging will be adequately managed.

Staff Evaluation

 1 The applicant submitted a supplement to the LRA dated May 16, 2012, which addresses a plant-specific aging management 

program entitled "Alkali-Silica Reaction Monitoring Program." The staff is currently reviewing this supplement, and therefore, its 

evaluation is not included in this SER with open items. 

. The Seabrook containment is a concrete cylinder topped with a hemispherical 

dome, supported on a reinforced concrete foundation mat. The concrete containment is 

completely contained within the containment enclosure building and is not exposed to an 

outdoor environment. The containment enclosure building is also a concrete cylinder with a 

hemispherical dome. There is an annular space of five feet between the containment and the 
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containment enclosure building. The below grade portion of the containment is not in contact 

with the soil or ground water. However, for some time in the past, the bottom 6 feet of the 

concrete containment cylinder was in contact with groundwater that leaked through the 

containment enclosure building and filled the annular space. The groundwater from this area 

has since been removed, and the applicant has committed to keep this annular space dry in the 

future. Two isolated areas of the concrete containment that were previously exposed to the 

groundwater have indications of cracking. 

This section of the SER addresses the staff's review and evaluation of the applicant's aging 

management program for the Seabrook concrete containment only. The aging management 

program for the other in-scope concrete structures, including the containment enclosure 

building, is described in Section 3.0.3.2.18 of this SER. 

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 one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.S2. 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.S2, with the exception of the “acceptance criteria” program element. For this 

element, the staff determined the need for additional clarification, which resulted in the issuance 

of RAIs.

GALL Report AMP XI.S2 recommends the acceptance criteria for concrete containments 

provided in IWL-3000. For concrete surfaces, the acceptance criteria rely on the determination 

of the “responsible engineer” regarding whether there is any evidence of damage or degradation 

sufficient to warrant further evaluation or repair. In addition, GALL Report AMP XI.S2 states 

that quantitative acceptance criteria based on the “evaluation criteria” provided in Chapter 5 of 

ACI 349.3R may also be used to augment the qualitative assessment of the responsible 

engineer. During its audit, the staff found that the preventive maintenance work orders that are 

used for tracking and identifying conditions and the site procedure that describes acceptance 

criteria for concrete containment surface evaluations do not implement the three-tier evaluation 

criteria in Chapter 5 of ACI 349.3R. The staff also found that visual inspection results for the 

concrete containment indicated numerous areas of spalled concrete that equaled or exceeded a 

depth of 1 in. In accordance with evaluation criteria in ACI 349.3R-02, Section 5.1, spalled 

areas that exceed a depth of 3

/8 in. and 4 in. in any dimension must be evaluated.

By letter dated November 18, 2010, the staff issued RAI B.2.1.28-1 requesting that the applicant 

provide the basis for acceptance criteria in its site procedure for evaluating concrete 

containment surfaces. The applicant was also asked to describe actions taken to address 

issues identified in NRC IN 2010-14, “Containment Concrete Surface Condition Examination 

Frequency and Acceptance Criteria.” In its response dated December 17, 2010, the applicant 

stated the following:

Any Containment concrete degradation identified during IWL Examinations is 

documented (per the implementing procedure) on Examination Forms, using the 

guidance of ACI 349.3R and ACI 201.1R for condition quantification, description 

and terminology. The degraded area is marked in the field with an identifying 

label to guide the Responsible Engineer's review, and subsequent Examination 

review. An Action Request (AR) is generated for Examination Forms that 

document degradation, requiring an Evaluation by the Responsible Engineer. 
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The Forms and Evaluations are retained and reviewed prior to the next 

Examination. During the subsequent Examination, previously reported areas are 

re-examined to determine if there has been any change in their condition. The 

retained Forms and Evaluations from each successive Examination will be 

maintained up to and through the Period of Extended Operation, thereby creating 

a continuous record of the condition of the Containment concrete.

The applicant also stated that, in response to IN 2010-14, “Containment Concrete Surface 

Condition Examination Frequency and Acceptance Criteria,” the Seabrook Inservice Inspection 

Procedure Primary Containment Section XI IWL Program was revised in October 2010 to 

include the guidance of ACI 201.1R and ACI 349.3R for identifying degradation during general 

visual examinations. 

The staff finds that the revision made to the Seabrook Inservice Inspection Procedure Primary 

Containment Section XI IWL Program to include guidance in ACI 349.3R is acceptable because 

use of quantitative acceptance criteria based on the “evaluation criteria” provided in Chapter 5 

of ACI 349.3R makes the applicant’s AMP consistent with GALL Report AMP XI.S2. The staff’s 

concern described in RAI B.2.1.28-1 is resolved.

By letter dated November 18, 2010, the staff issued RAI B.2.1.28-2 requesting that the applicant 

describe the methods used to evaluate spalled areas that exceed a depth of 3

/8 in. and 4 in. in 

any dimension. The applicant was also asked to provide findings from the most recent 

engineering evaluation report that was prepared to comply with ASME Code Section XI, 

Subsection IWL-3310 requirements.

In its response dated December 17, 2010, the applicant stated that prior to August 18, 2010, 

IWL examinations were conducted in accordance with ASME Code Section XI, Subsection IWL, 

of the 1995 Code with 1996 Addendum. During this time, deficiencies were reported in 

qualitative terms and evaluations were conducted by the responsible engineer, a licensed 

professional engineer, using the methodology described in the response to RAI B.2.1.28-1. The 

applicant further stated that the September 2010 IWL examination was conducted in 

accordance with ASME Code Section XI, Subsection IWL, of the 2004 Code and with the 

guidance of ACI 201.1R and ACI 349.3R. For this examination, deficiencies were reported in 

the quantitative terms of ACI 349.3R and evaluations were conducted by the responsible 

engineer, a licensed professional engineer, with the guidance of ACI 349.3R. The applicant 

also provided the following summary of findings from the September 2010 IWL examination:

Five Action Requests (ARs) were issued during the ASME Code Section XI, IWL 

examinations of the Containment concrete; eighty-four (84) deficient areas were 

identified that required an Engineering Evaluation.

Each of the reported discontinuities in the Containment concrete were 

individually reviewed and evaluated by Design Engineering. All of the reported 

discontinuities were accepted-as-is with no further technical evaluation or 

remediation, based on the criteria of ACI 349.3R.

The staff finds that use of acceptance criteria in ACI 349.3R to evaluate concrete containment 

deficiencies and discontinuities is acceptable because use of these criteria makes the 

applicant’s program consistent with GALL Report AMP XI.S2. The staff’s concern described in 

RAI B.2.1.28-2 is resolved.
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The staff also reviewed the portions of the “acceptance criteria,” “parameters monitored or 

inspected,” and “preventive actions” 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

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.S2. The staff noted that the applicant’s procedure for implementing its ASME 

Code Section XI, Subsection IWL AMP requires that the responsible engineer be a registered 

professional engineer experienced in evaluating the inservice condition of structural concrete 

and knowledgeable of the design and construction codes and other criteria used in design and 

construction of concrete containments. The staff finds this enhancement involving the definition 

of responsible engineer acceptable because it is consistent with the guidance provided in GALL 

Report AMP XI.S2 and IWL-2310 requirements.

. LRA Section B.2.1.28 states an enhancement to the “acceptance criteria” 

program element. This enhancement involves including the definition of “responsible engineer” 

(registered professional engineer) in the applicant’s procedure for implementing its ASME Code

Section XI, Subsection IWL AMP.

Enhancement 2

The staff reviewed the applicant's response concerning the elimination of Enhancement 2 and 

Commitment 51 and found it unacceptable. The staff's basis for this conclusion is described 

later in this SER section. This item is tracked as Open Item OI 3.0.3.2.18-1.

. By letter dated December 17, 2010, the applicant revised LRA 

Section B.2.1.28 to include an enhancement to the “parameters monitored or inspected” 

program element. This enhancement involves performing confirmatory testing and evaluation of 

the containment structure concrete. The testing and evaluation will determine the concrete 

compressive strength, the presence or absence of alkali-silica reaction (ASR), the concrete 

modulus of elasticity, and the presence or absence of rebar degradation. The testing and 

evaluation will be completed prior to the period of extended operation. However, by letter dated 

August 11, 2011, the applicant eliminated this enhancement and associated Commitment 51 

from the LRA. The applicant stated that program enhancement and commitment confirmatory 

testing cannot be made until aging effects due to ASR are fully understood. The applicant 

further stated that information regarding the planned approach to addressing ASR degradation 

throughout the site will be included in the engineering evaluation scheduled to be completed by 

March 2012. 

Enhancement 3

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.S2. The staff noted that no preventive actions are specified in GALL Report 

AMP XI.S2. However, maintaining the exterior surface of the containment structure from 

elevation -30 ft to +20 ft in a dewatered state is an appropriate preventive action because it will 

ensure that the exterior surface of the concrete containment will not be exposed to water that 

could contribute to cracking due to expansion and reaction with aggregates. In addition, during 

September 2011, NRC inspectors examined the subject area and found the exterior surface of 

the containment to be in a dewatered state. Portable sump pumps are used to dewater the 

area. However, the staff is concerned that until now the applicant has not implemented 

. By letter dated December 17, 2010, the applicant revised LRA 

Section B.2.1.28 to include an enhancement to the “preventive actions” program element. This 

enhancement involves implementing measures to maintain the exterior surface of the 

containment structure from elevation -30 ft to +20 ft in a dewatered state. These measures will 

be implemented prior to the period of extended operation.
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permanent measures for dewatering and revised procedures for routine inspection of this area. 

The staff's concern is tracked as Open Item OI 3.0.3.1.9-1.

Based on its audit, and review of the applicant’s responses to RAI B.2.1.28-1 and 

RAI B.2.1.28-2, the staff finds that elements one through six of the applicant’s ASME Code

Section XI, Subsection IWL AMP, with acceptable enhancements, are consistent with the 

corresponding program elements of GALL Report AMP XI.S2. However, as discussed below, 

the staff has determined that the applicant needs to resolve Open Item OI 3.0.3.2.18-1 by 

enhancing program elements “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria,” of the ASME Code Section XI, Subsection 

IWL AMP to demonstrate the effects of ASR will be adequately managed. 

Operating Experience

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program.

. LRA Section B.2.1.28 summarizes operating experience related to the 

ASME Code Section XI, Subsection IWL AMP. According to the applicant, this program is 

implemented through Seabrook’s Containment Surface Inspection Program, and the 

containment structure concrete has been found to be in good condition during inspections 

performed in accordance with ASME Code Section XI, Subsection IWL. The applicant further 

stated that containment inspections performed in 2002, 2005, and 2008 were completed 

satisfactorily with no indication of degradation of the concrete surfaces.

During its review, the staff identified operating experience, which could indicate that the 

applicant’s program may not be effective in adequately managing aging effects during the 

period of extended operation. The staff determined the need for additional clarification, which 

resulted in the issuance of RAIs.

In LRA Section B.2.1.28, the applicant stated that concrete degradation due to aggressive 

chemical attack is an aging effect applicable to Seabrook and that the Structures Monitoring 

Program addresses the plan and specific details to determine the effects of aggressive chemical 

attack on the concrete. The applicant further stated that an evaluation will be conducted after 

the testing in the plan is performed, and, if required, actions will be provided using the corrective 

action process for concrete under the Structures Monitoring Program and the ASME Code

Section XI, Subsection IWL AMP.

During the audit, the staff found that initial testing results for concrete samples obtained from 

below-grade areas of other safety-related structures indicate that the concrete in these areas is 

exhibiting cracking due to expansion and reaction with aggregates. In addition, the staff learned 

that the applicant observed about 6 ft of water accumulation in the annulus between the 

containment and the enclosure building. Although water is a contributing factor to 

cement-aggregate reactions as discussed in ACI 349.3R-02, Section 4.2.5, the applicant stated 

that the containment concrete in the annulus does not exhibit evidence of cracking due to 

expansion and reaction with aggregates. A review of Seabrook condition reports by the staff did 

not identify inspection findings that discussed cracking of concrete due to expansion and 

reaction with aggregates or nondestructive or destructive test data that quantify the magnitude 

or extent of cracking of accessible above-grade and below-grade portions of the concrete 

containment.
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By letter dated November 18, 2010, the staff issued RAI B.2.1.28-3 requesting that the applicant 

provide information about the test method or procedure used to confirm that the exterior 

containment concrete surface between elevation -30 ft and +20 ft is not experiencing cracking 

due to expansion and reaction with aggregates. The applicant was also asked to confirm that 

the compressive strength and modulus of elasticity of the containment concrete between 

elevation -30 ft and +20 ft are not affected by cracking due to expansion and reaction with 

aggregates. The staff also asked the applicant to provide results of any existing or planned 

compressive, tensile, and modulus of elasticity of concrete tests for core samples taken from the 

concrete containment between elevation -30 ft and +20 ft.

In its response dated December 17, 2010, the applicant stated that the 2010 ASME Code

Section XI, Subsection IWL 5-year inspection of the containment structure was performed using 

the guidance of ACI 349, “Evaluation of Existing Nuclear Safety-Related Concrete Structures.” 

The applicant also stated that there has been no sign of detrimental cracking in the containment 

structure based on the inspection performed using the guidance of ACI 349.3R. The applicant 

further stated that in the absence of detrimental cracking, there has been no reasonable 

expectation for loss of compressive strength or loss of modulus of elasticity. In addition, the 

applicant will perform confirmatory testing and evaluation of the containment structure concrete 

(Commitment No. 51). The applicant indicated that the testing and evaluation will determine the 

concrete compressive strength, the presence or absence of ASR, the concrete modulus of 

elasticity, and the presence or absence of rebar degradation. The testing and evaluation will be 

completed prior to the period of extended operation. 

Based on its review, the staff found the applicant’s response to RAI B.2.1.28-3 concerning 

confirmatory testing and evaluation of the Containment Structure concrete unacceptable. The 

staff was concerned that the applicant’s commitment (Commitment 51) to complete confirmatory 

testing and evaluation of the containment structure prior to the period of extended operation in 

March 2030 does not adequately support development of an appropriate aging management 

program. Furthermore, contrary to the applicant’s response in the RAI B.2.1.28-3, dated 

December 17, 2010, the applicant informed the staff during the license renewal inspection in 

April 2011 that a portion of containment concrete above the base slab has indications of 

cracking of concrete. Therefore, by letter dated June 28, 2011, the staff issued Follow-up 

RAI B.2.1.28-3 requesting that the applicant verify whether or not the enhancement and 

Commitment 51, regarding testing to confirm containment concrete properties, made in the 

letter dated December 17, 2010, is still valid, and provide detailed plans to monitor the extent of 

cracking and expansion in concrete. 

In its response dated August 11, 2011, the applicant stated that program enhancements and 

commitment to confirmatory testing cannot be made until the aging effects of the ASR are fully 

understood. The applicant also stated that information regarding the planned approach to 

addressing ASR degradation throughout the site will be included in an engineering evaluation 

scheduled to be completed in March 2012. The application also deleted Commitment 51.

In a subsequent letter dated March 30, 2012, the applicant stated that the ASME Section XI, 

Subsection IWL, 5-year inspection of the containment structure was performed in 2010 using 

the guidance of ACI 349. The applicant also stated that additional inspections of the exterior 

surface of the containment structure were performed in September 2011. The results of these 

inspections show a maximum crack width of 8 mils, which is less than the 15 mil criteria for 

acceptance without further evaluation in the first tier of Structural Monitoring Program. The 

inspection revealed two isolated locations of the containment exterior surface that exhibit 

pattern cracking that may be indicative of ASR. The applicant further stated that although the 
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crack width does not meet the Structural Monitoring Program threshold for further evaluation, 

these two locations will be included for further evaluation, and further inspections will be 

performed. Core samples have not been taken and are not currently planned. 

The staff reviewed the applicant’s response and finds it unacceptable because the applicant has 

not confirmed if the cracks are passive or active. The applicant has stated that the crack pattern 

may be due to ASR which is indicative of active cracking. Active cracking observed in a 

structure is required to be investigated because cracking damage can continue or intensify. The 

15 mil crack width acceptance criteria in the ACI 349.3R, incorporated in Structures Monitoring 

Program, is only for passive cracks. ACI 349.3R, Section 5.1 defines passive cracks as those 

having an absence of recent growth and an absence of other degradation mechanism at cracks. 

The staff believes that confirmatory testing is required to determine if ASR is present in the 

Containment Concrete. In addition, the applicant needs to enhance the program elements 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria,” of the ASME Section XI, Subsection IWL AMP for inspection of 

containment concrete to detect the presence of ASR and manage aging of the ASR affected 

areas of the concrete containment. Therefore, the staff concern is unresolved and identified as 

Open Item OI 3.0.3.2.18-1. 

In its response to RAI B.2.1.28-3, dated December 17, 2010, the applicant also stated it will 

implement measures to maintain the exterior surface of the containment structure, from 

elevation -30 ft and +20 ft, in a dewatered state (Commitment No. 52). These measures will be 

in effect prior to the period of extended operation. In a subsequent letter dated April 14, 2011, 

the applicant revised Commitment No. 52 and committed to implement measures by 

December 31, 2012, to maintain the exterior surface of the containment concrete from elevation 

-30 feet to +20 feet dewatered. During the December 31, 2010, inspection, NRC inspectors 

examined the subject area and found it in a dewatered state. Portable sump pumps are used to 

dewater the area. However, as discussed above, the staff is concerned that until now the 

applicant has not implemented any permanent measures for dewatering and revised procedures 

for routine inspection of this area. The staff's concern is tracked as Open Item OI 3.0.3.1.9-1. 

By letter dated November 18, 2010, the staff issued RAI B.2.1.28-4 requesting that the applicant 

provide plans and schedules for the following:

• conducting a baseline inspection of the condition of accessible above-grade and 

below-grade portions of the concrete containment in accordance with ACI 349.3R 

requirements 

• obtaining nondestructive or destructive test data for quantifying the mechanical 

properties (compressive strength, tensile strength, and modulus of elasticity) of concrete 

in areas that have experienced cracking due to expansion and reaction with aggregates

In its response dated December 17, 2010, the applicant stated that the most recent ASME Code

Section XI, Subsection IWL examination of containment concrete was completed in 

October 2010. This examination of the containment concrete consisted of general visual and 

detailed visual examinations consistent with the criteria in ACI 201.1-92 and ACI 349.3R-02. 

The applicant also stated that these two ASME Code IWL concrete examinations will serve as 

the baseline for future examinations of containment concrete, which are performed at 5-year 

intervals. The applicant further stated that the containment is enclosed by the containment 

enclosure building, and the inspection is based on one environment which is air-indoor 

uncontrolled. Measures that the applicant will take to determine the integrity of the containment 

concrete and steel reinforcing bars in areas that have experienced cracking due to expansion 
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and reaction with aggregates are discussed in its response to RAI B.2.1.28-3. As discussed, 

above, the staff has determined that the applicant needs to resolve Open Item OI 3.0.3.2.18-1 

by enhancing program elements “parameters monitored or inspected,” “detection of aging 

effects,” “monitoring and trending,” and “acceptance criteria,” of the ASME Code Section XI, 

Subsection IWL AMP to demonstrate the effects of ASR will be adequately managed.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment Nos. 31 and 52) to enhance the 

ASME Code Section XI, Subsection IWL AMP prior to entering the period of extended 

operation. Specifically, the applicant committed to include the definition for “Responsible 

Engineer” in its procedure for implementing its ASME Code Section XI, Subsection IWL AMP. 

The applicant also committed to implement measures to maintain the exterior surface of the 

containment structure, from elevation -30 feet to +20 feet, in a dewatered state. However, the 

staff is concerned that, until now, the applicant has not implemented Commitment 52 to 

maintain the exterior surface of the containment in a dewatered state.

. LRA Section A.2.1.28 provides the UFSAR supplement for the ASME 

Code Section XI, Subsection IWL AMP. 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 3.5-2.

The staff finds that until Open Items OI 3.0.3.1.9-1 and OI 3.0.3.2.18-1 are resolved, the 

information in the UFSAR supplement, as required by 10 CFR 54.21(d) is not adequate.

Conclusion

3.0.3.2.18 Structures Monitoring Program

. The staff concludes that the applicant has not demonstrated that the effects of 

aging will be adequately managed so that the intended functions will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The 

applicant needs to resolve Open Item OI 3.0.3.2.18-1 by enhancing the program elements 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria,” of the ASME Section XI, Subsection IWL AMP to demonstrate that the 

effects of the ASR in the concrete containment will be adequately managed. Once Open Items 

OI 3.0.3.1.9-1 and OI 3.0.3.2.18-1 are resolved, the applicant will need to make appropriate 

changes to the UFSAR supplement for this AMP to include a complete summary description of 

the program, as required by 10 CFR 54.21(d).

2

Summary of Technical Information in the Application

 2 The applicant submitted a supplement to the LRA dated May 16, 2012, which addresses a plant-specific aging management 

program entitled "Alkali-Silica Reaction Monitoring Program." The staff is currently reviewing this supplement, and therefore, its 

evaluation is not included in this SER with open items. 

. LRA Section B.2.1.31 describes the 

existing Structures Monitoring Program as being consistent, with enhancements, with GALL 

Report AMP XI.S6, “Structures Monitoring Program.” In the LRA, the applicant stated that AMP 

B.2.1.31, “Structures Monitoring Program,” is implemented through the Seabrook Maintenance 

Rule Program and integrates the Masonry Wall Program and RG 1.127, “Inspection of Water 

Control Structures Associated with Nuclear Power Plants,” Program. These programs are 

existing and consistent with the program elements in GALL Report AMP, XI.S5, “Masonry Wall 

Program,” GALL Report AMP XI.S6, “Structures Monitoring Program,” and GALL Report AMP, 

XI.S7, “RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power 

Plants,” with enhancements.
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In the LRA, the applicant stated that the Structures Monitoring Program performs visual 

inspections of structures and structural components for the detection of aging effects specific to 

the particular structure at a frequency determined by the characteristics of the environment in 

which the structure is located. These inspections are performed at an interval not to exceed 

5 years (plus or minus 1 year) for structures in a harsh environment. The applicant also stated 

that a harsh environment is defined as one that is in an area that is routinely subjected to 

outside ambient conditions of very high temperature, high moisture or humidity, frequent large 

cycling of temperatures, frequent exposure to caustic materials, or extremely high radiation 

levels. Structures not found in areas qualifying as a harsh environment are classified as being 

in a mild environment and are inspected on a 10-year basis. Individuals performing the 

inspections and interpreting the results have expertise in the design and inspection of steel, 

concrete, and masonry structures and are either licensed professional engineers experienced in 

this area or will be working under the direction of a licensed professional engineer with expertise 

in this area. The applicant further stated that parameters monitored meet the requirements of 

ACI 349.3R-96, “Evaluation of Existing Nuclear Safety Related Concrete Structures,” and 

ASCE 11-90, “Structural Condition Assessment of Buildings.” Identification of concrete 

deficiencies is based on guidance provided in ACI 201.1R-2, “Guide for Making a Condition 

Survey of Concrete in Service,” and acceptance guidelines use a three-tier hierarchy similar to 

that described in ACI 349.3R-96 9 (i.e., acceptable, acceptable with deficiencies, or 

unacceptable).

In the LRA, the applicant stated that aggressive subsurface environments are monitored by 

sampling the groundwater at 5-year intervals for chloride concentration, sulfate concentration, 

and pH. Inaccessible areas, such as buried concrete foundations, will be examined during 

inspections of opportunity or during focused inspections at 5-year intervals. The applicant also 

stated that although Seabrook has no block or concrete masonry walls used in Category I 

structures, masonry walls in structures and buildings (fire pumphouse, nonessential switchgear 

room, turbine building and yard structure station blackout) performing nonsafety-related

functions are monitored for cracking and evaluated under the Structures Monitoring Program. 

Periodic visual inspections of water control and flood protective structures are within the scope 

of the Structures Monitoring Program and are inspected under the Maintenance Rule Program.

Summary of Staff Evaluation. The staff has reviewed the various elements of the Structures 

Monitoring Program and found them to be consistent with corresponding elements of GALL 

Report AMP; however, based on the lack of understanding of alkali-silica reaction (ASR) and its 

impacts, the staff determined that the applicant needs to enhance the Structures Monitoring 

Program to manage the effects of ASR. The enhancements are required to the program 

elements “parameters monitored or inspected,” “detection of aging effects,” “monitoring and 

trending,” and “acceptance criteria.” This issue is being tracked as Open Item OI 3.0.3.2.18-1. 

Until this open item is resolved, the staff will not be able to conclude that the effects of aging will 

be adequately managed.

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.

. This section of the SER addresses the staff's review and evaluation of the 

applicant's aging management program for all license renewal in-scope concrete structures and 

masonry walls at Seabrook plant except for the concrete containment structure. The aging 

management program for the containment structure is described in Section 3.0.3.2.17 of this 

SER. 
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The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMPs XI.S5, XI.S6, and XI.S7. 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 AMPs XI.S5, XI.S6, and XI.S7.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” 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 the enhancements follows.

The staff noted that inclusion of opportunistic and focused inspections on a 5-year interval 

addresses GALL Report recommendations for examination of exposed portions of the 

below-grade concrete when excavated for any reason and development of a plant-specific AMP 

for plants with aggressive groundwater and soil that have experienced degradation. However, 

the staff also noted that the applicant inspected the remaining in-scope structures on a 5- or 

10-year basis, depending on the structure’s environment. The staff believes it may be 

acceptable to inspect structures on an interval greater than 5 years; however, the applicant 

must provide a list of the structures inspected under the longer interval along with a description 

of their environments and justification for the interval extension. Therefore, by letter dated 

January 5, 2011, the staff requested the applicant to identify the structures that will be inspected 

on a 10-year frequency along with their environments and a summary of past degradation.

In its response, dated February 3, 2011, the applicant stated that a harsh environment is an 

area routinely subjected to outside ambient conditions, high moisture or humidity, very high 

ambient temperatures or frequent large cycling of temperatures (including freezing and 

thawing), frequent exposure to caustic materials, or extremely high radiation levels. A mild 

environment is one that is not harsh. The applicant further stated that, based on ACI 349.3R, 

the evaluation and inspection frequency varies according to the environment, from 5–10 years. 

In accordance with ACI-349.3R, the interior, above-grade portions of the following in-scope of 

license renewal structures are in a mild environment and, therefore, subject to a 10-year 

inspection frequency: 

• the containment enclosure ventilation area

• the control building

• the diesel generator building

• the waste process building and tank farm (selected areas are harsh)

• the emergency feedwater pumphouse building including pre-action valve building

• the fuel storage building

• the primary auxiliary building (selected areas are harsh)

• the turbine generator building

• the fire pumphouse

• the steam generator blowdown recovery building

• the non-essential switchgear building

The applicant also stated that it classified the following structures, following ACI-349.3R 

guidance, to be in a harsh environment and, therefore, subject to a 5-year inspection: 

• all in-scope below-grade structures (interior and exterior)

• all exterior above grade structures

• all structures inside primary containment

• designated areas of the tank farm and of the primary auxiliary building
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• the service water pumphouse

• the circulating water pumphouse

• the intake transition structure

• the discharge transition structure

• the service water cooling tower revetment 

The applicant then reiterated that the past degradation of these structures is discussed in the 

body of the program in the LRA.

The staff reviewed the applicant’s response and found that it needed clarification regarding how 

frequently the spent fuel pool would be inspected and whether or not the inspection frequencies 

outlined in the response applied to all structures within the scope of the Structures Monitoring 

Program or just concrete components. The staff discussed these issues with the applicant 

during a conference call on March 18, 2011. By letter dated May 10, 2012, the applicant 

confirmed that the spent fuel pool is an in-scope below-grade structure and would be inspected 

on a 5-year frequency and that the inspection frequencies outlined in the RAI response dated 

February 3, 2011, applied to all in-scope structures, regardless of the material. The staff finds 

the applicant’s response acceptable because the applicant confirmed the spent fuel pool is an 

in-scope below-grade structure and would be inspected on a 5-year frequency and it outlined

which structures are subject to a 5-year or 10-year inspection, and it aligned the frequency with 

that recommended in ACI-349.3R, which provides the basis for industry standards. In addition 

the applicant confirmed that the 5-year or 10-year inspection frequency based on ACI-349.3R

applies to all structures within the scope of the Structures Monitoring Program. The staff’s 

concern discussed in RAI B.2.1.31-5 is resolved.

Enhancement 1

• inspection of elastomeric materials, aluminum, non-metallic fire proofing, and Lubrite®

. LRA Section B.2.1.31 states an enhancement to “scope of program” that 

expands the scope of the Structures Monitoring Program to add the following:

• inspection of overhead and fuel handling cranes, NUREG-0612 cranes, all supports, 

tanks (1-FP-TK-35-A, 1-FP-TK-35-B, 1-FP-TK-36-A, 1-FP-TK-36-B, and 1-FP-TK-29-A) 

and their supports and foundations, fire house boiler building, safety- and 

nonsafety-related electrical cable manhole and duct bank yard structures, and two fire 

protection water storage tanks

• opportunistic and focused inspections of below-grade and inaccessible concrete at least 

once every 5 years

The staff finds the addition of the above-listed materials, the cranes and support tanks, and 

inspections of opportunity for below-grade and inaccessible concrete to be an acceptable 

enhancement because, when implemented, the Structures Monitoring Program will address the 

materials and structures included within the scope of license renewal. These specific 

enhancements bring the “scope of program” program element of the applicant’s Structures 

Monitoring Program into partial compliance with the “scope of program” program element 

provided in GALL Report AMP XI.S6, “Structures Monitoring Program.” 

However, it was also not clear to the staff how frequently the tanks within the scope of the 

applicant’s Structures Monitoring Program would be inspected. By letter dated 

November 18, 2010, the staff issued RAI B.2.1.17-1 asking the applicant to verify whether the 

Structures Monitoring Program would also include inspection of tank coatings for tanks

1-FP-TK-35-A, 1-FP-TK-35-B, 1-FP-TK-36-A, 1-FP-TK-36-B, and 1-FP-TK-29-A. In its 
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response dated December 17, 2010, the applicant stated that, in addition to monitoring the 

aging effects in the tanks, the program would also include inspection of the external surfaces of 

the aboveground tanks for cracking, flaking, or peeling of paint or coatings. After further review 

of the applicant’s response, it was still not clear how often the applicant plans to visually inspect 

the tanks for cracking, flaking, or peeling of paint or coating(s) and whether it intends to follow 

the Structures Monitoring Program or the Aboveground Steel Tanks Program guidance, which 

recommends visual inspections at least every 2 years. The staff addressed this concern in a 

teleconference with the applicant on March 18, 2011. 

In a supplemental response provided by letter dated April 14, 2011, the applicant further 

clarified RAI B.2.1.17-1 stating that the Structures Monitoring Program will perform external 

visual or tactile (where required) surface inspections every 5 years of the aboveground steel 

tanks 1-FP-TK-35-A, 1-FP-TK-35-B, 1-FP-TK-36-A, 1-FP-TK-36-B, and 1-AB-TK-29 (fire fuel oil, 

fire water, and auxiliary boiler fuel oil tanks) to address cracking, flaking, or peeling of paint, 

coatings, sealants, and caulking. Additionally, the Fire Protection Program will also visually 

inspect these tanks quarterly to assess the condition of their coatings. For tanks that have a 

caulking seal between the tank and the foundation, tactile examination will be performed to 

evaluate the condition of the caulking per the System Walkdown Engineering Guidelines.

The staff finds the applicant’s response acceptable because the applicant will manage potential 

deterioration of the external surfaces of the aboveground tanks for cracking, flaking, or peeling 

of paint or coatings and, where applicable, the condition of caulking through two different 

AMPs—the Structures Monitoring Program and the Fire Protection Program. These two 

programs collectively will assure that the fire fuel oil tanks, fire water tanks, and auxiliary boiler 

fuel oil tanks external surfaces will be monitored so that the tanks can continue to perform 

adequately during the period of extended operation. The quarterly Fire Protection Program 

inspections also meet the frequency recommendation of every 2 years, as stated in the GALL 

Report AMP, Aboveground Steel Tanks Program. The staff’s concerns described in 

RAI B.2.1.17-1 are resolved.

Enhancement 2

It was not clear to the staff, however, how the applicant will use visual inspections to detect 

degradations in elastomeric, aluminum, and non-metallic fire proofing materials before they lose 

their intended functions. The staff addressed this concern in a teleconference with the applicant 

on March 18, 2011. 

. LRA Section B.2.1.31 states an enhancement to “parameters monitored or 

inspected” that expands the Structures Monitoring Program scope to include aging effects of 

elastomers for loss of sealing, leakage, and deterioration of seals; cracking of aluminum; 

abrasion and flaking of non-metallic fire proofing; corrosion, dirt, and distortion of Lubrite®; and 

degradation of below-grade concrete.

In a supplemental response provided by letter dated April 14, 2011, the applicant stated that 

elastomeric roof material inspections will be done by a licensed professional roofing company. 

Every 5 years, the contractor will assess the condition of the roof elastomeric material for 

separation, environmental degradation, and water in-leakage due to weathering through 

physical roof walks and visual inspections. The applicant further stated that, for aluminum and 

non-metallic fire proofing materials, the applicant’s inspectors are either licensed professional 

engineers experienced in this area or individuals working under the supervision of a licensed 

professional engineer with expertise in the design and inspection of steel, concrete, and 

masonry structures. During these inspections, aluminum will be visually inspected like all 

metallic materials (using the material aging effects) while non-metallic fire proofing, which is a 
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sprayed on cementitious material, will be examined the same as concrete. The frequency of 

inspection is based on the environment, as articulated above. Harsh environments inspections 

will be performed every 5 years while those in mild environments will be every 10 years. The 

applicant, however, stated that operating experience may increase the frequency of these 

inspections. The applicant also stated that the acceptance criteria will be based on the 

engineering department standard for the Structures Monitoring Program, which describes the 

aging effects and evaluation criteria based on ACI 349 three-tiered hierarchy and quantitative 

limits. Finally, the applicant stated that upon further review of Table 3.5.2.4 in LRA Chapter 3,

AMR item “Miscellaneous Yard Structures-Aluminum Station Blackout Structures Exposed To 

Air-Outdoor (External Weather),” was updated to reflect the appropriate aging effect for this 

component requiring management to be cracking instead of the originally reported crack 

initiation and crack growth.

The staff finds this enhancement and the clarifications provided by the applicant acceptable 

because inspections are performed periodically by professionals following the criteria laid-out in 

the Structures Monitoring Program. Furthermore, when implemented, this enhancement will 

support the aging effects for the component types to be monitored during the period of extended 

operation and will provide criteria for inspection of seals, aluminum, non-metallic fire proofing, 

Lubrite®, and below-grade concrete. These enhancements of the “parameters monitored or 

inspected” program element of the applicant’s Structures Monitoring Program are consistent

with the “parameters monitored or inspected” program element provided in GALL Report 

AMP XI.S6, “Structures Monitoring Program.” 

Enhancement 3

The staff finds this enhancement acceptable because, when implemented, this enhancement 

will add clarification to the component types to be monitored during the period of extended 

operation so that the extent of degradation of the buried concrete is such that reasonable 

assurance is provided that these components are capable of fulfilling their intended functions. 

These enhancements of the “monitoring and trending” program element of the applicant’s 

Structures Monitoring Program are consistent with the “parameters monitored or inspected” 

program element provided in GALL Report AMP XI.S6, “Structures Monitoring Program.”

. LRA Section B.2.1.31 states an enhancement to the “monitoring and trending” 

program element that expands the Structures Monitoring Program to perform below-grade 

inspections of buried concrete at least once every 5 years through either an opportunistic or 

focused inspection.

Enhancement 4

The staff finds this enhancement acceptable because it supports the Aboveground Steel Tanks 

AMP, and the inclusion of the examinations under the Structures Monitoring Program 

procedures is acceptable. A review of the technical acceptability of the one-time UT 

examination and its comparison to the GALL Report Aboveground Steel Tanks Program

recommendations is discussed in the staff’s review of the Aboveground Steel Tanks Program in 

SER Section 3.0.3.2.9.

. LRA Section B.2.1.31 states an enhancement to the “detection of aging 

effects” program element that expands the Structures Monitoring Program to include one-time 

UT examinations of the two fire protection water storage tanks prior to the period of extended 

operation.

Based on its onsite audit, the staff finds that elements one through six of the applicant’s 

Structures Monitoring Program, which integrates the Masonry Wall Program and the Water 

Control Structures Inspection Program, with acceptable enhancements, are consistent with the 

corresponding program elements of GALL Report AMPs XI.S5, XI.S6, and XI.S7. However, as 
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discussed below, the staff has determined that the applicant needs to resolve Open Item 

OI 3.0.3.2.18-1 by enhancing program elements “parameters monitored or inspected,” 

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria,” of the 

Structures Monitoring AMP to demonstrate that the effects due to ASR will be adequately 

managed during the period of extended operation. 

Operating Experience

The staff reviewed the operating experience information, in the application and during the onsite 

audit, to determine if 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 if 

the applicant adequately incorporated and evaluated operating experience related to this 

program.

. LRA Section B.2.1.31 summarizes operating experience related to the 

Structures Monitoring Program and states that groundwater infiltration through below-grade 

concrete structures has been an issue at Seabrook. Groundwater sampling performed in 

November 2008 and September 2009 found pH values between 6.01–7.51, chloride levels 

between 19–3,900 ppm, and sulfate levels between 10-100 ppm, indicating that the 

groundwater is an aggressive environment. The LRA also states that below-grade concrete 

structures have experienced groundwater infiltration through cracks, capillaries, pore spaces, 

seismic isolation joints, and construction joints. To stop or reduce the infiltration, various 

methods have been used but have had only limited success (e.g., dewatering wells and 

waterproofing agents). The LRA further states that additional testing is planned during the 

second and third quarters of 2010 in areas that experienced groundwater infiltration to 

determine its aging effects and the need for additional remedial action. The LRA finally states 

that visual inspections have been conducted of nonsafety-related masonry for indications of 

cracking and degradation as identified in the “monitoring checklist” of the applicant’s Structures 

Monitoring Program. The condition of water control and flood protection structures has been 

assessed through visual inspections conducted through the applicant’s Structures Monitoring 

Program.

During its review, the staff identified operating experience that could indicate that the applicant’s 

program may not be effective in adequately managing aging effects during the period of 

extended operation. The staff determined the need for additional clarification that resulted in the 

issuance of four RAIs.

During the audit walkdown and review of condition reports, the staff noted that groundwater 

infiltration through below-grade concrete walls has been a chronic issue at the plant. The staff 

also observed indications of leaching and alkali-aggregate reactions occurring in the concrete 

exposed to groundwater infiltration. The staff was unclear if the concrete degradation due to 

groundwater infiltration had been quantified and how the degradation will be managed during 

the period of extended operation. To address the groundwater issue, by letter dated 

November 18, 2010, the staff issued RAI B.2.1.31-1 expressing concerns on the effects of its 

infiltration in the concrete structures and requesting the applicant to provide a summary of all 

concrete mechanical testing performed to date and explain how its results are correlated to the 

actual plant structures. The staff also asked the applicant to provide the root cause of any 

reductions in structural capacities and degraded material properties and explain how the 

followup aging effects would be managed during the period of extended operation.

In its response dated December 17, 2010, the applicant stated that concrete mechanical testing, 

performed in May of 2010, is only reflective of the location where it was conducted. Specifically, 
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the applicant stated that cores were taken and penetration resistance tests (PRT) were 

conducted to evaluate the compressive strength of concrete, at elevation -20 ft of the “B" 

Electrical Tunnel. The average compressive strength for the PRT was 5,340 psi and, for the 

bores, 4,790 psi. The measured strength was approximately 20 percent less than that obtained 

in earlier years. In particular, the PRT performed in 1979 yielded a compressive strength of 

6,759 psi. For the construction test cylinders tested in 1975, the compressive strength was 

6,120 psi. Similarly, analysis of current data indicated a reduction in the original modulus of 

elasticity by about 47 percent. Further, petrographic analysis of the 2010 core samples showed 

evidence of ASR. The applicant further stated that a prompt operability determination 

concluded that the areas of concrete on the “B” electrical tunnel affected by ASR comply with 

the applicable design codes, and the structural integrity of the “B” electrical tunnel is intact with 

all SSCs housed within the tunnel being operable and capable of performing their design 

functions. The applicant finally stated that an extent of condition investigation is in progress to 

test potentially five additional suspect areas (including the containment enclosure building) to 

obtain supplementary information for the assessment of the plant concrete condition and the 

cause of its degradation. The Structures Monitoring Program has recognized ACI 349 as a 

monitoring and inspection standard that will help manage aging effects during the period of 

extended operation. Identified deficiencies will be evaluated and put into the Corrective Action 

Program for resolution (i.e., remediation, corrective, and preventive actions) as required, 

including further structural analysis, if necessary.

After review of the applicant’s response, the staff did not understand what the extent of 

condition assessment would include and how it would ensure the adequacy of susceptible 

concrete during the period of extended operation. The response also lacked information 

regarding approximate completion dates and a probable path forward including the location and 

timing of future tests and proposed remedial actions. Therefore, by letter dated March 17, 2011, 

the staff issued a followup RAI to RAI B.2.1.31-1 asking the applicant to identify the extent and 

timeliness of the assessment and anticipated remediation, including the path forward to ensure 

the concrete would retain its integrity during the period of extended operation.

By letter dated April 14, 2011, the applicant responded to the RAI. In the response, the 

applicant stated that concrete samples had been taken from five additional locations, which 

were chosen because they exhibited groundwater in-leakage and surface cracking indicative of 

ASR. The applicant further explained that an action plan was being developed to address the 

ASR degradation. The plan would include multiple activities to include those listed below:

• identify areas potentially susceptible to ASR

• complete concrete testing in other susceptible areas to determine compressive strength, 

modulus of elasticity, and confirm the presence of ASR

• based on test results, reconcile existing calculations and analyses to ensure structures 

continue to meet all design basis conditions

• perform lab tests to determine the rate of the ASR degradation mechanism and how it 

propagates

• issue an engineering evaluation addressing ASR, the results of testing, and mitigation 

techniques 

• update the Structures Monitoring Program to include guidance on monitoring for ASR, 

including the appropriate frequency of inspection

• develop a long-range plan to implement mitigation techniques to arrest ASR degradation
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The applicant further stated that the implementation of the action plan is tentatively scheduled to 

be completed in December 2013. Finally, the applicant stated that the Structures Monitoring 

Program will be revised to include action for inspection and monitoring of concrete for 

degradation due to ASR.

The staff reviewed the applicant’s response and finds the response lacked specific information 

about what tests (laboratory and in-situ) would be conducted and when. The response also 

made no mention of how possible reductions in concrete shear strength were being estimated 

and addressed. In addition, the RAI response stated that cores were being taken in accordance 

with American Concrete Institute (ACI) 228.1R-03; however, it did not address the statistical 

validity and size of core samples taken or planned at each location. Therefore, by letter dated 

June 29, 2011, the staff issued follow up RAI B.2.1.31-1 requesting the applicant to: 

1) Explain if the current operability evaluation remains valid until the long-term aging 

management plan is developed and implemented.

2) Explain how the concrete tests and evaluations performed so far can be used to 

establish a trend in degradation of the affected structures until the long-term aging 

management plan is implemented. 

3) Provide detailed and comprehensive information regarding the planned approach to 

addressing ASR degradation throughout the site. 

4) Explain how the possibility of a reduction in shear strength capacity due to ASR 

degradation is being evaluated.

By letter dated August 11, 2011, the applicant provided initial response to the RAI. In this 

response, the applicant stated that the current operability determination is expected to remain 

valid but may require modification. The applicant also stated that a comprehensive plan to 

evaluate and address ASR concrete degradation, and develop and implement a long-term

monitoring plan is ongoing and will be included in an engineering evaluation scheduled to be 

completed by March 2012. 

In a subsequent letter dated March 30, 2012, the applicant stated that it has initiated actions to 

perform additional testing to demonstrate that the effects of ASR on in-scope structures can be 

managed to maintain the intended functions of the affected structures through the period of 

extended operation. The applicant also stated that through this testing, quantitative crack limits 

will be developed. The crack limits will be incorporated into the Structural Monitoring Program 

to manage the effects of ASR on concrete structures. The quantitative crack limits will be used 

to develop acceptance criteria such that corrective action can be implemented prior to loss of 

intended function. The applicant also submitted another letter on April 18, 2012, in which it 

stated that the two operability evaluations were revised on October 11, 2011. These revised 

operability evaluations concluded that the ASR affected structures are fully capable of 

performing their intended function and operable with reduced margin. The applicant further 

stated that full qualification will be attained when the testing and analysis plans are completed 

and the long-term resolution is incorporated into the UFSAR and/or other applicable design 

documents. 

The staff reviewed the applicant’s response in the three letters and noted that the applicant 

plans to enhance the Structural Monitoring Program to manage ASR degradation. However, the 

enhancements will not be completed until the long-term additional testing is completed and 

quantitative acceptance criteria for crack limits are developed. The staff is concerned that the 

applicant has not provided the details of the proposed enhancements to the program elements 
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“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria,” to the Structures Monitoring AMP to manage the effects of ASR. A 

revised aging management program with enhancements for managing the ASR degradation, for 

each in-scope concrete structure, is required to demonstrate that the effects of aging will be 

maintained consistent with the current licensing basis for the period of extended operation as 

mandated by 10 CFR 54.21(a)(3). Until the applicant provides an enhanced Structures 

Monitoring Program, this issue is Open Item OI 3.0.3.2.18-1. 

During the audit walkdown and review of condition reports, the staff also noted that groundwater 

infiltration has caused degradation of internal plant structures and components, such as 

supports, base-plates, cable trays, etc. The staff was unclear how the degradation due to 

groundwater infiltration will be managed during the period of extended operation. To address 

this issue, by letter dated November 18, 2010, the staff issued RAI B.2.1.31-2 asking the 

applicant to explain how internal plant structures exposed to groundwater infiltration will be 

managed for additional or accelerated degradation during the period of extended operation.

In its response, dated December 17, 2010, the applicant reiterated that components affected by 

groundwater in-leakage are managed through the plant's Structures Monitoring Program, which 

follows the Structural Engineering Standard Technical Procedure issued in March of 2010. The 

Structures Monitoring Program inspects building structural steel components (e.g., base plates, 

columns, beams, braces, platforms, cable trays, structural bolting, and fasteners) for corrosion, 

peeling paint, excessive support deflections, twisting, warping, or locally deflecting beams and 

columns, loose or missing anchors and fasteners, missing, cracked, or degraded grout under 

the steel base plates, and cracked welds. The program evaluates and assesses each 

component’s acceptability based on the extent of its degradations and then initiates corrective 

actions, followed by additional inspections to verify their effectiveness.

After review of the applicant’s response, it was not clear to the staff why, after the update of the 

procedure in March of 2010, there was still degradation due to in-leakage witnessed during 

audit walkdowns in October of 2010. To this end, by letter dated March 17, 2011, the staff 

issued a followup RAI to RAI B.2.1.31-2 asking the applicant to state what actions will be taken 

to avert further degradation in areas prone to in-leakage.

By letter dated April 14, 2011, the applicant responded to the RAI and stated that deficiencies 

identified in structural steel during structures monitoring inspection are documented on the 

inspection reports and evaluated. The applicant further stated that deficiencies that do not meet 

the acceptance criteria are entered into the Corrective Action Program, and deficiencies that are 

accepted by engineering review are trended for evidence of further degradation. The applicant 

also explained that deficiencies being repaired or trended are subject to follow-up inspections at 

a maximum frequency of 2.5 years. The applicant also stated that the structures monitoring 

procedure has been revised to include specific direction regarding monitoring for the presence 

of water in-leakage.

The staff reviewed the applicant’s response and finds it acceptable because the applicant 

explained that deficiencies are either repaired or accepted by engineering review. If a condition 

is accepted by engineering review, the inspection frequency is adjusted accordingly to provide 

assurance that any further degradation will be properly identified and addressed (e.g., maximum 

inspection frequency of 2.5 years). This approach is consistent with recommendations in the 

GALL Report AMP XI.S6 which recommends that aging effects are evaluated by qualified 

personnel using criteria derived from industry codes and standards contained in the plant 

current licensing bases, including ACI 349.3R. As recommended in ACI 349.3R, the applicant’s 
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inspectors for the Structures Monitoring Program are either licensed professional engineers or 

individuals working under the supervision of a licensed professional engineer with expertise in 

the design and inspection of steel, concrete, and masonry structures. These inspectors are 

qualified and will adjust the inspection frequency depending on the results of the inspection but 

not more than 2.5 years for structural steel components in the areas of ground water in-leakage. 

This is consistent with the guidance in ACI 349.3R that recommends increase in frequency of 

inspection for structures that are found to be degraded beyond acceptance criteria. The staff’s 

concerns described in RAI B.2.1.31-2 and its followup RAI are resolved.

During the audit walkdown and review of condition reports, the staff further noted that 

groundwater infiltration through below-grade concrete walls has been a chronic issue at the 

plant; however, the staff was unable to locate any inspection reports that identified and 

monitored and trended the degradation caused by the infiltration in a quantitative manner. The 

staff concluded that a baseline quantitative concrete inspection of in-scope structures is 

necessary for monitoring and trending degradation during the period of extended operation. To 

address this issue, by letter dated November 18, 2010, the staff issued RAI B.2.1.31-3 

requesting that the applicant discuss plans for conducting a quantitative baseline inspection, in 

accordance with ACI 349.3R, prior to the period of extended operation.

In its response, dated December 17, 2010, the applicant stated that the Structures Monitoring 

Program described in LRA Appendix A, Section A.2.1.31, and LRA Appendix B, 

Section B.2.1.31, has been revised to include the ACI 349.3R guidance for inspections. This is 

reflected in Supplement 2 of the Seabrook LRA, dated November 15, 2010. The implementing 

procedure for the Structures Monitoring Program issued in March of 2010 describes the 

evaluation criteria based on the ACI 349.3R three-tiered hierarchy and quantitative limits.

The staff reviewed the applicant’s response and finds it acceptable because its program is 

upgraded to follow the industry defined three-tiered ACI 349.3R hierarchical standard (i.e., 

acceptance without further evaluation, acceptance after review, conditions requiring further 

evaluation) with quantitative limits. In addition, the new acceptance criteria have already been 

implemented and are being used during current structural inspections. The staff’s concerns 

described in RAI B.2.1.31-3 are resolved.

During the audit and review of program basis documents, the staff noted that the fuel transfer 

canal has shown indications of borated water leakage. In order to complete its review, the staff 

requested additional information on historic and current leakages (values, paths, etc.) and the 

condition of the affected structures. To address this issue, by letter dated November 18, 2010, 

the staff issued RAI B.2.1.31-4 requesting the applicant to discuss the leakage path, current 

status of leak(s), and any other information to demonstrate that the affected structures will be 

able to perform their intended functions during the period of extended operation.

In its response dated December 17, 2010, the applicant itemized historical records dating back 

to 1999. During that year, the applicant performed a root cause study, which identified the 

source of water in the annulus region between the containment building and the containment 

enclosure building to have originated from the spent fuel pool. Immediately, an enclosed tank 

was installed in the spent fuel pool leakoff sump to collect new leakage and to protect the sump 

and the environment from further contamination. Additional actions included protecting 

foundations and groundwater from contamination with selective dewatering through existing 

wells and removing leakage from contaminated systems. From 2000–2004, testing and 

inspection continued in the spent fuel pool, the spent fuel transfer canal, and the cask handling 

area to identify the source of the leak. In 2002, the applicant installed a nonmetallic liner in an 
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attempt to stop the leakage. The applicant further stated that, by 2004, the leak had stopped in 

the spent fuel pool (confirmed by the lack of contaminated water in the sump), but water level 

fluctuations caused the leak in the canal to increase to 350 gallons per day. From 2005–2008, 

the applicant repaired delaminating coatings, and since 2006, the applicant instituted 

programmatic weekly monitoring of the leakage. A 2002 and 2004 chemical analysis of leakage 

indicated that it is compatible to the water in the spent fuel pool.

After review of the applicant’s response, it was not clear to the staff whether the applicant has 

stopped all the leakage and that no through-wall leakage is occurring. In addition, based on 

industry operating experience with failures of spent fuel pool nonmetallic coatings, the staff is 

not confident that the nonmetallic liner is an appropriate long-term fix. To address these issues, 

by letter dated March 17, 2011, the staff issued a follow-up RAI to B.2.1.31-4 requesting that the 

applicant discuss the measures to be taken to demonstrate the integrity of the concrete 

structures exposed to spent fuel pool leakage, including the possibility of core bores from known 

leakage locations. The staff also requested that the applicant explain its conclusion that no 

through-wall leakage is occurring at the present, especially in inaccessible areas. Furthermore, 

the staff asked the applicant to demonstrate that, if a nonmetallic liner is relied upon to stop 

leakage, what measures will be taken to ensure its adequacy during the period of extended 

operation.

By letter dated April 14, 2011, the applicant responded to the RAI and stated that a core-bore 

test would be completed no later than December 31, 2015. The test would take place in an 

area subjected to wetting during the timeframe of the leakage and would test for compression 

strength of the concrete and would expose rebar. The applicant further stated that the spent 

fuel pool leak-off system is routinely hydro-lazed to ensure that it is free-flowing. The applicant 

stated that the leak-off system is the path of least resistance for any water between the liner 

plate and the concrete wall, and leakage from the spent fuel pool would drain to the leak 

collection sump. The sump is periodically sampled and tested for signs of leakage, such as 

boron and tritium. Finally, the applicant stated that the nonmetallic lining is replaced on the 

basis of condition monitoring that will identify when the end of life for the material has been 

reached. The applicant stated that the following activities will be continued during the period of 

extended operation: 

• monitoring of the liner coating coupon system under the Preventative Maintenance (PM),

“Visual Inspection of Coupons Coated with SEFR” 

• continued sampling and analysis of leak system effluent under procedure “Spent Fuel 

Pool Leakage Collection Program”

The staff reviewed the applicant’s response but found the response was unclear in identifying 

where the leakage was coming from and what the leakage values had been historically. In 

addition, the applicant did not identify how frequently the leak-off system was confirmed to be 

clear. To clarify these points, the staff held a conference call with the applicant on 

May 31, 2011. During the conference call, the applicant stated that additional spent fuel pool 

leakage was detected during the spring 2011 outage. Therefore, to address this additional 

operating experience, by letter dated June 29, 2011, the staff issued followup RAI B.2.1.31-4 

requesting the applicant: 

(1) Provide technical justification for the adequacy of the December 31, 2015, deadline for 

the spent fuel pool concrete core bore, or provide a new deadline and appropriate 

justification.
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(2) Identify the frequency that the leak-off system is ensured to be free-flowing.

(3) Provide information on the recent leakage from the spent fuel pool, including the 

probable leakage path and source; whether the leakage is contained within the leak-off 

system; and whether or not chemical analysis will be performed on leakage during the 

period of extended operation.

By letter dated August 11, 2011, the applicant responded to the first request by stating that 

there is not continuous borated water leakage from the spent fuel pool. Currently, any leakage 

collects in a catch basin in sump and does not contact concrete. The applicant further 

committed to confirming the absence of embedded steel corrosion by performing a shallow core 

sample in an area subjected to wetting during the time frame of the spent fuel pool leakage. 

Finally, the applicant stated that the December 31, 2015, deadline was acceptable because 

similar operating experience at other nuclear plants has shown that structural capacity is not 

significantly affected by exposure to borated water.

In response to the second request, the applicant stated that hydro-lazing is performed on the 

spent fuel pool leak-off lines at a 4.5-year frequency, which will be maintained throughout the 

period of extended operation. The applicant also explained that leak-off is recorded once a 

month and reviewed by the system engineer. Unusual leakage, or lack thereof, could be an 

indicator of blockage and would be investigated accordingly.

In response to the third request, the applicant stated that the spent fuel pool leak-off is analyzed 

for gamma and tritium activity. On April 6, 2011, zone 6 of the spent fuel pool leak-off system 

showed a step increase in the tritium activity concentration. The applicant explained that this 

increase occurred coincident with refilling of the cask loading pool, which had previously been 

drained. At this point, the leak rate was estimated at 1.2 gal. per day (gpd). Subsequent 

measurements identified a peak leak rate of approximately 2.57 gpd, which decreased to the 

current level of 0.016 gpd (approximately 2 oz per day). The applicant further explained that, on 

average, approximately 10 gallons per day of groundwater infiltration leaks out of the zone 6 

tell-tale line. The applicant explained that “[t]he volume of spent fuel pool leakage is estimated 

by taking the ratio of the leak-off line tritium concentration to the pool tritium concentration and 

multiplying that value by the amount of zone 6 leakage pumped out from the collection tank. In 

this particular instance, the only leak-off line that indicated any leakage was zone 6.” The 

applicant then stated that there are several potential causes for the increased leakage, including 

a new stainless steel liner plate leak in an area not coated with the non-metallic liner; a failure in 

the non-metallic liner at the same location as a stainless steel liner failure; or a skimmer pit leak. 

The applicant further stated that these possibilities are being addressed with corrective actions, 

including verifying the integrity of the cask loading area liner through drain down and inspection, 

revising procedures for cask filling to limit the pool level, and determining if the current design of 

the skimmer pits is appropriate or if changes can be made to prevent leakage from the pit. 

Finally, the applicant committed to analyze spent fuel pool leak-off for chlorides, sulfates, pH 

and iron for four quarters of 1 year once every 5 years.

The staff reviewed the applicant’s response and was unable to determine the source or flow 

path of the leakage. In response to the first portion of the followup RAI, the applicant stated that 

it “does not have continuous borated water leakage from the spent fuel pool”; however, in 

response to the third portion, the applicant stated “leakage decreased to the current level of 

0.016 gpd.” Based on this response, it is not clear if the spent fuel pool is leaking. The staff 

also noted that the applicant committed to monitor the leakage quarterly for chlorides, sulfates, 

pH, and iron once every 5 years (Commitment No. 68). This approach is unacceptable for 

detecting a possible trend that may indicate degradation such as an increase in the iron content 
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of the leakage. The staff provided its concerns to the applicant during an inspection visit the 

week of September 26, 2011.

To address these concerns, the applicant supplemented its response to followup RAI B.2.1.31-4 

by letter dated November 2, 2011. In its response, the applicant explained that the spent fuel 

pool, cask handling, and fuel transfer canal areas have nine zones that collect leakage. The 

spent fuel pool is separated from the cask handling area and the fuel transfer area by a gate. 

The applicant stated that there have been no incidents of leakage from the spent fuel pool; the 

only incidents of leakage have been from the cask handling and fuel transfer canal areas. The 

applicant further stated that zone 6 is the only leakage collection sample line that routinely has 

water flow, that this zone collects leakage from the cask handling area, and that the majority of 

the water in the zone 6 sample line is from groundwater in-leakage. The applicant further 

clarified that the leakage detected on April 6, 2011, was from zone 6, which meant it was from 

the cask handling area and not the spent fuel pool. The applicant also updated Commitment 

No. 68 to sample the leak-off water once every 3 months.

The staff reviewed the applicant’s supplement and noted that leakage has not occurred from the 

spent fuel pool; all historic leakage has been from the cask handling and fuel transfer canal 

areas. The staff also noted that the applicant plans to sample the leak-off water quarterly, which 

provides reasonable assurance any negative trends in chlorides, sulfates, pH, or iron content 

that could indicate degradation would be captured in a timely fashion. The staff also reviewed 

the original RAI and followups dated December 17, 2010, April 14, 2011, and August 11, 2011, 

and noted that the current leakage is captured within the leak-off system and is collected in the 

spent fuel pool leakage sump. The staff further noted that there has been no operating 

experience with leakage migrating through the concrete walls, except the leakage identified in 

1999, which was leakage out of the sump that had been directed to the sump by the leak-off 

collection system. Once the spent fuel pool leakage sump was identified as the source of the 

through-wall leakage, a tank was added to the sump, which collects any leak-off flow before it 

potentially contaminates the sump. The staff also noted that, in order to keep the leak-off 

system free-flowing, the applicant will hydro-laze the lines on a 4.5-year frequency and monitor 

the flow monthly for any indications of blockage. Finally, the staff noted that the applicant 

committed to take a core bore from the spent fuel pool sump in an area that was exposed to 

through-wall leakage (Commitment No. 67). The bore will be examined for concrete 

degradation and will expose the rebar to examine it for any signs of degradation. Based on its 

review, the staff finds the applicant’s response and approach acceptable for the following 

reasons:

• The applicant has plans in place to take a core bore from an area that was continuously 

wetted by borated water. This provides assurance that any degradation that may have 

occurred in the past will be identified and addressed prior to the period of extended 

operation.

• The applicant does not currently have any indications of leakage migrating through the 

concrete walls of the spent fuel pool (i.e., leakage not captured in the leak-off system). 

This provides assurance that any degradation that may have occurred in the past due to 

borated water will not continue during the period of extended operation.

• The applicant has plans in place to maintain the leak-off system clear of blockage, which 

provides assurance that any future leakage will be captured in the system and directed 

to the sump, as opposed to migrating through the spent fuel pool concrete walls.
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• The applicant will monitor the chemical properties of the leak-off collection on a quarterly 

basis. Any changes in the chemical makeup of the leak-off water could be a sign that 

the leakage is interacting with the concrete, which may indicate leakage outside of the 

collection system.

• The applicant will continue to attempt to locate the leakage source and stop it 

completely.

Based on the above, the staff’s concern discussed in RAI B.2.1.31-4, and the associated 

followup RAIs, is resolved.

Until Open Item OI 3.0.3.2.18-1 concerning the enhancement to the Structures Monitoring AMP 

to manage the effects of ASR is resolved, the staff cannot find that the operating experience 

related to the applicant's program demonstrates that it can adequately manage the detrimental 

effects of aging on SSCs within the scope of the program and that implementation of the 

program has resulted in the applicant taking appropriate corrective actions.

UFSAR Supplement

In LRA Section Appendix A, the applicant provided the UFSAR supplement for the Structures 

Monitoring Program. The staff reviewed this UFSAR supplement section and noted that it 

conforms to the recommended description for these types of programs, as described in SRP-LR 

Table 3.5-2. However, the supplement made no mention of ACI 349.3R, which is an important 

reference document for the applicant’s program. Several of the applicant’s program elements 

were found consistent with the GALL Report recommendations because they followed guidance 

from ACI 349.3R. This information was provided to the applicant during the consistency audit. 

To address the issue, by letter dated November 15, 2010, the applicant revised the supplement 

to include ACI 349.3R. The staff also noted that the applicant committed (Commitment Nos. 32 

and 33) to enhance the Structures Monitoring Program prior to entering the period of extended 

operation. Specifically, the applicant committed to do the following:

. LRA Sections A.2.1.31 provides the UFSAR supplement for the 

Structures Monitoring Program.

• enhance procedure to add the aging effects, additional locations, inspection frequency, 

and ultrasonic test requirements

• enhance the procedure to include inspection of opportunity when planning excavation 

work that would expose inaccessible concrete

In addition, the applicant committed (Commitment Nos. 67 and 68) to do the following:

• perform one shallow core bore in an area that was continuously wetted from borated 

water to be examined for concrete degradation and also exposed rebar to detect any 

degradation such as loss of material, no later than December 31, 2015.

• perform sampling at the leakoff collection points for chlorides, sulfates, pH, and iron 

once every three months, starting January 2014.

Additional enhancements to the structures monitoring aging management program are required 

to closeout Open Item OI 3.0.3.2.18-1 for the ASR issue. The staff finds that until Open Item 

OI 3.0.3.2.18-1 is resolved, the information in the UFSAR supplement, as required by 

10 CFR 54.21(d) is not adequate.
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Conclusion

3.0.3.2.19 Inaccessible Power Cables Not Subject To 10 CFR 50.49 Environmental 

Qualification Requirements Program

. The staff concludes that the applicant has not demonstrated that the effects of 

aging will be adequately managed so that the intended functions will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The 

applicant needs to resolve the Open Item OI 3.0.3.2.18-1, as discussed above. Once the Open 

Item OI 3.0.3.2.18-1, as discussed above is resolved, the applicant will need to make 

appropriate changes to the UFSAR supplement for this AMP to include a complete summary 

description of the program, as required by 10 CFR 54.21(d).

Summary of Technical Information in the Application. LRA Section B.2.1.34, as revised by LRA 

supplement letters dated October 29, 2010, and December 17, 2010, describes the new 

Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program as 

consistent, with an enhancement, with GALL Report AMP XI.E3, “Inaccessible Medium-Voltage 

Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements.” The 

applicant stated that the new program will manage the aging effects of localized damage and 

breakdown of insulation leading to electrical failure of inaccessible power cables (greater than or 

equal to 400 V) due to adverse localized environments caused by exposure to significant 

moisture regardless of frequency of energization. The applicant also stated that an adverse 

localized environment for inaccessible power cables is defined as periodic exposures to 

moisture that lasts more than a few days (e.g., cable in standing water). The applicant further 

stated that the applicant’s Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ 

Requirements Program includes periodic and event-driven inspection of manholes containing 

in-scope inaccessible power cables and draining water, as needed. The applicant stated that 

the maximum time between inspections will be no more than 1 year, but the frequency will be 

based on plant-specific operating experience with cable wetting or submergence, with the first 

inspections completed prior to the period of extended operation. In addition, the applicant 

stated that in-scope inaccessible power cables are tested to provide an indication of the 

condition of the conductor insulation with testing performed prior to the period of extended 

operation and at least every 6 years thereafter.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP XI.E3. As discussed in the audit report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL Report AMP XI.E3.

. 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 also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” and “detection of aging effects” program elements associated with the enhancement 

to determine 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. During the audit, the staff was concerned that the applicant’s AMP may not be 

consistent with GALL Report AMP XI.E3 or SRP-LR Section A.1.2.3.10 in that, as additional 

operating experience is obtained, lessons learned are evaluated and the program adjusted as 

required. Specifically, the application of GALL Report AMP XI.E3 to inaccessible medium 

voltage cable was based on operating experience available at the time Revision 1 of the GALL 

Report was developed. Recently identified industry operating experience indicates that the 
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presence of water or moisture can be a contributing factor in inaccessible power cable failures 

at lower service voltages (400 V to 2 kv). Further, industry operating experience, provided by 

NRC applicants in response to GL 2007-01, “Inaccessible or Underground Power Cable 

Failures that Disable Accident Mitigation Systems or Cause Plant Transients,” has shown that 

there is an increasing trend of cable failures with length in service beginning in the 6th through 

10th years of operation and that moisture intrusion is a predominant factor contributing to cable 

failure. Industry operating experience has also shown that some NRC applicants may 

experience events, such as flooding or heavy rain, that subjects cables within the scope of 

program for GALL Report AMP XI.E3 to significant moisture.

In response to the staff’s concern, the applicant stated during the audit that the Inaccessible 

Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program and associated 

UFSAR supplement would be revised to address the staff concerns regarding more recent 

industry operating experience.

The applicant revised LRA Section B.2.1.34 by letters dated October 29, 2010, and 

December 17, 2010, which provided an enhancement to “scope of program,” “parameters 

monitored or inspected,” and “detection of aging effects.” The enhancement expanded the 

Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program to include 

all inaccessible power cables (including de-energized cable) greater than or equal to 400 V 

within the scope of license renewal and subject to significant moisture. In addition, although not 

specifically identified as an enhancement or exception, the applicant also revised the cable 

manhole inspection frequency from a maximum time between inspections of no more than 

2 years to no more than 1 year. In addition to periodic inspections, the applicant also revised 

the LRA to include inspections for event-driven occurrences (e.g., rain or flood). The applicant 

also revised the cable testing frequency from at least every 10 years to at least every 6 years.

The staff finds that, with the enhancements and revised inspection and testing intervals 

specified in the LRA supplements dated October 29, 2010, and December 17, 2010, there is 

reasonable assurance that the applicant’s Inaccessible Power Cables Not Subject To 

10 CFR 50.49 EQ Requirements Program will adequately manage the aging effects of 

inaccessible power cables. The applicant’s program addresses industry operating experience 

consistent with current staff and SRP-LR Section A.1.2.3.10 guidance. The staff concerns 

identified in the audit report are resolved.

Based on its audit, and review of the applicant’s LRA including supplements dated 

October 29, 2010, and December 17, 2010, the staff finds that elements one through six of the 

applicant’s Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements 

Program, with acceptable enhancement, are consistent with the corresponding program 

elements of GALL Report AMP XI.E3 and industry operating experience. 

Operating Experience

The applicant stated that the GALL Report was considered as part of its operating experience 

review through the September 2005 issue date of GALL Report, Revision 1. In its response to 

GL 2007-01, the applicant concluded that no failures have occurred in power cables within the 

scope of the maintenance rule. The applicant also noted that, based on operating experience, it

has maintained an inspection of 10 percent of the safety-related manholes every 5 years since 

1994. The applicant also stated that a 2009 fleet procedure was issued that provided 

dewatering for electrical cables with the strategy that all cables important to generation and 

. LRA Section B.2.1.34 as revised by LRA supplement dated 

October 29, 2010, summarizes operating experience related to the Inaccessible Power Cables 

Not Subject To 10 CFR 50.49 EQ Requirements Program.
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nuclear safety are to be maintained in a dry (not submerged) condition. The applicant further 

stated that it is in the process of implementing this fleet procedure. The applicant stated that it 

performed inspections in late 2009 and early 2010 of all safety-related manholes and removed 

water from the manholes. The applicant further stated that the inspection frequency was 

increased to prevent submergence of safety-related cables and that it has performed tests on all 

safety-related, inaccessible, in-scope, greater than or equal to 400 V power cables and the 

nonsafety-related medium voltage cables with the test acceptance criteria met.

The staff reviewed the operating experience, in the application and during the audit, to 

determine if 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 including manhole inspection and cable 

test information to determine if the applicant adequately incorporated and evaluated operating 

experience related to this program. Further, the staff performed a search of regulatory 

operating experience for the past 10 years through April 2010. Databases were searched using 

various key word searches and then reviewed by technical auditor staff. The staff walked down 

selected in-scope manholes during the audit and noted limited water accumulation with no cable 

submergence noted.

During the audit, the staff identified industry operating experience, which could indicate that the 

applicant’s program may not be effective in adequately managing aging effects during the 

period of extended operation. The staff determined the need for additional clarification 

concerning more recent industry operating experience. To resolve the staff’s concerns, the 

applicant provided LRA supplements dated October 29, 2010, and December 17, 2010, which 

included an enhancement of the Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ 

Requirements Program. The enhancement increased the scope of the program to include 

in-scope inaccessible cable greater than or equal to 400 V (energized or deenergized) subject 

to significant moisture. Additional program revisions included increasing the manhole inspection 

frequency to a maximum time between inspections of 1 year and changing the cable testing 

frequency to at least once every 6 years. To account for event-driven occurrences such as 

heavy rain or flooding, the applicant also included event-driven inspections for cable manholes. 

With the included enhancement and additional changes to the applicant’s Inaccessible Power 

Cables Not Subject To 10 CFR 50.49 EQ Requirements Program, the applicant’s program is 

consistent with recent industry- and plant-specific operating experience and current staff 

guidance. The staff concerns identified during the audit are resolved.

Based on its audit, review of the application, and review of the applicant’s LRA supplements 

dated October 29, 2010, and December 17, 2010, the staff finds that operating experience 

related to the applicant’s program demonstrates that it can adequately manage the detrimental 

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. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement

The staff reviewed the UFSAR supplement description of the program, as revised by letters 

dated October 29, 2010, and December 17, 2010, and noted that it conforms to the 

recommended description for this type of program, as described in SRP-LR Table 3.6-2. As 

. LRA Section A.2.1.34 provides the UFSAR supplement for the 

Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program.
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part of the applicant’s LRA supplements, the applicant revised LRA Section A.2.1.34 to do the 

following:

• add in-scope low-voltage power cable (greater than or equal to 400 V)

• eliminate the criterion that exempts cables when not energized 25 percent of the time

• revise inspections and test frequencies

• include event-driven inspections due to event-driven occurrences such as heavy rain or 

flooding

The staff also noted that the applicant committed (Commitment No. 36) to implement the new 

Inaccessible Power Cables Not Subject To 10 CFR 50.49 EQ Requirements Program prior to 

entering the period of extended operation for managing aging of applicable components.

The staff determined that the information in the UFSAR supplement, as amended, is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.20 Protective Coating Monitoring and Maintenance Program

. On the basis of its audit and review of the applicant’s Inaccessible Power Cables 

Not Subject To 10 CFR 50.49 EQ Requirements Program, the staff finds that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent. 

Additionally, the staff finds the program’s enhancement to incorporate greater than or equal to 

400 V in-scope inaccessible power cable to be consistent with industry operating experience. 

The staff concludes that the applicant 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).

Summary of Technical Information in the Application

The applicant stated that, at the beginning of every refueling outage (RFO), the NextEra Energy 

coating supervisor and the design engineer inspect all areas and components from which 

peeling coatings have the potential of falling into the reactor cavity or emergency core cooling 

system (ECCS) recirculation sumps. It was indicated that after completion of all containment 

closeout work, the coating supervisor shall notify the design engineer and the nuclear coating 

specialist to perform the containment closeout inspection, and unqualified coatings found during 

this inspection shall be evaluated based on size, location, and coating type. The applicant 

further stated that, based on the results of this evaluation, the unqualified coating shall be 

removed as directed by the design engineer or documented on the containment coatings 

closeout inspection form and on an action request.

. By letter dated November 15, 2010, the 

applicant submitted an LRA supplement that included LRA Section B.2.1.38 which describes the 

existing Protective Coating Monitoring and Maintenance Program as consistent, with 

enhancements, with GALL Report AMP XI.S8, “Protective Coating Monitoring and Maintenance 

Program.” The applicant stated that the program manages cracking, blistering, flaking, peeling, 

and delamination of the Service Level 1 coatings, consistent with the guidelines of Regulatory 

Position C4 of the NRC RG 1.54, Revision 1, “Quality Assurance Requirements for Protective 

Coatings Applied to Water-Cooled Nuclear Power Plants,” as described in NUREG-1801, 

Revision 1.
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The applicant stated that the program requires that all accessible areas of containment receive 

a coatings inspection of all Service Level 1 coatings. It was reported that these inspections are 

performed during each RFO by qualified coatings inspectors. The applicant stated that the 

coatings inspectors are qualified per the requirements of ANSI N45.2.6, “Qualification of 

Inspection, Examination, and Testing Personnel.”

The applicant stated that the coatings used in Service Level 1 applications were qualified and 

applied in accordance with the requirements of the following documents: 

• NRC RG 1.54

• ANSI N101.4-1972, “Quality Assurance for Protective Coatings Applied to Nuclear 

Facilities” 

• ANSI N101.2-1972, “Protective Coatings (Paints) for Light Water Nuclear Containment 

Facilities”

• ANSI N512-1974, “Protective Coatings (Paints) for the Nuclear Industry”

The applicant indicated that the determination of acceptability of the coatings will be made by 

qualified inspection personnel. The applicant reported that the inspection personnel 

determination, as well as any deteriorated or unqualified coatings identified, will be documented 

in the as-left action request.

Staff Evaluation

The staff evaluated the information provided by the applicant and determined that the 

application of the Protective Coatings Monitoring and Maintenance Program is acceptable in 

managing coating degradation since the program is consistent with GALL Report Section XI.S8. 

The staff finds the frequency of coating inspections to be acceptable since inspecting every 

RFO would provide adequate assurance that there is proper maintenance of the protective 

coatings. The method of performing the coatings inspection is acceptable since the staff has 

found acceptable that visual inspections are performed and are able to detect for adverse 

coating conditions such as blistering, cracking, flaking, rusting, checking, insufficient adhesion, 

undercutting, peeling, and other signs of distress. The staff also found acceptable the manner 

in which the programs meet the requirements of ANSI N101.4-1972, N101.2-1972, N512-1974, 

since it is consistent with NRC RG 1.54. In addition, the qualification of personnel who perform 

the inspection is found to be acceptable since the staff has reviewed and confirmed that ANSI 

N45.2.6 is acceptable.

. During its audit, the staff reviewed the applicant’s Service Level 1 coatings 

qualification. 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 also reviewed the portions of the “detection of aging effects,” “monitoring and 

trending,” and “acceptance criteria” 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.2.1.38 states an enhancement to the “detection of aging 

effects” program element. The applicant stated that the program will be enhanced by 

designating and qualifying an inspection coordinator and an inspection results evaluator.
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On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.S8.

Enhancement 2

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations of GALL Report AMP XI.S8.

. LRA Section B.2.1.38 states an enhancement to the “detection of aging 

effects” program element. The applicant stated that the program will be enhanced to include 

instruments and equipment needed for inspection (i.e., flashlight, spotlights, marker pen, mirror, 

measuring tape, magnifier, binoculars, camera with or without wide angle lens, self sealing 

polyethylene sample bags).

Enhancement 3

The staff notes that the frequency of monitoring reports are completed during the coating 

inspections every RFO and would provide adequate assurance that the protective coatings are 

being trended for degradation. The method of performing the coatings inspection, as described 

above, is to do visual inspections which detect for adverse coating conditions such as blistering, 

cracking, flaking, rusting, checking, insufficient adhesion, undercutting, peeling, and other signs 

of distress.

. LRA Section B.2.1.38 states an enhancement to the “monitoring and 

trending,” program element. The applicant stated that the program will be enhanced to include 

a review of the previous two monitoring reports.

On the basis of its review, the staff finds this enhancement acceptable because it is consistent 

with ASTM D 5163 which specifies a review of the previous two monitoring reports (two 

previous RFOs) and when the enhancement is implemented, prior to the period of extended 

operation, it will make the program consistent with the recommendations in GALL Report 

AMP XI.S8.

Enhancement 4

On the basis of its review, the staff finds this enhancement acceptable because, when it is 

implemented, prior to the period of extended operation, it will make the program consistent with 

the recommendations in GALL Report AMP XI.S8.

. LRA Section B.2.1.38 states an enhancement to the “acceptance criteria” 

program element. The applicant stated that the program will be enhanced to include a 

requirement for the inspection report to be evaluated by responsible evaluation personnel who 

are to prepare a summary of findings and recommendations for future surveillance or repair.

Operating Experience

The applicant provided the following information regarding operating experience:

. LRA Section B.2.1.38 summarizes operating experience related to the 

Protective Coating Monitoring and Maintenance Program. The applicant states that the 

program is an existing program that is used to identify degraded or deteriorated Service Level 1 

coatings.

(1) In June 2010 an Action Request (AR) was issued to review NRC 

Information Notice IN 2010-12—Containment Liner Corrosion. The NRC 

issued this IN to inform addressees of recent issues involving corrosion of 

the steel reactor containment building liner. The AR response addressed 

all the concerns identified by the IN 2010-12. The AR concludes that: i) 
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Seabrook Station Containment structure is enclosed by a reinforced 

seismic category I concrete enclosure building which prevents exterior 

containment concrete from exposure to external atmosphere; ii) during 

construction at Seabrook Station there were three independent levels of 

Quality Control that provided assurance that adequate concrete 

placement techniques were implemented which eliminated the possibility 

of foreign material (organic compounds) being introduced during the 

concrete placement; and iii) the last IWE inspections of the containment 

liner performed at the Seabrook Station concluded that there were minor 

imperfections and discoloration in the coating film and isolated areas 

where the coating had been damaged, exposing the liner steel which 

contained only rust staining, or minor surface corrosion. In general, there 

was no measurable corrosion or any metal loss detected in the 

containment liner steel.

(2) In October 2010 an AR identified failure and degradation of Reactor 

Sump Liner Coating of the Unit 3 Reactor Sump Liner Plate at Turkey 

Point Nuclear Station. NextEra is in the process of evaluating this current 

AR for applicability at Seabrook.

(3) In December 1997, a Condition Report (CR) identified containment liner 

paint (approximately two square feet) scraped off at the scaffold storage 

area during the refueling outage OR05, due to poor material control 

practices for storing the scaffolding material. Paint in this area and other 

additional areas listed in the work order were repaired.

(4) In July 1998 Seabrook personnel performed a review of NRC Generic 

Letter GL 98-04, "Potential for Degradation of the Emergency Core 

Cooling System (ECCS) and the Containment Spray System (CSS) After 

a Loss-of-Coolant (LOCA) Accident Because of Construction and 

Protective Coating Deficiencies and Foreign Material in Containment." 

Seabrook Station responded to GL 98-04 via letter NYN-98125.

The staff reviewed the operating experience information in the application to determine if the 

applicable aging effects and industry- and plant-specific operating experience were reviewed by 

the applicant and are evaluated in the GALL Report. During its review, the staff found no 

operating experience to indicate that the applicant’s program would be ineffective in adequately 

managing aging effects during the period of extended operation.

Based on its review of the application, the staff finds that operating experience related to the 

applicant’s program demonstrates that it can adequately manage the detrimental effects of 

aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the application taking appropriate corrective actions. The staff confirmed that the 

“operating experience” program satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, 

the staff finds it acceptable.

UFSAR Supplement. LRA Section A.2.1.38 provides the UFSAR supplement for the Protective 

Coating Monitoring and Maintenance Program. The staff reviewed the 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 3.5-2.
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The staff also noted that the applicant committed (Commitment Nos. 46, 47, 48, and 49) to 

enhance the Protective Coating Monitoring and Maintenance Program prior to entering the 

period of extended operation. Specifically, the applicant committed to do the following:

(1) Enhance the program by designating and qualifying an inspection

coordinator and an inspection results evaluator.

(2) Enhance the program to include instruments and equipment needed for 

inspection (i.e., flashlight, spotlights, marker pen, mirror, measuring tape, 

magnifier, binoculars, camera with or without wide angle lens, self sealing 

polyethylene sample bags).

(3) Enhance the program to include a review of the previous two monitoring 

reports.

(4) Enhance the program to include a requirement that the inspection report 

be evaluated by the responsible evaluation personnel, who is to prepare a 

summary of findings and recommendations for future surveillance or 

repair.

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.2.21 Metal Fatigue of Reactor Coolant Pressure Boundary Program

. On the basis of its review of the applicant’s Protective Coating Monitoring and 

Maintenance Program, the staff determined that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation through Commitment Nos. 46, 47, 48,

and 49 prior to the period of extended operation would make the existing AMP consistent with 

the GALL Report AMP to which it was compared. The staff concludes that the applicant 

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)(2). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides and adequate summary description of the program, as required 

by 10 CFR 54.21(d).

Summary of Technical Information in the Application. LRA Section B.2.3.1 describes the 

existing Metal Fatigue of Reactor Coolant Pressure Boundary Program as consistent, with 

enhancements, with GALL Report AMP X.M1, “Fatigue Monitoring Program.” The applicant’s 

program is a preventive measure to mitigate fatigue cracking of RCPB components by 

monitoring and tracking critical thermal and pressure transients for selected RCS components. 

This ensures the number of design transient cycles is not exceeded during the operating life and 

the cumulative usage factor (CUF) for these components remains less than 1.0. The applicant 

stated that the fatigue-sensitive components include locations such as the reactor vessel shell 

and lower head; reactor vessel inlet and outlet nozzles; pressurizer surge line (hot leg and 

pressurizer nozzles); reactor coolant piping charging system nozzle; reactor coolant piping

safety injection nozzle; and RHR system Class 1 piping. The applicant also stated that the 

environmental effects for the fatigue-sensitive components specified in the NUREG/CR-6260, 

“Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant 

Components,” report for newer vintage Westinghouse plants have been addressed in LRA

Section 4.3. Four of these components will be monitored by the applicant’s program for fatigue 

usage, including environmental effects. These components are pressurizer surge line (hot leg 
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and pressurizer nozzles); reactor coolant piping charging system nozzle; reactor coolant piping 

safety injection nozzle; and RHR system Class 1 piping, analyzed in accordance with ASME 

Code Section III, Subsection NB-3200.

The applicant also stated that pre-established cycle limits would identify components 

approaching design limits. Corrective actions for components approaching design limits include 

reanalysis; inspection and flaw tolerance evaluation; and repair or replace, in accordance with 

applicable design codes. The applicant further stated that Seabrook will enhance the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program to include additional transients beyond 

those defined in the TS and the UFSAR and to use a software program to count transients to 

monitor cumulative usage on select components.

Staff Evaluation

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL Report AMP X.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 X.M1, with the exception of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements. For these 

elements, the staff determined the need for additional clarification, which resulted in the 

issuance of RAIs.

. 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.

In its review the staff noted that the scope of the applicant’s program includes nuclear steam 

supply system (NSSS), non-NSSS components, and transients in UFSAR Section 3.9.1.1 that 

require tracking. LRA Section 4.3 states that the metal fatigue time-limited aging analyses 

(TLAAs) that are evaluated in the LRA fall into the following categories: 

(a) Explicit fatigue analyses for NSSS pressure vessel and components that were prepared 

in accordance with ASME Code Section III, Class A or Class 1 rules, developed as part 

of the original design.

(b) Supplemental explicit fatigue analyses for piping and components that were prepared in 

accordance with ASME Code Section III rules to evaluate transients that were identified 

after the original design analyses were completed. Such analyses include consideration 

of pressurizer surge line thermal stratification and reactor vessel internal (RVI) 

component fatigue analyses.

(c) New fatigue analyses (also in accordance with ASME Code Section III, Class 1 rules) 

prepared for license renewal to evaluate the effects of the reactor water environment on 

the sample of high fatigue locations applicable to newer vintage Westinghouse Plants, 

as identified in Section 5.5 of NUREG/CR-6260, and using the methodology presented 

in LRA Section 4.3.4.

In addition, LRA Section 4.3.1 states that the most limiting number of transients used in these 

NSSS component analyses are shown in LRA Table 4.3.1-2, and are considered to be design 

limits. The staff confirmed that these transients are consistent with those listed in UFSAR

Table 3.9(N)-1.

The staff noted that LRA Table 4.3.1-2 lists more plant design transients than those identified in 

TS 5.7 and TS Table 5.7-1. For example, in the TS table, normal condition transients include 

only plant heatup and shutdown. Upset transients include only loss of load without turbine roll, 
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loss of all offsite power, partial loss of flow, and reactor trip from full power. Faulted transients 

include large steam line break, and test transients include primary and secondary side 

hydrostatic test and primary side leak test. It was not clear to the staff if the design CUF fatigue 

analyses for NSSS pressure vessels and components were based on the design transients 

listed in TS Table 5.7-1 or the non-TS transients that were included in LRA Table 4.3.1-2 and 

UFSAR Table 3.9(N)-1.

For those transients listed in LRA Table 4.3.1-2 but not in the TS, it was not clear to the staff 

how a transient will be accounted for, in accordance with the applicant’s program during the 

period of extended operation. The staff noted that the “parameters monitored/inspected” 

program element of GALL Report AMP X.M1 states that the program monitors all plant 

transients that cause cyclic strains, which are significant contributors to the fatigue usage factor. 

By letter dated December 14, 2010, the staff issued RAI B.2.3.1-1 requesting that the applicant 

clarify whether the “category (a)” fatigue analysis and the “category (b)” supplemental fatigue 

analysis were based on transients from TS Table 5.7-1 or LRA Table 4.3.1-2 and in UFSAR

Table 3.9(N)-1. The staff also asked the applicant to confirm that the plant-specific 

cycle-counting procedure ensures that those design transients listed in LRA Table 4.3.1-2 but 

not in TS 5.7 will be tracked and monitored (i.e., counted) in accordance with the Metal Fatigue 

of Reactor Coolant Pressure Boundary Program during the period of extended operation. In 

addition, the staff requested that, if these transients are not monitored during the period of 

extended operation, the applicant should justify with respect to the “parameters 

monitored/inspected” program element.

In its response dated January 13, 2011, the applicant stated that the “category (a)” fatigue 

analysis and the “category (b)” supplemental fatigue analysis were based on transients listed in 

LRA Table 4.3.1-2, and the cycle-counting procedure tracks and monitors design transients 

listed in this table and not those listed in TS 5.7. In response to RAI B.2.3.1-3, the applicant 

provided an enhanced LRA Table 4.3.1-2 detailing the current and future proposed monitoring 

of design transients. The additional design transients listed in the enhanced Table 4.3.1-2 are 

monitored by the Metal Fatigue and Reactor Coolant Pressure Boundary Program through the 

plant's engineering procedure for cycle-counting. The applicant further stated that the 

FatiguePro automated cycle-counting module will be used in companion to this procedure to 

count, categorize, and record the plant transients listed in the last column of enhanced LRA

Table 4.3.1-2. In addition, consistent with the applicant's Commitment No. 41, normal, upset, 

and test condition transients defined in the TS and UFSAR will be monitored during the period 

of extended operation. The “initial and random steady-state fluctuations and boron

concentration equalization” transients are not currently counted or proposed to be counted 

during the extended period because they are considered to be insignificant stress events, and 

their number of actual transients is not expected to approach the analyzed number of cycles. 

The staff finds this acceptable because the stress levels due to these transients would be below 

the endurance limit; therefore, it can be assumed that the number of allowed cycles is infinite. 

The applicant further added that emergency and faulted condition transients listed in 

LRA Table 4.3.1-2 are not required to be included in the fatigue evaluations and, therefore, are 

also not monitored by the Metal Fatigue and Reactor Coolant Pressure Boundary Program. The 

staff finds this acceptable. Since the faulted transients are not included in the fatigue 

calculations, they do not have an effect on the calculated fatigue usage and, therefore, do not 

require monitoring to ensure the design limit of 1.0 is not exceeded.

Based on its review, the staff finds the applicant’s response to RAI B.2.3.1-1 acceptable 

because the applicant clarified that the fatigue analyses were based on transients listed in 

LRA Table 4.3.1-2 and not in TS Table 5.7-1. The applicant also enhanced LRA Table 4.3.1-2 
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listing all the transients that are being monitored (or will be monitored) during the period of 

extended operation by the Metal Fatigue and Reactor Coolant Pressure Boundary Program. 

Furthermore, the applicant is monitoring all cyclic-strain causing transients that are significant 

contributors to the fatigue usage factor and have been included in the applicant’s fatigue 

analyses, consistent with the recommendations in the “parameters monitored/inspected”

program element of GALL Report AMP X.M1. The staff’s concern described in RAI B.2.3.1-1 is 

resolved.

In its review, the staff further noted that the scope of the applicant’s program includes both 

NSSS and non-NSSS components as well as transients in UFSAR Section 3.9.1.1 that are 

required to be tracked. The applicant stated that the most limiting numbers of transients used in 

these NSSS component analyses are shown in LRA Table 4.3.1-2 and are considered to be 

design limits. However, the staff noted that the transients are termed differently in the LRA,

UFSAR, and relevant documents that were reviewed during the staff’s audit. For example, 

upset condition transients such as “inadvertent startup of an inactive loop” or “inadvertent 

emergency core cooling system actuation” are referred to differently in these documents. The 

staff also noted during its audit that the applicant’s program basis document includes auxiliary 

transients such as “charging and letdown flow shutoff and return” or “letdown flow step decrease 

and return.” However, these transients are not included in the list of design transients provided 

in LRA Table 4.3.1-2.

By letter dated December 14, 2010, the staff issued RAI B.2.3.1-2 asking the applicant to do the 

following:

• justify the difference of designations for the transients between LRA Table 4.3.1-2 and 

the CUF analyses in the applicant’s program basis document

• clarify and justify how the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

and the associated onsite procedure will be capable of tracking transient occurrences to

ensure that the design limit of 1.0 is not exceeded and that any assumptions that are 

made in the fatigue CUF analyses remain valid, if the designations for the transients are 

not consistent between the LRA, the UFSAR, and other relevant documents

• clarify the significance of the auxiliary transients used in fatigue CUF analyses and 

explain how these transients are accounted for by the list of design transients provided 

in LRA Table 4.3.1-2

In its response dated January 13, 2011, the applicant acknowledged several wording 

differences between the transient designation listed in LRA Table 4.3.1-2 and those defined in 

the UFSAR Section 3.9(N).1.1 and program basis document. The applicant stated that the 

differences fall into the following categories:

• differences in the use of abbreviations and combining of symmetric transients such as 

unit loading and unloading of 5 percent of full power per minute

• addition of supplementary auxiliary transients necessary for the fatigue design basis for 

the chemical and volume control system (CVCS) components

• several fatigue-insignificant plant transients such as steady-state fluctuations and boron 

concentration equalization that are omitted from the fatigue monitoring basis document

The applicant further added that the first column of the enhanced LRA Table 4.3.1-2 lists all the 

transients that are included in the Fatigue Management Program and used in the fatigue 
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analyses of the Class 1 components. The Fatigue Management Program will ensure that all 

fatigue-analyzed components remain within their respective design fatigue analyses results (i.e., 

CUF less than 1.0) by ensuring that the counted plant transients remain within the number of 

occurrences of each plant transient listed in the second column of enhanced LRA Table 4.3.1-2. 

The applicant also clarified that the six auxiliary transients listed in the enhanced Table 4.3.1-2 

with footnote (6) are listed in the design specification for defining fatigue transients for CVCS 

components and are identified and counted in the FatiguePro software as part of the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program.

Based on its review, the staff finds the applicant’s response to RAI B.2.3.1-2 acceptable 

because the applicant did the following:

• clarified the differences in the designations of the transients

• described how the Metal Fatigue of Reactor Coolant Pressure Boundary Program and 

Fatigue Management Program track transient occurrences

• explained the significance of the auxiliary transients used in the fatigue analyses

In addition, the applicant’s program will ensure that all fatigue-analyzed components remain 

below the design limit of 1.0 by ensuring that the counted plant transients remain within the 

number of occurrences the component was analyzed for, consistent with the recommendations 

of GALL Report AMP X.M1. The staff’s concern described in RAI B.2.3.1-2 is resolved.

In its review, the staff noted that LRA Section B.2.3.1 states that the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program monitors and tracks the number of transient cycles to 

ensure that the CUF for selected RCS components remains less than 1.0 through the period of 

extended operation. The applicant also stated the program ensured the environmental effect on 

fatigue sensitive locations are addressed. Locations with CUF approaching the design limit are 

reanalyzed, inspected, repaired, or replaced, as necessary, in accordance with applicable 

design codes. LRA Section B.2.3.1 states that pre-established action limits will permit 

completion of corrective actions before the design basis number of events is exceeded and 

before the CUF, including environmental effects, exceeds the ASME Code limit of 1.0.

However, it was not clear to the staff if the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program will perform cycle-counting, cycle-based fatigue monitoring, or stress-based fatigue 

monitoring for RCPB components (including the environmentally-assisted fatigue (EAF)). 

Furthermore, the Metal Fatigue of Reactor Coolant Pressure Boundary Program does not 

provide details regarding the action limits that are set on design basis transient cycle-counting

activities or on CUF monitoring activities. It also did not provide the corrective actions that will 

be implemented if an action limit for cycle-counting or CUF monitoring is reached. By letter 

dated December 14, 2010, the staff issued RAI B.2.3.1-4 asking the applicant to define and 

justify the “action limit or limits” that will be used by the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program for the following:

• design basis CUF values for Class 1 components and any non-Class 1 components 

evaluated to Class 1 component CUF requirements

• environmentally-assisted CUF for the program’s NUREG/CR-6260 equivalent or 

bounding locations

• Class 1 components that are within the scope of the applicant’s high-energy line break 

(HELB) analyses for Class 1 components
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In its response dated January 13, 2011, the applicant stated that the action limit for components 

for which CUF values are evaluated against a design limit of CUF=1.0 is 80 percent of the 

design or analyzed number of occurrences for any plant transient included in the fatigue 

analysis of any of these fatigue-analyzed components with or without EAF analysis. For any 

plant transient included in the fatigue analysis of the EAF-analyzed HELB components, the 

action limit for components, for which CUF values are evaluated against a design limit of 

CUF=0.1, is 80 percent of the analyzed number of occurrences. The applicant added that when 

any one or more of these plant transients reach a value of 80 percent or more of the design 

number of occurrences, a re-evaluation of each of the components analyzed for the plant 

transient(s) that have achieved their 80 percent limit will be performed. Also, the re-evaluation 

may take advantage of use of 60-year projected cycles for other transients that are included in 

the fatigue analysis of each of the affected components.

Based on its review, the staff finds the applicant’s response to RAI B.2.3.1-4 acceptable 

because the action limits are set such that corrective actions can be taken prior to the 

cumulative fatigue usage of these components exceeding the design limit of 0.1 for HELB 

locations and 1.0 for all other locations, consistent with the recommendations of GALL Report 

AMP X.M1. The staff’s concern described in RAI B.2.3.1-4 is resolved.

The staff further noted that the “corrective actions” program element in GALL X.M1 states that 

acceptable corrective actions include repair of the component, replacement of the component, 

and a more rigorous analysis of the component to demonstrate that the design code limit will not 

be exceeded during the period of extended operation. However, LRA Section B.2.3.1 states 

that corrective actions may encompass one of several activities below:

• reanalyze affected component(s) for an increase in the number of a specific transient 

while accounting for other component-affecting plant transients that may be projected 

not to achieve their analyzed levels

• perform a fracture mechanics evaluation of a postulated flaw in affected plant 

components, which, when coupled with an Inservice Inspection Program, will serve to 

demonstrate flaw tolerant behavior

• repair the affected component

• replace the affected component

By letter dated December 14, 2010, the staff issued RAI B.2.3.1-5 requesting that the applicant 

justify for the corrective action, to perform a fracture mechanics evaluation, which is not 

consistent with the recommendations of the “corrective actions” program element of GALL 

Report AMP X.M1.

In its response dated January 13, 2011, the applicant stated that GALL Report AMP X.M1 does 

not specifically address the use of a fracture mechanics evaluation to reanalyze affected 

components. However, the ASME B&PV Code Section XI, Appendix L, provides guidance for 

methods for performing fatigue assessments to determine acceptability for continued service of 

RCS and pressure boundary components subjected to thermal and mechanical fatigue loads. 

The applicant further stated that the ASME Code specified two methods for performing fatigue 

assessments—a fatigue usage factor evaluation and a flaw tolerance evaluation (using fracture 

mechanics techniques). Furthermore, these two evaluation methods are the analytical options 

provided in LRA Section B.2.3.1. The applicant added that the use of the flaw tolerance 

evaluation method would require NRC approval of fatigue crack growth curves used in the 

analysis.
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Based on its review, the staff finds the applicant’s response to RAI B.2.3.1-5 acceptable 

because Appendix L of the ASME Code Section XI specifies that a fatigue usage factor 

evaluation and a flaw tolerance evaluation using fracture mechanics techniques can be used for 

performing fatigue assessments, and the applicant’s use of a flaw tolerance evaluation method 

would require NRC review and approval of the fatigue crack growth curves used in the analysis. 

The staff’s concern described in RAI B.2.3.1-5 is resolved.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “monitoring and trending,” and “acceptance criteria” 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

In its response dated January 13, 2011, the applicant included an enhanced LRA Table 4.3.1-2, 

which provides the additional design transients that will be monitored by the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program through its plant-specific procedure for 

documentation of design operating transients. The applicant added that the additional 

transients are postulated in the design basis calculations but have not been included in the 

TS 5.7 and UFSAR Section 3.9. Also, the additional transients have been included in the EAF

evaluations presented in LRA Section 4.3.4.

. LRA Section B.2.3.1 states an enhancement to the “parameters monitored or 

inspected” program element. The applicant stated that its program will be enhanced to include 

additional transients beyond those defined in the TS and the UFSAR. The staff reviewed this 

enhancement and noted that the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

does not identify these additional design transients that are monitored beyond those defined in 

the TS and the UFSAR. The staff also noted that the applicant’s program does not provide any 

description or the significance of these additional transients. The applicant’s program also does 

not identify the components that these additional transients affect, specifically those CUF TLAAs 

in LRA Section 4.3 that the applicant dispositioned under 10 CFR 54.21(c)(1)(iii). By letter 

dated December 14, 2010, the staff issued RAI B.2.3.1-3 requesting that the applicant to identify 

all additional design transients that are monitored by the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program, justify why these additional transients need to be monitored, and 

provide a discussion of the significance of these additional transients to the TLAAs identified in 

LRA Section 4.3. The staff also asked the applicant to clarify how these additional transients 

relate to TS 5.7 and the transients analyzed for in UFSAR Section 3.9. Additionally, the staff 

asked the applicant to clarify whether these transients were included in the new EAF analysis 

evaluations that were prepared for license renewal in LRA Section 4.3.4. If they were not

included, the applicant must justify why these transients are significant only for those analyses 

in the CLB and not significant for the analyses performed for the period of extended operation.

The applicant further stated that the LRA Section 4.3.1 has been revised to include the 

enhanced LRA Table 4.3.1-2 to identify transients that will be monitored by the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program. The applicant also stated that the FatiguePro 

automated cycle-counting module will be used as a companion to this procedure to count, 

categorize, and record the plant transients listed in the last column of the enhanced LRA

Table 4.3.1-2. The applicant stated that the additional design transients are selected to record a 

comprehensive set of plant transients for the purpose of assuring that plant operation remains 

within the fatigue design bases of the important plant components and to provide plant 

operational data, should it be necessary to reanalyze plant components in the future.
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The staff noted that the “parameters monitored/inspected” program element of GALL Report 

AMP X.M1 states that the program monitors all plant transients that cause cyclic strains, which 

are significant contributors to the fatigue usage factor.

Based on its review, the staff finds the applicant’s response to RAI B.2.3.1-3 acceptable 

because the applicant provided the enhanced LRA Table 4.3.1-2 clarifying all the transients that 

are being monitored or will be monitored during the extended period by the Metal Fatigue and 

Reactor Coolant pressure Boundary Program. Additionally, the applicant is monitoring those 

additional transients that are postulated in the design basis calculations, which contribute to 

fatigue usage, consistent with recommendations of the “parameters monitored/inspected” 

program element of GALL Report AMP X.M1. Also, the applicant clarified that EAF analysis, 

performed to address the effects of reactor water environment on component fatigue life,

consistent with the recommendations of GALL Report AMP X.M1, have included these 

additional transients. The staff’s concern described in RAI B.2.3.1-3 is resolved.

During its review of LRA Section 4.6.2, the staff noted that the personnel airlock and equipment 

hatch are designed to 120 heatup and cooldown cycles. The staff also noted that the applicant 

dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(i), that the analyses will remain 

valid for the period of extended operation. The applicant’s basis for this conclusion was 

provided in LRA Table 4.3.1-3, which shows that the 60-year projected number of heatups and 

cooldowns is 87 and 84, respectively. The applicant stated that the anticipated cycles for the 

personnel airlock and equipment hatch projected to occur during the period of extended 

operation is bounded by the original design of 120 heatup and cooldown cycles. The staff noted 

in LRA Table 4.3.1-2 the limiting design basis number of occurrences for plant heatups and 

cooldowns is 200 each. The staff further noted that the applicant’s Fatigue Monitoring Program 

tracks plant transients and triggers corrective actions or re-evaluation of fatigue analyses when 

and if the plant approaches the design basis limit of 200 heatup or cooldown cycles but the LRA 

does not explain if the program will trigger corrective actions if the plant approaches 120 cycles, 

which is the design limit for the personnel airlock and equipment hatch. 

In a conference call on November 22, 2011, the staff inquired how the applicant will track design 

limits related to plant startups and shutdowns as listed in LRA Section 4.6.2 related to the 

personnel airlock and equipment hatch . The staff noted that as previously noted in the 

applicant’s response to RAI B.2.3.1-3 and RAI B.2.3.1-4 (Reference 3) the design limit tracked 

by FatiguePro is 200 plant heatups and cooldowns with an 80 percent trigger level for further 

evaluation. The staff noted that this action limit would exceed the design limit of 120 heatup and 

cooldown cycles for the personnel airlock and equipment hatch as specified in LRA 

Section 4.6.2.

By letter dated December 15, 2011, the applicant stated that it has revised LRA Table 4.3.1-2 

previously submitted in response to RAI B.2.3.1-3 to include the specific plant startup and 

shutdown design limit of 120 cycles for the Personnel Airlock and Equipment Hatch. In addition, 

cycle counting for these specific components will initiate appropriate evaluations through the 

corrective action program if the 80 percent action limit is reached and that this limit will be used 

by the Metal Fatigue of Reactor Coolant Pressure Boundary Program for all limits tracked in 

FatiguePro. The applicant stated that this action limit will provide sufficient margin and time to 

allow for appropriate corrective actions as defined in the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program to be implemented prior to reaching the design limit. The staff 

reviewed the revised LRA Table 4.3.1-2 and confirmed that the applicant included a separate 

line item with a design limit of 120 cycles, which is specific only to the personnel airlock and 

equipment hatch analysis.
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The staff noted that the applicant confirmed that there were no additional non-conservative 

design limits utilized in TLAA other than the plant heatups and cooldowns used in the analysis 

for the personnel airlock and equipment hatch.

The staff finds the applicant’s supplement acceptable because (1) the applicant’s Metal Fatigue 

of Reactor Coolant Pressure Boundary Program ensures that the design cycles (120 plant 

heatups and cooldowns) that were used in the fatigue analysis for the personnel airlock and 

equipment hatch will not be exceeded during the period of extended operation; (2) the program 

ensures sufficient time for corrective actions to be taken (i.e., reanalysis of the component, 

repair or replacement of the component) with an 80 percent action limit on the design cycles; 

and (3) the applicant confirmed that there are no other analyses that contain more limiting 

number of cycles that need to be incorporated into the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program.

Based on its review, the staff finds Enhancement 1 acceptable because the applicant will 

monitor these additional transients from its design basis calculations, which are not included in 

TS 5.7 and UFSAR Section 3.9, consistent with the “parameters monitored/inspected” program 

element of GALL Report AMP X.M1.

Enhancement 2

The “detection of aging effects” program element of GALL Report AMP X.M1 states that the 

AMP provides periodic update of the fatigue usage calculations. LRA Section B.2.3.1 also 

states that “[t]he program includes generation of a periodic fatigue monitoring report, including a 

listing of transient events, cycle summary event details, cumulative usage factors, a detailed 

fatigue analysis report, and a cycle projection report.” However, the staff noted that the LRA 

does not provide the details regarding the software package that will be used. It is not clear to 

the staff if the “program” being referred to is the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program or the software program. It is also not clear to the staff if the software 

package will be used for cycle-counting only or if it will also be used for cycle-based or 

stress-based fatigue analysis and includes periodic CUF updates.

. LRA Section B.2.3.1 states an enhancement to the “scope of program,” 

“parameters monitored or inspected,” “monitoring and trending,” and “acceptance criteria” 

program elements. The applicant stated that its program will be enhanced to use a software 

program to count transients to monitor cumulative usage on selected components.

By letter dated December 14, 2010, the staff issued RAI B.2.3.1-6 requesting that the applicant 

do the following:

• clarify, in detail, how the selected software package will be capable of monitoring those 

transients that are significant to fatigue usage such that the design limit of 1.0 is not 

exceeded during the period of extended operation, consistent with the recommendations 

in GALL Report AMP X.M1

• clarify how the software package will perform periodic CUF updates, consistent with the 

recommendations of the “detection of aging effects” program element of GALL Report 

AMP X.M1

• clarify how the software package, referenced in LRA Section B.2.3.1 and Commitment 

No. 42, addresses and resolves the issue associated with NRC RIS 2008-30, “Fatigue 

Analysis of Nuclear Power Plant Components”
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In its response dated January 13, 2011, the applicant stated that the EPRI FatiguePro software 

is used to perform the following functions to accommodate fatigue monitoring of fatigue-critical 

components:

• The data acquisition system module collects plant instrument data for selected time 

periods.

• The automated cycle-counting module analyzes the collected plant instrument data and 

identifies, counts, categorizes, and records pre-defined plant transients with their 

pertinent engineering parameters.

• The cycle-based fatigue module calculated cumulative fatigue usage for selected plant 

components by applying counted plant transients to the component design stress report 

fatigue analysis.

The applicant also stated that the FatiguePro software would be used in conjunction with its 

plant-specific cycle-counting procedure to provide the technical basis and data for monitoring 

the number of occurrences and severity of the plant transients that define the fatigue design 

basis for fatigue-critical components. In addition, the data would be used to assure that the 

number and severity of the counted plant transients remain bounded by the component design 

analyses and, thereby, provide assurance that the design fatigue usage limit of 1.0 is 

maintained.

The applicant clarified that, as discussed above, the EPRI FatiguePro cycle-based fatigue 

program calculates cumulative fatigue usage for selected plant components by applying 

counted plant transients to the component design stress report fatigue analysis. The applicant 

added that the CUF computation is used as a secondary method for detecting aging effects due 

to fatigue; cycle-counting is the primary method for detecting aging effects.

The applicant also addressed the staff’s concern in NRC RIS 2008-30 regarding the use of 

simplifying assumptions when performing new ASME Code Section III NB-3200 fatigue 

analyses. The staff’s concern is that simplification of the six-stress tensor state to fewer stress 

components in the course of the fatigue analysis may lead to non-conservative fatigue usage 

results and should be benchmarked to six-stress tensor analyses whenever this simplification is 

used. The applicant clarified that the simplified method was used only in the stress-based 

fatigue module of the current FatiguePro software and, to resolve and address this issue, its 

Metal Fatigue of Reactor Coolant Pressure Boundary Program would not use the simplified 

FatiguePro stress-based fatigue module.

Based on its review, the staff finds the applicant’s response to RAI B.2.3.1-6 acceptable for the 

following reasons:

• The applicant counts, categorizes, and records the plant transients with FatiguePro in 

order to ensure that the design limit of 1.0 is not exceeded and the number and severity 

of the counted plant transients are bound by the component design analyses.

• The applicant’s Metal Fatigue of Reactor Coolant Pressure Boundary Program will 

periodically calculate fatigue CUF by applying counted plant transients to the component 

design stress report fatigue analysis, consistent with the “detection of aging effects” 

program element of GALL Report AMP X.M1.
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• The applicant confirmed that the simplified method used only in the FatiguePro 

stress-based module will not be used in its Metal Fatigue of Reactor Coolant Pressure 

Boundary Program.

The staff’s concern described in RAI B.2.3.1-6 is resolved.

The staff reviewed GALL Report AMP X.M1 and noted the following:

• The “scope of program” program element states that it includes preventive measures to 

mitigate fatigue cracking of metal components of the RCPB caused by anticipated cyclic 

strains in the material.

• The “parameters monitored/inspected” program element states the number of plant 

transients that cause significant fatigue usage for each critical RCPB component is to be 

monitored.

• The “monitoring and trending” program element states that the applicant will monitor a 

sample of high fatigue usage locations.

• The “acceptance criteria” program element states that it involves maintaining the fatigue 

usage below the design code limit.

Based on its review, the staff finds Enhancement 2 acceptable because the applicant’s 

program, when enhanced, include preventive measures to mitigate fatigue cracking by 

monitoring plant transients that cause significant fatigue usage on a sample set of high fatigue 

usage locations and maintain usage below the design limit of 1.0 by counting transients to 

monitor cumulative usage on selected components with a software package, consistent with the 

recommendations of GALL Report AMP X.M1.

Based on its audit, and review of the applicant’s responses to RAIs B.2.3.1-1 to B.2.3.1-6, the 

staff finds that elements one through six of the applicant’s Metal Fatigue of Reactor Coolant 

Pressure Boundary Program, with acceptable enhancements, are consistent with the 

corresponding program elements of GALL Report AMP X.M1 and, therefore, are acceptable.

Operating Experience. LRA Section B.2.3.1 summarizes operating experience related to the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant presented 

several examples that demonstrate that the applicant’s program can effectively manage the 

aging effects of fatigue damage by using industry information to identify fatigue sensitive 

locations and assure that the CUF meets the acceptance criterion of less than 1.0 during the 

period of extended operation. In 1989, the applicant responded to the NRC Bulletin 88-11, 

“Pressurizer Surge Line Thermal Stratification,” by reviewing the pressurizer surge line 

temperature and displacement data, collected during the first operating cycle, to analyze and 

demonstrate the acceptability of the fatigue CUF analysis for the surge line. Also, in 1988, the 

applicant evaluated the possibility and effects of fluid leakage in four piping sections in the high 

head safety injection lines and three piping sections in charging system lines that were 

un-isolable from the RCS and pressurized by the charging pumps. The applicant concluded 

that these piping sections were not subject to stresses due to thermal stratification or 

temperature oscillations resulting from the mechanism described in NRC Bulletin 88-08, 

“Thermal Stresses in Piping Connected to Reactor Coolant Systems.” In addition, in order to 

support the 60-year TLAAs associated with metal fatigue of the RCS pressure boundary, the 

applicant analyzed the projected CUF, incorporating environmental effects for seven locations 

specified in NUREG/CR-6260, and found that the CUFs for the surge line hot-leg nozzle and the 

charging nozzle will exceed 1.0 for 60 years of service. The staff noted that these analyses for 
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the surge line hot-leg nozzle and the charging nozzle are dispositioned in accordance with 

10 CFR 54.21(c)(1)(iii) and will be managed by the applicant’s Metal Fatigue of Reactor Coolant 

Pressure Boundary Program.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated 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 operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental 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. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the 

staff finds it acceptable.

UFSAR Supplement

• enhance the program to include additional transients beyond those defined in the TSs

and the UFSAR

. LRA Section A.2.3.1 provides the UFSAR supplement for the Metal 

Fatigue of Reactor Coolant Pressure Boundary 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 4.3-2. The staff also noted

that the applicant committed (Commitment Nos. 41 and 42) to enhance the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program prior to entering the period of extended operation. 

Specifically, the applicant committed to the following enhancements, respectively: 

• enhance the program to implement a software program to count transients to monitor 

cumulative usage on selected components

The staff determined 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 applicant’s Metal Fatigue of Reactor 

Coolant Pressure Boundary, the staff determined 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 through Commitment Nos. 41 and 42 

prior to the period of extended operation would make the existing AMP consistent with the GALL 

Report AMP to which it was compared. The staff concludes that the applicant 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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3.0.3.3 Aging Management Programs Not Consistent with or Not Addressed in the 

GALL Report 

In LRA Appendix B, the applicant identified the following AMPs as plant-specific:

• Buried Piping and Tanks Inspection Program

• 345 kV SF6 Program

• Boral Monitoring Program

• Nickel-Alloy Nozzles and Penetrations Program

• PWR Vessel Internals Program

For AMPs not consistent with or not addressed in the GALL Report, the staff performed a 

complete review to determine their adequacy to monitor or manage aging. The staff’s review of 

these plant-specific AMPs is documented in the following sections.

3.0.3.3.1 Buried Piping and Tanks Inspection Program

Summary of Technical Information in the Application. As a result of interactions during the AMP

audit conducted at the applicant’s site and the applicant’s review of recent significant industry 

operating experience, the applicant resubmitted LRA Section B.2.1.22, Buried Piping and Tanks 

Inspection Program, as a new plant-specific program by letter dated October 29, 2010. The 

applicant stated that the program will include preventive measures, including coating, cathodic 

protection, and backfill quality to mitigate corrosion and periodic inspections that manage the 

effects of aging. The applicant also stated that the program will include buried pipe, which is in 

direct contact with soil; underground pipe, which is located below grade within a vault that is 

exposed to air-indoor uncontrolled and where access is restricted; and inaccessible submerged 

pipe, which is located below grade within a vault that is in contact with raw water. There are no 

in-scope buried tanks.

Staff Evaluation. The staff reviewed program elements one through six of the applicant’s 

program against the acceptance criteria for the corresponding elements, as stated in SRP-LR

Section A.1.2.3. The staff’s review focused on how the applicant’s program will manage aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 

each of these elements follows.

Scope of the Program

The staff reviewed the applicant’s “scope of the program” program element against the criteria 

in SRP-LR Section A.1.2.3.1, which states that the program should include the specific 

structures and components for which the program manages aging.

. LRA Section B.2.1.22 states that the program will manage the aging 

effects for in-scope buried and underground piping constructed of any material, including 

metallic and polymeric materials. The applicant stated that the auxiliary boiler, auxiliary steam 

condensate, auxiliary steam heating, control building air handling, condensate, plant floor 

drains, diesel generator, instrument air, feedwater, fire protection and service water systems 

contain buried components. The applicant also stated that the auxiliary steam condensate and 

auxiliary steam heating systems include underground piping. The applicant further stated that 

the service water systems include inaccessible submerged pipe exposed to raw water.

The staff reviewed the applicant’s program basis documents and LRA Sections 2.3 and 3.0. 

The staff determined that the LRA provides a list of the specific aging effects to be managed as 

well as all component types and systems that are covered by this program. However, in its 
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LRA, Supplement 2, dated November 15, 2010, LRA Table 3.3.2-37 was revised to include 

copper alloy with greater than15 percent zinc valves and bolting exposed to raw water in the 

submerged underground vault for service water piping. The applicant stated that the 

components will be managed for aging by the Buried Piping and Tanks Inspection Program. 

The applicant did not revise LRA Section B.2.1.22 to reflect inclusion of this material nor provide 

inspection frequencies.

By letter dated March 7, 2011, the staff issued RAI B.2.1.22-5 requesting that the applicant 

provide justification to why the program did not include copper alloy greater than 15 percent zinc 

and did not provide the number of planned inspections of these components.

In its response dated April 5, 2011, the applicant revised LRA Section B.2.1.22 to include 

copper alloy greater than 15 percent zinc components within the scope of the program and 

stated that two inspections will be conducted in each 10-year period starting 10 years prior to 

the period of extended operation.

The staff finds the applicant’s response acceptable because the Buried Piping and Tanks 

Inspection Program scope includes all in-scope materials. Additionally, given that the copper 

alloy greater than 15 percent zinc components are drain valves and not a long run of pipe, two 

inspections in each 10-year period starting 10 years prior to the period of extended operation 

ensures that the applicant is conducting a sufficient number of inspections to establish a 

reasonable basis for the staff to conclude that the CLB function(s) of the buried in-scope 

components will be maintained throughout the period of extended operation. The staff’s 

concern described in RAI B.2.1.22-5 is resolved.

The staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.1; therefore, the staff finds it acceptable.

Preventive Actions

The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that the activities for prevention and mitigation 

programs should be described, and these actions should mitigate or prevent aging degradation.

. LRA Section B.2.1.22 states that preventive actions include coatings, 

cathodic protection, and quality of backfill. The applicant stated that coatings were installed to 

industry standards on buried steel and stainless steel piping and tested during installation for 

holidays, faults, and missing material. The applicant also stated that backfill was controlled by 

plant specifications and will be evaluated during all excavations along with any evidence of 

damage to pipe or coatings. The applicant further stated that the cathodic protection system 

protects the service water, diesel generator cooling water, and instrument air piping systems as 

well as portions of the fire protection and control building air handling system. The applicant 

stated that it tests the cathodic protection system every 6 months for pipe-to-soil potentials, in 

accordance with National Association of Corrosion Engineers (NACE) standards.

The staff noted that the coatings and backfill quality provisions will mitigate or prevent 

degradation because the coatings have been installed and tested by industry standards, the 

backfill was controlled by plant inspections, and both will be inspected during buried pipe 

excavations. The staff also noted that the auxiliary boiler, auxiliary steam condensate, auxiliary 

steam heating, condensate, feedwater, and plant floor drains, as well as portions of the control 

building air handling systems, are not provided with cathodic protection. In addition, the staff 

noted that the LRA does not state the availability of the cathodic protection system. By letter 

dated December 14, 2010, the staff issued RAI B.2.1.22-1 requesting that the applicant do the 

following:
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(a) state the availability of the cathodic protection system

(b) state the length of buried in-scope piping for systems or portions of systems not 

cathodically protected

(c) provide details on localized soil conditions and, if data does not exist, state what 

samples will be taken

(d) state the basis of the inspection population size and provide details on how plant-specific 

data of localized soil conditions will be used to optimize inspection locations

In its response dated January 13, 2011, the applicant stated the following:

(1) the third quarter 2010 cathodic protection availability was 98 percent and 

in the future, if availability drops below 90 percent or deviates from NACE 

criteria for greater than 90 days, those systems protected by that portion 

of the cathodic protection system will be considered as not having 

cathodic protection and will have an increased number of inspections,

(2) there is 970 feet of safety-related control building air handling, 152 feet of 

nonsafety-related condensate, 50 feet of nonsafety-related diesel 

generator, 147 feet of safety-related feedwater, and 250 feet of 

nonsafety-related plant floor drains buried in-scope piping without 

cathodic protection,

(3) localized soil condition data is not available; however, prior to buried pipe 

inspections, soil samples will be obtained in the area of planned direct 

inspections, consisting of soil resistivity, water samples, measurement of 

under-film liquid pH and [microbiologically-influenced corrosion] samples 

if applicable, and

(4) for buried in-scope steel piping systems without cathodic protection, the 

basis of the inspection size was multiplying the GALL Report AMP XI.M41 

recommended inspection quantities for steel systems with cathodic 

protection by four, and if coating damage attributable to backfill material 

was found, a multiple of eight was used.

The staff finds the applicant’s response to RAI B.2.1.22-1 items (a) and (b) acceptable. For 

item (a), consistent with the cathodic protection recommendations of GALL Report AMP XI.M41, 

the applicant will either ensure that the cathodic protection system is available greater than 

90 percent of the time and not unavailable for greater than 90 days or increase its inspections 

quantities to that for a steel system that has no cathodic protection. For item (b), the applicant 

provided the length of buried in-scope piping by system for the staff to inform its evaluation of 

the applicant’s program. The staff’s concern described in RAI B.2.1.22-1 is not resolved for 

item (c) because the staff does not have enough information to evaluate how the applicant will 

evaluate soil data to determine an increase in the number of required inspections. Additionally, 

it is not clear to the staff that soil samples will be obtained in the vicinity of each buried in-scope 

steel piping system (excluding fire protection) that is not provided with cathodic protection or

how often soil samples will be obtained during the period of extended operation. Additionally, 

the soil parameters do not appear to be sufficient to be able to determine soil corrosivity. For 

item (d), the staff’s concern is not resolved because the basis of the program for increased 

quantity of inspections does not consider soil corrosivity. By letter dated March 7, 2011, the 

staff issued followup RAI B.2.1.22-1 (followup) requesting that the applicant state the following:
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(a) what soil parameters will be used and how their aggregate impact will determine soil 

corrosivity

(b) whether localized soil conditions will be used to increase the number of inspection if the 

soil is corrosive

(c) if soil samples will be obtained in the local vicinity of all buried in-scope steel piping 

systems (excluding fire protection) that are not provided with cathodic protection

(d) how often soil sampling will be conducted during the period of extended operation or 

how it is known that localized soil conditions will not vary with time

In its response dated April 5, 2011, the applicant stated the following: 

(1) Soil sampling will include analyzing for soil resistivity, pH, redox potential, 

sulfides and moisture in the soil. The aggregate impact will be 

determined using EPRI Report 1021470, “Balance of Plant Corrosion—

the Buried Pipe Reference Guide,” Chapter 8, Soil Analysis, which 

endorses the [American Water Works Association] C105 soil corrosivity 

index. If the index is greater than 10, the soil is considered corrosive.

(2) The number of inspections of non-cathodically protected steel pipe not 

containing hazardous materials will be increased from four to six, and for 

steel piping containing hazardous materials from five percent to 

7.5 percent if the soil is determined to be corrosive. The staff noted that 

at the current time, the applicant does not have any non-cathodically 

protected in-scope buried steel pipe containing hazardous materials.

(3) Soil samples will be taken at a minimum of two locations in the vicinity of 

in-scope non-cathodically protected steel piping to obtain representative 

soil conditions for each system, excluding fire protection.

(4) Soil will be sampled prior to the period of extended operation to confirm 

that the soil conditions are not corrosive. If the initial survey shows the 

soil to be non-corrosive, additional soil samples will be taken every 

ten years thereafter during the period of extended operation to confirm 

the initial sample results.

The staff noted that the applicant revised LRA Section A.2.1.22, UFSAR supplement, to state 

that analysis for soil corrosivity is included in the program, and LRA Section B.2.1.22 to include 

the details as described in the April 5, 2011, response for items (a) through (d) above. The staff 

finds the applicant’s response acceptable for the following reasons:

• The soil sample parameters and integrated effects are consistent with the standard 

industry practice for determining soil corrosivity.

• The increase in the number of inspections, if the soil is determined to be corrosive, is 

consistent with the current staff position for a system without cathodic protection.

• The number of soil samples proposed by the applicant will ensure that a representative 

determination of soil corrosivity can be obtained.

• The applicant will continue to confirm a non-corrosive determination by additional soil 

samples in the period of extended operation.

The staff’s concern described in RAI B.2.1.22-1 and RAI B.2.1.22-1 (followup) are resolved.
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The staff confirmed that the “preventive actions” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.2; therefore, the staff finds it acceptable.

Parameters Monitored or Inspected

• hydrostatic testing of at least 25 percent of the piping under consideration on an interval 

not to exceed 5 years

. LRA Section B.2.1.22 states that steel and stainless steel 

piping will be inspected for degradation of coatings. When such damage is found, the piping 

material will be inspected visually to detect loss of material and by surface or volumetric 

examination to detect cracking due to SCC in stainless steel piping or loss of wall thickness in 

stainless steel and steel piping. The applicant stated that polymeric materials will be inspected 

by manual methods for changes in material properties and visual inspection for signs of 

cracking, blistering, or damage. The applicant also stated that pipe-to-soil and cathodic 

protection current will be monitored to determine the effectiveness of the cathodic protection 

system. The applicant further stated that the program provides alternative means to test the 

integrity of buried piping systems, including the following:

• internal inspection of at least 25 percent of the piping under consideration by a qualified 

method accepted by the staff that is capable of detecting both general and pitting 

corrosion at an interval not to exceed 5 years

• an annual NFPA flow test conducted on fire mains or monitoring of jockey pump 

operation for unexplained changes in pump activity at an interval not to exceed 1 month

• if unexplained changes occur, a flow test by the end of the next RFO

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3. The SRP-LR states that the parameters to be 

monitored or inspected should be identified and linked to the degradation of the particular 

structure and component intended function(s) and, for a Condition Monitoring Program, the 

parameter monitored or inspected should detect the presence and extent of aging effects.

The staff noted that the use of visual, surface, and volumetric inspection methods proposed by 

the applicant to detect loss of material and cracking where coating degradation has occurred is 

consistent with standard industrial practices and GALL Report AMP XI.M34, “Buried Piping and 

Tanks Inspection.” These methods have proven to be effective in detecting loss of material or 

coating degradation due to the aging effects covered in the applicant’s program. The staff also 

noted that manual inspection methods can detect changes in material properties for polymeric 

material. The staff further noted that, consistent with the inspection recommendations of GALL 

Report AMP XI.M41, the alternative means to test the integrity of the buried piping will be 

effective because they do one of the following:

• test the pressure-retaining capability of the piping system by an elevated pressure test 

which can detect current or near term leaks

• directly inspect for wall thickness degradation by volumetric means

• demonstrate that the fire protection system is capable of performing its CLB function to 

deliver flow

Therefore, the staff determined that the parameters to be inspected by the applicant are 

appropriate for the aging effects addressed.
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The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3; therefore, the staff finds it acceptable.

Detection of Aging Effects

The applicant stated that each inspection will examine a 10-ft segment of buried pipe. The 

number of inspections is based on the availability of cathodic protection, coating, and the 

adequacy of backfill materials. The number of inspections varies from one (where the cathodic 

protection system is installed and the backfill material is adequate) to eight (where there is no 

cathodic protection and the backfill material is inadequate). Additionally, the applicant has 

proposed to inspect 5 percent of the steel piping containing hazardous materials where the 

backfill is adequate and 10 percent where the backfill is not adequate and no cathodic 

protection is installed. As described above in the “preventive actions” program element, the 

number of inspections of non-cathodically protected steel pipe not containing hazardous 

materials will be increased from four to six and, for steel piping containing hazardous materials,

from 5 to 7.5 percent if the soil is determined to be corrosive. The staff noted that, at the current 

time, the applicant does not have any non-cathodically protected in-scope buried steel pipe 

containing hazardous materials.

. LRA Section B.2.1.22 states that the opportunistic or directed visual 

inspections as described in the “parameters monitored or inspected” program element will 

commence 10 years prior to entering the period of extended operation and be repeated in each 

10-year period of extended operation. The applicant stated that testing of the pipe-to-soil 

potentials and current for cathodic protection systems will be conducted annually. The applicant 

also stated that inspections will be performed in areas with the highest likelihood of corrosion 

problems. 

The staff summarized the quantity of in-scope existing buried piping inspections as shown in 

Table 3.0.3.3.1-1 Buried Piping Inspections, below:

Table 3.0.3.3.1-1 Buried Piping Inspections

System Code Class or 

Safety Related

Contains 

Hazardous 

Materials

Material Committed 

Inspections

Control Building 

Air Handling

Yes No Steel, with no 

cathodic protection

4/6/82

Fire Protection No No Steel, with no 

cathodic protection

4/6/82

Diesel Generator No No Steel, with no 

cathodic protection

4/6/82

Plant Floor 

Drains (not 

safety related)

No No Steel, with no 

cathodic protection

4/6/82

Condensate No No Steel, with no 

cathodic protection

4/6/82

Feedwater Yes No Steel, with no 

cathodic protection

4/6/82

Control Building 

Air Handling

Yes No Steel, with cathodic 

protection

1/NA/42

Instrument Air No No Steel, with cathodic 

protection

1/NA/42
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Fire Protection No No Steel, with cathodic 

protection

1/NA/42

Service Water Yes No Steel, with cathodic 

protection

1/NA/42

Condensate No No Stainless Steel 1

Diesel Generator 

– Cooling Water1 Yes Yes Stainless Steel 1

Fire Protection No No Fiberglass 1/NA/22

Notes:

1 Diesel generator cooling water piping contains glycol. 

2 The first number is the number of inspections if backfill is found to be acceptable. The second number is the number of 

inspections if the soil is determined to be corrosive. The third number is the number of inspections if backfill is not found to be 

acceptable.

The applicant stated that none of the underground piping systems contain hazardous materials, 

and two inspections of either the entire length of the piping or a minimum of 10 ft will be 

conducted. The applicant also stated that none of the inaccessible submerged piping systems 

contain hazardous materials, and two inspections of either the entire length of the piping or a 

minimum of 10 ft will be conducted. The applicant stated that the piping system is protected by 

a cathodic protection system and coatings are installed.

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that detection of aging effects should occur 

before there is a loss of the structure and component intended function(s). The criteria also 

states that parameters to be monitored or inspected should be appropriate to ensure that the 

structure and component intended function will be adequately maintained for license renewal 

under all CLB design conditions. The criteria further states that a program based solely on 

detecting structure and component failure should not be considered as an effective AMP for 

license renewal. The criteria states that this program element describes “when,” “where,” and 

“how” program data are collected (i.e., all aspects of activities to collect data as part of the 

program). The criteria continue by stating that the method or technique and frequency may be 

linked to plant-specific or industry-wide operating experience.

The staff confirmed that the use of the applicant’s methods is appropriate for detecting the aging 

effects covered in the program by comparing them to GALL Report AMP XI.M34, “Buried Piping 

and Tanks Inspection.” The staff also confirmed that the use of visual inspections provides 

sufficient detection methods to monitor degradation of coatings and corrosion effects prior to 

loss of the buried steel piping intended function or failure. Additionally, the program specifies 

the periodicity of the inspections and location of the inspections relative to material type and risk 

ranking, and it ensures that inspections will be performed by excavated direct inspection of the 

pipe or alternative acceptable methods as described in the “parameters monitored or inspected” 

program element.

As discussed in the staff evaluation of the “preventive actions” program element, the staff issued 

RAIs B.2.1.22-1 and B.2.1.22-1 (followup) requesting that the applicant state the basis of the 

inspection population size and provide details on plant-specific data of localized soil conditions 

that will be used to optimize inspection locations. As discussed in the staff’s evaluation of 

RAIs B.2.1.22-1 and B.2.1.22-1 (followup), above, the staff’s concern described in this RAI was 

resolved.
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In Footnote 4 of the Buried Piping Inspection Locations Table of LRA Section B.2.1.22, the 

applicant stated that if, during inspections of a particular material type, damage to coatings or 

base materials is determined to have been caused by backfill, the backfill will be considered to 

be “inadequate” for that material type only. The staff noted that the number of prescribed 

inspections increases if backfill is determined to be inadequate. In the “preventive action” 

program element, the applicant did not state that backfill requirements were dependent on the 

material type of the buried pipe. By letter dated December 14, 2010, the staff issued 

RAI B.2.1.22-2 requesting that the applicant justify why an inadequate backfill determination for 

a single material type inspection should not be applied to the other material types.

In its response dated January 13, 2011, the applicant revised Footnote 4 to state that if damage 

to coatings is determined to have been caused by backfill, the backfill will be considered 

inadequate for the purposes of the program. The staff finds the applicant’s response acceptable 

because the applicant will use backfill quality and coatings damage inspection results to inform 

the number of inspections across the entire program scope. The staff’s concern described in 

RAI B.2.1.22-2 is resolved.

The staff noted that there was insufficient information in LRA Section B.2.1.22 for the staff to 

evaluate the aging effects for the inaccessible steel service water submerged piping that is 

coated and provided with cathodic protection. By letter dated December 14, 2010, the staff 

issued RAI B.2.1.22-3 requesting that the applicant state how corrosion of the piping system will 

be detected that occurs either through permeability of the coating or coating holidays that 

remain undetected.

In its response dated January 13, 2011, the applicant stated that the original piping was coated 

with coal tar primer over which a hot, applied coal tar enamel with bonded asbestos felt or 

fibrous glass mat was installed. The piping was then covered with a final wrap of kraft 

paper/whitewash. The applicant also stated that holiday testing was conducted, and any faults 

were repaired. The applicant further stated that, subsequent to the original installation, pipe 

flanges were installed to allow for access to the interior piping. The applicant stated that the 

new piping was coated with a Keeler and Long 1000 Kolormastic coating system with a 

Tapecoat 20 primer and wrap.

The staff finds the applicant’s response acceptable for the original installation because, per the 

NACE Resource Center glossary, coal tar epoxy creates a very water resistant film, and holiday 

testing is an effective method to detect holidays to allow repair of localized coating defects. The 

staff did not have enough information to determine that the coatings used in the modification to 

add flanges to the system are sufficiently waterproof. By letter dated March 7, 2011, the staff 

issued RAI B.2.1.22-3 (followup) requesting that the applicant provide sufficient technical data 

for the staff to determine that the coating is waterproof.

In its response dated April 5, 2011, the applicant stated that the Tapecoat primer and wrap is a 

hot applied coal tar epoxy coating system that complies with American Water Works 

Association C203. The applicant also stated that the Keeler and Long 1000 Kolormastic coating 

system is epoxy based with a dry film thickness of 5–8 mils, and two coats were applied. The 

applicant further stated that given that technical data from the vendor demonstrating that the 

Keeler and Long 1000 Kolormastic coating system is acceptable for long-term immersion is not 

readily available, it will conduct two inspections every 10 years by an individual qualified to 

inspect coatings for those portions of the piping that was coated in this manner. The applicant 

stated that since installation in 1995, several inspections have been conducted, and there has 

been no documented degradation.
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The staff finds the applicant’s response acceptable because the Tapecoat 20 primer and wrap is 

coal tar epoxy based, inspections of 10–8 mills of the Keeler and Long 1000 Kolormastic coated 

components is thin enough that it would readily reveal underlying corrosion, and plant-specific 

operating experience to date has revealed no degradation of the coating. Also, even though

long-term immersion data is not readily available for the coating system, two inspections every 

ten years will provide adequate indication of loss of material due to corrosion. The staff’s 

concern described in RAI B.2.1.22-3 and RAI B.2.1.22-3 (followup) are resolved.

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.4; therefore, the staff finds it acceptable.

Monitoring and Trending

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities should 

be described, and they should provide predictability of the extent of degradation, and thus, 

effect timely corrective or mitigative actions. The criteria also states that this program element 

describes “how” the data collected are evaluated and may also include trending for a forward 

look, including an evaluation of the results against the acceptance criteria and a prediction

regarding the rate of degradation in order to confirm that timing of the next scheduled inspection 

will occur before a loss of intended function.

. LRA Section B.2.1.22 states the results of previous inspections will 

be evaluated (against minimum wall thickness requirements as described in the “acceptance 

criteria” program element) and used to assess the condition of external surfaces of other buried 

pipe to identify susceptible locations that warrant further inspection. The applicant also stated 

that pipe-to-soil potentials and currents will be monitored at least once a year and trended to 

identify changes in the effectiveness of the cathodic protection system. The applicant further 

stated that if the aging effects for the fire protection piping will be managed by monitoring for 

jockey pump performance, the data will be trended at least once a month.

The staff determined the applicant’s coverage of this program element to be adequate because 

the applicant’s program will include analysis of results against minimum wall thickness criteria 

that will be used to identify susceptible locations that warrant further inspection. The staff also 

determined that trending of cathodic protection performance meets industry standard for both 

parameters and the frequency, and trending of jockey pump performance on a monthly basis 

can be effective at detecting subtle day-to-day variance in performance.

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.5; therefore, the staff finds it acceptable.

Acceptance Criteria

• If metallic piping shows evidence of corrosion, the affected area will be evaluated 

against minimum wall thickness requirements.

. LRA Section B.2.1.22 states that, for coated piping, there should be no 

signs of coating damage and extent of coating damage will be evaluated by a qualified 

individual. The applicant stated the following:

• Cracking and blistering of polymeric piping will be evaluated under the Corrective Action 

Program.

• Cathodic protection pipe-to-soil potential and current will be evaluated against the 

criteria listed in NACE SP0169-2007.
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• Backfill will be evaluated against NACE SP0169-2007, ASTM D 448-08, and whether no 

damage has occurred to pipe coatings.

• Flow tests results for fire main testing will be evaluated against NFPA 25.

• Unexplained jockey pump activity is evaluated under the Corrective Action Program.

• Hydrostatic test results will meet the requirement of “without leakage” contained in 

49 CFR 195.302.

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states the acceptance criteria of the program and its basis 

should be described, including ensuring that the structure and component intended function(s) 

are maintained under all CLB design conditions during the period of extended operation. 

Acceptance criteria could be specific numerical values or could consist of a discussion of the 

process for calculating specific numerical values of conditional acceptance criteria to ensure 

that the structure and component intended function(s) will be maintained under all CLB design 

conditions. Information from available references may be cited. The criteria also states that 

acceptance criteria, which do permit degradation, are based on maintaining the intended 

function under all CLB design loads. The criteria further state that qualitative inspections should 

be performed to the same predetermined criteria as quantitative inspections by personnel in 

accordance with ASME Code and through approved site-specific programs.

The staff determined the applicant’s coverage of this program element to be adequate because 

the applicant’s program description includes details on the method to be followed in response to 

observed corrosion effects, and it relies on established design or performance-based 

acceptance criteria for the specific component and materials to be covered, which will be 

evaluated against industry standards when available. The staff also noted that qualified 

personnel are used to perform evaluations of coating conditions. Therefore, the staff 

determined that the acceptance criteria being used to evaluate aging effects are appropriate for 

the aging effects addressed.

The staff confirmed that the “acceptance criteria” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable.

Operating Experience

The staff reviewed this information against the acceptance criteria in SRP-LR

Section A.1.2.3.10, which states that the operating experience information provided should 

provide objective evidence that the effects of aging will be adequately managed so that the 

intended function(s) of the in-scope components and structures are maintained during the 

period of extended operation.

. LRA Section B.2.1.22 summarizes operating experience related to the 

Buried Piping and Tanks Inspection Program. The applicant stated that there are no 

plant-specific instances of failure of buried piping leading to loss of function of an in-scope 

component. The applicant also stated that it has conducted extensive visual inspections of the 

interior surfaces of buried service water piping and noted no staining of the cement liner; thus, it

expects that there has been no penetration of the pipe wall. The applicant further stated that an 

opportunistic inspection of steel fire protection piping showed no degradation of the coatings. 

The applicant cited two instances where wrappings or coatings were damaged including buried 

fuel supply piping that leaked as a result of damaged wrapping where further damage was 

subsequently discovered and the pipe was not returned to service and another opportunistic 

inspection of fire protection piping that revealed that the coating was worn but the piping was 

not exposed.
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The staff noted that the applicant did not state the extent of condition review that occurred as a 

result of a November 2000 buried fuel supply leak that was caused by damaged wrapping. 

Given that portions of the buried piping systems are not cathodically protected and, thus, the 

only barrier to corrosion of the piping system is its coating, the staff needs to understand the 

extent of condition of potential coating damage in other in-scope systems. The staff also noted 

that, due to the extent of piping degradation, the affected portion of the in-scope buried fuel 

supply piping was replaced with a temporary design. The staff further noted that the applicant 

did not commit to replace the temporary piping prior to the period of extended operation or 

provide details on how the aging effects of the replacement piping will be managed. By letter 

dated December 14, 2011, the staff issued RAI B.2.1.22-4 requesting that the applicant state 

what extent of condition review beyond the inspections of the fuel oil piping system was

conducted to determine the extent of coating damage in other in-scope buried piping systems. 

Additionally, given that the temporary piping would fulfill a license renewal function, the staff 

asked the applicant to describe how this piping will be age-managed during the period of 

extended operation.

In its response dated January 13, 2011, the applicant stated that the root cause evaluation did 

not result in the inspection of other buried piping as a result of this incident. The applicant also 

stated that the probable cause of the leak was damage to the coating, which occurred during 

construction. The applicant committed (Commitment No. 60) to replace the buried auxiliary 

boiler supply piping with a pipe-within-a-pipe design with leak detection capability prior to the 

period of extended operation.

The staff finds the applicant’s response acceptable because, even though the applicant did not 

pursue further inspections as part of the root cause analysis for the buried pipe leak, the 

applicant committed to conducting inspections every 10 years, starting 10 years prior to the 

period of extended operation through the period of extended operation. These inspections will 

result in a sufficient number of inspections to allow the staff to conclude that there is a 

reasonable basis that the in-scope buried piping will continue to meet its CLB function(s). In 

addition, the staff finds the applicant’s proposal to monitor the annular space in the 

pipe-within-a-pipe design acceptable because it is consistent with the inspection 

recommendations of GALL Report AMP XI.M41. The staff’s concern described in 

RAI B.2.1.22-4 is resolved.

Based on its review of the application, and review of the applicant’s response to RAI B.2.1.22-4, 

the staff finds that operating experience related to the applicant’s program demonstrates that it 

can adequately manage the detrimental effects of aging on SSCs within the scope of the 

program and that implementation of the program has resulted in the applicant taking appropriate 

corrective actions. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement

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 

Tables 3.3-2 and 3.4-2. The staff also noted that the applicant committed to do the following:

. LRA Section A.2.1.22 provides the UFSAR supplement for the Buried 

Piping and Tanks Inspection Program.

• implement the new Buried Piping and Tanks Inspection Program (Commitment No. 24)
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• replace the buried auxiliary boiler supply piping with a pipe-within-a-pipe design with leak 

detection capability prior to the period of extended operation for managing aging of 

applicable components (Commitment No. 60)

• conduct soil analyses prior to entering the period of extended operation and every 

10 years thereafter if the soil is determined to be non-corrosive (Commitment No. 64)

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.3.2 345 kV SF6 Bus Program

. On the basis of its technical review of the applicant’s Buried Piping and Tanks 

Inspection Program, the staff concludes that the applicant 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).

Summary of Technical Information in the Application

• loss of pressure boundary due to elastomer degradation

. LRA Section B.2.2.1 describes the new 

345 kV SF6 Bus Program as a plant-specific program. The applicant states that this program 

will manage the following aging effects on the 345 kV SF6 Bus: 

• loss of material due to pitting, crevice, and galvanic corrosion

• loss of function due to unacceptable air, moisture, or sulfur dioxide (SO2) levels

Sulfur hexafluoride (SF6) is an inert gas used to insulate the bus conductor. The program will 

inspect for corrosion on the exterior of the bus duct housing, test for leaks at elastomers, and 

periodically test SF6 gas samples to determine air, moisture, and SO2 levels. The presence of 

air or moisture may lead to the loss of intended function. SO2 levels are an indication of partial 

discharge internal to the bus ducts.

Staff Evaluation. The staff reviewed the program elements one through six of the applicant’s 

program against the acceptance criteria for the corresponding elements as stated in SRP-LP

Section A.1.2.2. The staff’s review focused on how the applicant’s program manages aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 

each of these elements follows.

Scope of the Program

The 345 kV SF6 Bus AMP in-scope bus segments are those bus segments included in the 

recovery path for an SBO event. Two possible recovery paths are identified as follows:

. LRA Section B.2.2.1 states the 345 kV SF6 Bus Program is credited for 

maintaining the pressure boundary formed by the exterior metal housing and elastomers. The 

program also monitors critical SF6 parameters such as air, moisture, and SO2 levels. The SF6

Bus Program will routinely monitor the integrity of the elastomers by performing leak tests.

• The first path includes the SF6 bus from 345 kV Power Circuit Breakers 11 and 163 to 

the generator step-up transformer and to the unit auxiliary transformers via the isolated 

phase bus.
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• The second path includes the SF6 bus from 345 kV Power Circuit Breakers 52 and 695 

to the reserve auxiliary transformers.

The staff reviewed the applicant’s “scope of program” program element against the criteria in 

SRP-LR Section A.1.2.3.1, which states that the scope of program should include the specific 

structures and components of which the program manages the aging.

The specific commodity groups for which the program manages aging effects are identified as 

the two paths above, which satisfies the criterion defined in SRP-LR Appendix A.1.2.3.1.

The staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.1; therefore, the staff finds it acceptable.

Preventive Actions

The “preventive actions” program element criterion in SRP-LR Section A.1.2.3.2 is that 

Condition Monitoring Programs do not rely on preventive actions; thus, preventive actions need 

not be provided. The staff determined that the preventive actions program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.2. The staff finds it acceptable because this is a 

Condition Monitoring Program, and there is no need for preventive actions. The staff finds this 

program element acceptable.

. LRA Section B.2.2.1 states that actions of the 345 kV SF6 Bus Program is 

to perform tests and inspections. The applicant stated that tests and inspections shall be 

performed prior to entering the period of extended of operation and at least once every 

6 months thereafter. No preventive actions are taken as part of this program to prevent or 

mitigate aging degradation.

The staff confirms that the “preventive actions” program element satisfies the criterion defined in 

SRP-LR Section A.1.2.3.2; therefore, the staff finds it acceptable.

Parameters Monitored or Inspected

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which states the parameters to be monitored or 

inspected should be identified and linked to the degradation of the particular structure and 

component intended function(s). Additionally, for a Condition Monitoring Program, the 

parameters monitored or inspected should detect the presence and extent of aging effects.

. LRA Section B.2.2.1 states that the 345 kV SF6 Bus 

Program performs tests and inspections to maintain the critical parameters of the SF6 bus 

system prior to entering the period of extended of operation and at least once every 6 months 

thereafter. Critical parameters of the SF6 bus system are mechanical integrity of the system to 

maintain a pressure boundary and maintenance of acceptable air, moisture, and SO2 levels. 

The applicant stated that the program includes pressure monitoring of the SF6 gas to insure that 

adequate insulating properties are maintained. The applicant also stated that the program 

performs periodic tests on samples of the SF6 gas to determine air, moisture, and SO2 levels as 

well as inspections for loss of materials on the exterior surfaces of the duct.

The parameters monitored or inspected will provide evidence of degradation of the insulating 

properties of the SF6 gas via sample testing. Also, the pressure monitoring of the SF6 gas and 

detection of loss of materials on the SF6 bus duct system will help to maintain its pressure 

boundary and ensure the component intended function during the period of extended operation.
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The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3 of the SRP-LR; therefore, the staff finds it 

acceptable.

Detection of Aging Effects

The applicant stated that the program maintains the pressure boundary by monitoring the 

pressure of SF6 gas and inspecting for leaks. The system SF6 bus will be inspected for leaks 

prior to entering the period of extended operation and at least once every 6 months thereafter.

. LRA Section B.2.2.1 states that the 345 kV SF6 Bus Program tests 

samples of the SF6 gas to determine if the insulating properties are adequate. These tests are 

focused on air, moisture, and SO2 levels. The SO2 measurements provide an indication of 

arcing internal to the bus. The gas is sampled, and its properties are tested prior to entering the 

period of extended operation and at least once every 6 months thereafter.

The applicant also stated that the program performs visual inspections on the exterior surfaces 

of the duct prior to entering the period of extended operation and at least once every 6 months 

thereafter.

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that the parameters to be monitored or 

inspected should be appropriate to ensure that the structures and components intended 

function(s) will be adequately maintained for license renewal under all CLB design conditions. 

This includes aspects such as method or technique (e.g., testing samples of SF6 gas, visual 

inspection for surface of duct), frequency, and timing of inspection to ensure timely detection of 

aging effects.

Testing samples of SF6 gas for insulating properties and visual inspection of the bus duct are an 

acceptable method to detect a degradation of SF6 bus systems. The staff also determined that 

periodic tests on samples and visual inspection every 6 months are adequate to detect the 

degradation of insulating properties.

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.4; therefore, the staff finds it acceptable.

Monitoring and Trending

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities should 

be described, and they should provide predictability of the extent of degradation and thus affect 

timely corrective or mitigative actions. This program element describes how the data collected 

are evaluated and may also include trending for a forward look.

. LRA Section B.2.2.1 states that the 345 kV SF6 Bus Program 

includes trending actions of the SF6 properties. The applicant stated that trending provides 

additional data, which can be analyzed to determine the rate of change in the measured 

parameters against the acceptance criteria. The applicant further stated that analysis of the 

collected data against the acceptance criteria and inspection may result in corrective actions.

The staff determined that once every 6 months testing and visual inspection for monitoring and 

trending and activities is acceptable since testing and inspection provide a prediction regarding 

the rate of degradation in order to confirm that timing of the next scheduled inspection and 

testing will occur before a loss of the structure and component intended function.
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The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in the SRP-LR Section A.1.2.3.5; therefore, the staff finds it acceptable.

Acceptance Criteria

The Seabrook program maintains the pressure boundary by inspecting for leaks 

and monitoring SF6 gas pressure. The minimum acceptable pressure value is 

sufficient to provide adequate insulation between the conductor and the exterior 

housing. The SO2 measurements of the SF6 gas provide an indication of partial 

discharge occurring internal to the bus. Any indication of the presence of SO2

will be evaluated by engineering staff. The evaluation will provide corrective 

action required.

. LRA Section B.2.2.1 states that the 345 kV SF6 Bus Program performs 

leak tests, tests the quality of SF6 gas, and inspects for loss of material. The applicant 

described the following criteria as acceptance criteria:

A dew point check is used to determine the moisture content of the SF6 gas. The 

maximum allowable dew point measurement is below the dew point value that 

would lead to break-down of the insulation.

Purity check is used to determine the air content of the SF6 gas. The maximum 

allowable air content is below the value that would lead to breakdown of the 

insulation.

Visual inspection on the exterior surfaces of the duct will detect the presence of 

pitting, crevice, and galvanic corrosion. Engineering evaluations will be 

performed if corrosion is found on the duct. The evaluation will determine the 

ability of the remaining wall thickness to maintain the required pressure 

boundary.

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states that the acceptance criteria of the program and their 

bases should be described. The acceptance criteria, against which the need for corrective 

actions will be evaluated, should ensure that the structure and component intended function(s) 

are maintained under all CLB design conditions during the period of extended operation.

The acceptance criteria for the tests and inspection provide assurance that the SF6 gas 

maintains its intended function as the bus insulation under CLB design conditions.

The staff determined that the “acceptance criteria” program element satisfies the criteria defined 

in SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable.

Operating Experience

The applicant stated that the program relied on a review of the Corrective Action Program 

database to provide the basis of this review. The applicant also stated that its review of the 

recent operating experience for the SF6 leak inspections at Seabrook increased the reliability of 

the SF6 switchyard. Also, in 2008, the applicant experienced an increase in the level of SO2 in a 

sample of the SF6 gas. An engineering evaluation attributed the increase to thermal cycling or 

partial discharge, which occurs with normal switch operation. The SF6 gas was filtered. This 

. LRA Section B.2.2.1 summarizes operating experiences related to the 

345 kV SF6 Bus Program. The applicant stated that Seabrook routinely performs monitoring 

and test activities for various parameters of the SF6 bus. The inspections and tests are 

performed as part of maintenance activities. Results that are not acceptable are documented in 

the Corrective Action Program.
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operating experience demonstrates the ability of Seabrook to routinely detect and analyze 

anomalies prior to loss of intended function. Plant-specific and industry operating experiences 

will be evaluated in the development and implementation of this program. As additional 

operating experience is obtained, the applicant will incorporate lessons learned into the 

program.

The staff reviewed this information against the acceptance criteria in SRP-LR

Section A.1.2.3.10, which states that operating experience with existing programs should be 

discussed. The operating experience 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.

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 operating experience related 

to the applicant’s program demonstrates that the program can adequately manage the 

detrimental effects of aging on SSCs within the scope of the program and implementation of the 

program has resulted in the applicant taking corrective actions. The staff confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; 

therefore, the staff finds it acceptable.

UFSAR Supplement

The staff also noted that the applicant committed (Commitment No. 40) to implement the 345 kV 

SF6 Bus Program prior to entering the period of extended operation for managing aging of 

applicable components.

. LRA Section A.2.2.1 provides the UFSAR supplement for the 345 kV SF6

Bus Program. The staff reviewed the UFSAR supplement description of the program and noted

that it conforms to the recommendation for this type of program, as described in SRP-LR

Section 3.6.3.4 and Table 3.6-2. 

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion

3.0.3.3.3 Boral Monitoring Program

. On the basis of its technical review of the applicant’s 345 kV SF6 Bus Program, the 

staff concludes that the applicant 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).

Summary of Technical Information in the Application. LRA Section B.2.2.2 describes the 

existing Boral Monitoring Program as plant-specific. The applicant stated that the program 

manages the aging effects of reduction of neutron absorbing capacity due to Boral degradation. 

It also manages changes in the dimensions and loss of material due to general corrosion of 

Boral neutron absorbing material in the spent fuel pool racks by relying on representative 

coupon samples mounted in a coupon “train” located in the spent fuel pool to monitor 

performance of the absorber material without disrupting the integrity of the storage system. The 
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applicant further stated that the program assures the Boral neutron absorbers in the spent fuel 

racks maintain the validity of the criticality analysis in support of the rack design.

Staff Evaluation. The staff reviewed program elements one through six of the applicant’s 

program against the acceptance criteria for the corresponding elements as stated in SRP-LR

Section A.1.2.3. The staff’s review focused on how the applicant’s program manages aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 

each of these elements follows.

Scope of the Program

The staff reviewed the applicant’s “scope of program” program element against the criteria in 

SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the 

specific structures and components of which the program manages the aging, and it finds that 

the applicant adequately described the structures and components to be managed.

. LRA Section B.2.2.2 states that the applicant’s spent fuel pool is divided 

into two regions. The applicant further stated that region one has six racks with Boral as the 

neutron absorber that allow space for 576 fuel assemblies. The applicant further stated that 

region two contains Boraflex as the neutron absorber and is not credited in the criticality 

analysis; therefore, region two is not within the scope of license renewal. The applicant also 

stated that the scope of the program is the management of the reduction of neutron-absorbing 

capacity of the Boral sheets in region one. The applicant stated that this is accomplished by 

monitoring neutron-absorbing capacity, inspecting for changes in dimensions and inspecting for 

loss of material due to general corrosion caused by the effects of the spent fuel pool 

environment on representative Boral coupons.

The staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.1; therefore, the staff finds it acceptable.

Preventive Actions

The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that for Condition or Performance Monitoring Programs, 

they do not rely on preventive actions; thus, this information need not be provided.

. LRA Section B.2.2.2 states that the applicant’s Boral Monitoring Program is 

a Condition Monitoring and Inspection Program; therefore, there are no preventive actions 

required.

The staff confirmed that the “preventive actions” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.2; therefore, the staff finds it acceptable.

Parameters Monitored or Inspected. LRA Section B.2.2.2 states that the applicant uses 

standard Boral coupons of the same design as, and traceable to, the specific Boral heat lot 

material used in the fabrication of the spent fuel racks. The applicant stated that the standard 

coupons are placed in the spent fuel pool for monitoring of the aging effects and control 

coupons were supplied, in addition to standard coupons, to benchmark coupon initial conditions, 

to monitor possible pool conditions, and to demonstrate comparisons between different 

examination techniques and service contractors. The applicant further stated that the program 

monitors changes in the physical properties of the Boral coupons such as blistering, pitting, 

cracks, corrosion and spalling, loss of material, and other damage or condition. The applicant 

also stated that the physical dimensional requirements of the coupons are also monitored, and 

two or more Boral coupons are selected each RFO for examination by an outside contractor 

where neutron attenuation, neutron radiography examination, and other nondestructive 

examinations are performed.
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The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which states that the parameters to be 

monitored or inspected should be identified and linked to the degradation of the particular 

structure and component intended function(s). The SRP-LR also states that, for a Performance 

Monitoring Program, a link should be established between the degradation of the particular 

structure or component intended function(s) and the parameter(s) being monitored.

After reviewing the “parameters monitored or inspected” program element, the staff determined 

that the applicant adequately addressed the criterion defined in SRP-LR Section A.1.2.3.3. 

Inspection of the Boral coupons, which are indicative of the Boral in the spent fuel pool, is an 

acceptable means to monitor for the aging effects of loss of material and reduction of neutron 

absorber capacity. Furthermore, monitoring the physical condition of the neutron-absorbing 

material, such as geometric changes in the material (formation of blisters, pits and bulges), and 

decreased boron areal density makes this element of the program consistent with 

LR-ISG-2009-01, “Aging Management of Spent Fuel Pool Neutron-Absorbing Materials other 

than Boraflex.”

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3; therefore, the staff finds it acceptable.

Detection of Aging Effects

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that detection of aging effects should occur 

before there is loss of the structure and component intended function(s). The parameters to be 

monitored or inspected should be appropriate to ensure that the structure and component 

intended function(s) will be adequately maintained for license renewal under all CLB design 

conditions. This includes aspects such as method or technique (e.g., visual, volumetric, surface 

inspection), frequency, sample size, data collection, and timing of new and one-time inspections 

to ensure timely detection of aging effects. Additionally the program should provide information 

that links the parameters to be monitored or inspected to the aging effects being managed.

. LRA Section B.2.2.2 states the Boral Monitoring Program monitors 

coupon samples located in the spent fuel pool to determine the condition of the neutron 

absorber material without disrupting the integrity of the spent fuel storage system. The 

applicant stated that the program measures certain physical and chemical properties of these 

sample coupons each RFO. The applicant further stated that the program maintains the coupon 

train within the spent fuel pool positioned such that the coupons experience the same conditions 

as the Boral panels built into the actual fuel racks. The applicant further stated that the coupons 

are mounted in stainless steel jackets and stainless steel coupon train mimicking the 

construction of the fuel racks designed to recreate the spent fuel pool environment for known 

effects and potential effects that may be unknown at this time

After reviewing the “detection of aging effects” program element, the staff determined that the 

applicant adequately addressed the criterion defined in SRP-LR Section A.1.2.3.4 because the 

Boral Monitoring Program is set up to facilitate early detection of aging effects in the Boral 

sheets in the spent fuel pool via detection of aging effects in the Boral coupons. The Boral 

Monitoring Program tests selected coupons every RFO, exposes the coupons to a similar 

environment to that of the actual Boral in the spent fuel pool, and maximizes the amount of 

exposure the coupon trains receive while in the spent fuel pool.

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.4; therefore, the staff finds it acceptable.
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Monitoring and Trending

The staff reviewed the applicant’s “monitoring and trending program” program element against 

the criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities 

should be described, and they should provide predictability of the extent of degradation and thus 

effect timely corrective or mitigative actions. Plant-specific or industry-wide operating 

experience or both may be considered in evaluating the appropriateness of the technique and 

frequency.

. LRA Section B.2.2.2 states that the neutron attenuation tests are 

trended to ensure that degradation does not challenge the assumptions within the spent fuel 

pool criticality analysis of record. The applicant stated that observable loss in neutron 

attenuation ability, if any, is projected to determine when neutron attenuation may fall below 

acceptance criteria. Additionally, the applicant stated that, along with size and weight 

measurements to determine the extent of shrinkage or loss of material, blister shape and size 

are recorded and trended to determine whether new blisters are forming, the rate of growth of 

existing blisters, and the rate of increase in blister thickness.

After reviewing the “monitoring and trending” program element, the staff determined that the 

applicant adequately addressed the criterion defined in SRP-LR Section A.1.2.3.5 because the 

applicant’s Boral Monitoring Program includes trending of the degradation of the boral coupons 

as well as the physical characteristics of the coupons, which is congruent with the 

recommendations, as described in SRP-LR Section A.1.2.3.5.

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.5; therefore, the staff finds it acceptable.

Acceptance Criteria

The applicant stated that failure to meet acceptance criteria is addressed by the following 

engineering evaluation:

. LRA Section B.2.2.2 states that the purpose of the applicant’s Boral 

Monitoring Program is to ensure that degradation does not challenge the design bases and 

assumptions within the spent fuel pool criticality analysis of record. The applicant further stated 

that the design of the region one spent fuel racks containing Boral as a neutron absorbing 

material assures a Keff less than 0.95 (5 percent subcriticality margin). The applicant stated that 

the acceptance criteria for the following properties are applied to each exposed standard Boral 

coupon inspected.

a. Voided Blister Displacement—the total blister void volume for all blisters 

present on both sides of a coupon will be less than a 45 mil uniform void 

over the area of the coupon. The rate of change in blister displacement 

provides indication of availability of sufficient margin to avoid exceeding 

the 45 mil uniform void prior to the next Boral coupon examination.

b. Boron Carbide Loss—B10 areal density measured by thermal neutron 

attenuation will be greater than 0.02 gm/cm2 [grams per square 

centimeter] as specified within the criticality analysis and material 

specification. The rate of change in boron carbide loss provides 

indication of availability of sufficient margin to maintain the 0.02 gm/cm2

B10 areal density beyond the next Boral coupon examination.

c. Boron Carbide Redistribution—Boron carbide distribution will be uniform 

as observed by thermal neutron radiography. Thinned or depleted areas 

will satisfy the criterion for boron carbide loss discussed above.
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The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states that the acceptance criteria of the program and its basis 

should be described. The acceptance criteria, against which the need for corrective actions will 

be evaluated, should ensure that the structure and component intended function(s) are 

maintained under all CLB design conditions during the period of extended operation. The 

program should include a methodology for analyzing the results against applicable acceptance 

criteria.

After reviewing the “acceptance criteria” program element, the staff determined that the 

applicant adequately addressed the criterion defined in SRP-LR Section A.1.2.3.6 because the 

acceptance criterion listed in the applicant’s Boral Monitoring Program are congruent with the 

recommendations of SRP-LR A.1.2.3.6. These acceptance criterion will ensure that the 

structure and component intended function(s) are maintained under all CLB design conditions 

during the period of extended operation.

The staff confirmed that the “acceptance criteria” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable.

Operating Experience

The applicant stated that the operating experience included the following:

. LRA Section B.2.2.2 summarizes operating experience related to the 

Boral Monitoring Program. The applicant stated that the Boral Monitoring Program is an 

existing AMP proposed for the period of extended operation.

(1) During planned work involving an inspection of the Spent Fuel Pool Boral 

coupon tree in 2003, an unexpected blistering of the Boral material was 

identified when one of the Boral coupons was examined.

a. The condition report evaluation concluded that the effect on the 

current Spent Fuel Pool criticality analysis was insignificant and 

the current blistered condition was acceptable as is. The 

evaluation stated that the degree of Boral blistering was expected 

to increase with repeated exposure to gamma energies present 

during offload; as such, a Boral monitoring program was 

established to evaluate future changes in the Boral material. 

Since the Boral monitoring program would not gather any 

additional data on the blistering events until after the next core 

offload, a water reduction in the flux trap equal to 90 mils was 

analyzed and applied to the revised criticality analyses to formally 

accommodate any increased blistering at offload.

b. The revised type determination curves are conservative to the 

existing curves at all points, and were implemented prior to core 

offload. The type determination curves with the 90 mil allowance 

were included to accommodate any future blistering. This 

allowance is used as an acceptance criterion for the Boral 

monitoring program. Other acceptance criteria will include the 

Boron10 areal density.

(2) As of January 2003, a Boral Monitoring Program had not yet been 

formally established following implementation of the engineering change 

to incorporate Boral instead of Boraflex in the second set of fuel racks. 

Although no commitment had been made to implement such a program, 
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Seabrook Station opted to establish a Boral coupon monitoring program 

as a good practice.

(3) During the Cycle 10 monitoring program (Spring of 2005), aluminum 

cladding oxidation and spalling was observed on Boral coupons. Photos 

of these coupons taken in the previous monitoring cycle were reviewed 

and showed oxidation but no evidence of spalling. The progression and 

effect of this oxidation and spalling was evaluated and predicted to 

remain within the program acceptance criteria through the next coupon 

examination in Cycle 11, when the material would be re-evaluated.

The Boral oxidation and spalling condition was described and 

posted with [Institute of Nuclear Plant Operation] INPO as 

operating experience on August 26, 2005.

The Cycle 11 examinations (Fall of 2006) indicated continued 

aluminum cladding oxidation on most coupons. The potential 

degradation of neutron absorbing capacity due to continued, and 

eventually through-wall, oxidation and spalling was evaluated by 

observing previously dissected blisters on special coupon A131. 

Blisters on this coupon had been intentionally dissected to 

investigate the effect on the Boral should a blistered area break 

through. By dissecting the blisters, the cermet [ceramic-metallic] 

compound was now exposed directly to the Spent Fuel Pool 

water. The altered coupon A131 with dissected blisters had been 

exposed to the Spent Fuel Pool conditions for approximately 

3 years, and was then indicating measurable change in B10 areal 

density in the bare cermet.

The results of the Cycle 11 examinations indicated continued 

aluminum cladding oxidation. The Boral coupons did, however, 

remain well within the areal density specification. The change in 

B10 areal density was just above the lower limit of detection by 

visual examination. The corrosion process appeared to be 

proceeding very slowly.

The potential for measurable B10 loss in the unaltered coupons 

was reasonably expected within the next few cycles. Therefore 

long term B10 areal density monitoring, via neutron attenuation, 

was also implemented to ensure conformance to Boral 

specifications.

The staff reviewed this information against the acceptance criteria in SRP-LR

Section A.1.2.3.10, which states that the operating experience of AMPs, 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.
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The staff reviewed neutron radiography examination data as well as the applicant’s technique 

for determining areal density of the Boral coupons. This technique involves performing visual 

examinations of the radiographical images of coupons. During its review, the staff identified 

operating experience, which could indicate that the applicant’s program may not be effective in 

adequately managing aging effects during the period of extended operation. The staff 

determined the need for additional clarification, which resulted in the issuance of an RAI.

In LRA Section B.2.2.2 the applicant stated that Boral coupons are selected each RFO for 

examination by an outside contractor. By letter dated December 14, 2010, the staff issued 

RAI B.2.2.2-1 requesting additional information on how the coupons were handled by the 

applicant and the contractor to ensure the condition of the coupons were representative of the 

coupons upon exiting the pool and not due to the handling and transportation of the coupons to 

the testing facility.

In its response dated January 13, 2011, the applicant provided excerpts from both the 

contractor procedure and its own program documents detailing the controls put in place to 

ensure consistent and effective handling and testing of the Boral coupons. The applicant further 

provided details on the different tests done on the coupons once they arrive at the contractor 

facility. Based on its review, the staff finds the applicant’s response to RAI B.2.2.2 acceptable 

because the applicant demonstrated the appropriate level of care to ensure that the coupons 

analyzed are the most representative of the Boral in the spent fuel pool.

Based on its review of the application, and review of the applicant’s responses to RAI B.2.2.2, 

the staff finds that operating experience related to the applicant’s program demonstrates that it 

can adequately manage the detrimental effects of aging on SSCs within the scope of the 

program and that implementation of the program has resulted in the applicant taking appropriate 

corrective actions. The staff confirmed that the “operating experience” program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it acceptable.

UFSAR Supplement

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

. LRA Section A.2.2.2 provides the UFSAR supplement for the Boral 

Monitoring 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 LR-ISG-2009-01.

Conclusion

3.0.3.3.4 Nickel-Alloy Nozzles and Penetrations Program

. On the basis of its technical review of the applicant’s Boral Monitoring Program, 

the staff concludes that the applicant 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).

Summary of Technical Information in the Application. LRA Section B.2.2.3 describes the 

existing Nickel-Alloy Nozzles and Penetrations Program as plant-specific. The applicant stated 

that the Nickel-Alloy Nozzles and Penetrations Program manages the aging effect of cracking 

due to PWSCC of nickel-based alloy pressure boundary and structural components exposed to 

reactor coolant.
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Staff Evaluation

GALL Report Table 3.1-1, IDs 31 and 34,and their subordinate items, are unique in the GALL 

Report in that they do not recommend that aging be managed through the use of an AMP 

contained in the GALL Report. Rather, they recommend specific aging management activities. 

For nickel-alloy materials addressed by these AMR items, the recommended aging 

management activities consist of the following:

. The staff reviewed program elements one through six and ten of the 

applicant’s program against the acceptance criteria for the corresponding elements, as stated in 

SRP-LR Section A.1.2.3. The staff’s review focused on how the applicant’s program manages 

aging effects through the effective incorporation of these program elements. The staff’s 

evaluation of each of these elements follows.

• use of Inservice Inspection (IWB, IWC, and IWD) AMP

• use of Water Chemistry AMP

• compliance with all NRC Orders

• commitment to implement applicable bulletins and generic letters

• commitment to implement staff accepted industry guidelines

The approach taken by the GALL Report for these AMR items permits license renewal 

applicants to demonstrate consistency with the GALL Report by citing these aging management 

activities in their LRA AMR items. Alternatively, as has been done in this case, consistency with 

the GALL Report may be demonstrated for these items by developing an AMP and citing it for 

each applicable AMR item, which is consistent with SRP-LR Section A.1.2.3 and which 

addresses all of the recommended aging management activities listed above. The staff’s review 

of this AMP is, therefore, designed to verify consistency with SRP-LR Section A.1.2.3 and to 

ensure that the aging management activities listed for nickel-alloy components included in GALL 

Report Table 3.1-1, IDs 31 and 34, are addressed by the AMP.

Scope of the Program

The staff reviewed the applicant’s “scope of the program” program element against the criteria 

in SRP-LR Section A.1.2.3.1, which states that the program should include the specific 

structures and components for which the program manages aging.

. LRA Section B.2.2.3 states that the Nickel-Alloy Nozzles and 

Penetrations Program is an existing program that manages the effects of aging of nickel-alloy

components including alloy 82/182 weld metal in accordance with industry guidance documents, 

ASME B&PV Code, Code Case N-722, and 10 CFR 50.55a. The scope of the program element 

contains a specific list of components, which are included within the scope as well as a general 

specification of components, which are excluded. This section also states that the AMP 

complies with applicable NRC Orders and implements applicable NRC bulletins, generic letters,

and staff-accepted industry guidelines.

Based on the list provided, which addresses materials and components included within the 

scope of the AMP, the staff confirmed that the “scope of the program” program element satisfies 

the criterion defined in SRP-LR Section A.1.2.3.1; therefore, the staff finds it acceptable.

Preventive Actions. LRA Section B.2.2.3 states that the Water Chemistry Program AMP is used 

to prevent and mitigate PWSCC. Additionally, this section of the LRA states that several other 

preventive and mitigative techniques are available for use. These techniques include

mechanical stress improvement, induction heat stress improvement, weld overlay, mechanical 

nozzle seal assembly, zinc injection, abrasive water jet, nickel plating, or replacement with 

Alloy 690/52/152 components.
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The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that activities for prevention and mitigation programs 

should be described.

Based on the description of the available mitigative techniques, the staff confirmed that the 

“preventive actions” program element satisfies the criterion defined in SRP-LR

Section A.1.2.3.2; therefore, the staff finds it acceptable.

Parameters Monitored or Inspected

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which states that the parameters to be 

monitored or inspected should be identified and linked to the degradation of the particular 

structure and component intended function(s). Additionally, for a condition Monitoring Program, 

the parameters monitored or inspected should detect the presence and extent of aging effects.

. LRA Section B.2.2.3 states that the program monitors 

cracking due to PWSCC of Alloy 600/82/182 materials exposed to reactor coolant. This LRA 

section also states that the program performs condition monitoring examinations of the lower 

reactor vessel head surface and each bottom-mounted instrumentation tube penetration. This 

LRA section additionally states that these examinations monitor for through-wall cracks that may 

exist in the nozzles or their associated partial penetration J-groove welds. This LRA section 

further states that, for other in-scope pressure boundary components, the program monitors for 

evidence of reactor coolant leakage which may manifest itself in the form of boric acid residues 

or corrosion products. This LRA section finally states that the core support pads and lugs and 

clevis inserts are VT-3 inspected once per interval for evidence of cracking.

The staff finds that, for the components under consideration, cracking is the degradation 

mechanism, which will affect their intended function and that the exams included in the program 

will be capable of directly detecting cracks or will be capable of detecting secondary evidence of 

cracks (e.g., boric acid). Based on this finding, the staff confirmed that the “parameters 

monitored or inspected” program element satisfies the criterion defined in SRP-LR

Section A.1.2.3.3; therefore, the staff finds it acceptable.

Detection of Aging Effects

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that detection of aging effects should occur 

before there is a loss of the structure and component intended function(s). The criteria also 

states that parameters to be monitored or inspected should be appropriate to ensure that the 

structure and component intended function will be adequately maintained for license renewal 

under all CLB design conditions. The criteria further states that a program based solely on 

detecting structure and component failure should not be considered as an effective AMP for 

license renewal. The criteria states that this program element describes “when,” “where,” and 

“how” program data are collected (i.e., all aspects of activities to collect data as part of the 

program). The criteria continue by stating that the method or technique and frequency may be 

linked to plant-specific or industry-wide operating experience.

. LRA Section B.2.2.3 states that visual, surface, and volumetric 

exams are used to detect cracking due to SCC in Alloy 600/82/182 components. In this 

element, the applicant also states that SSCs will be inspected in accordance with the ASME 

Code, Section XI, Subsections IWB, IWC, and IWD Program.

In its review, the staff determined that cracking is an appropriate parameter to monitor to ensure 

the maintenance of intended function of the components under consideration. The staff also 

determined that a combination of visual, surface, and volumetric test methods were capable of 
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detecting cracking or secondary evidence of cracking, e.g., boric acid, prior to loss of intended 

function. The staff additionally determined that this AMP refers to the Code of Federal 

Regulations, the ASME Code, and various code cases and that the specifications (how, where, 

when) for these inspections are contained in these documents. The staff finally determined that 

there is no industry- or plant-specific operating experience, which necessitates deviating from 

the inspections proposed in this program element.

Based on the above evaluation, the staff confirmed that the “detection of aging effects” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.4; therefore, the staff finds it 

acceptable.

Monitoring and Trending

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities should 

be described, and they should provide predictability of the extent of degradation and, thus,

effect timely corrective or mitigative actions. The criteria also states that plant-specific or

industry-wide operating experience or both may be considered in evaluating the 

appropriateness of the technique and frequency. The criteria further states that this program 

element describes “how” the data collected are evaluated and may also include trending for a 

forward look, including an evaluation of the results against the acceptance criteria and a 

prediction regarding the rate of degradation in order to confirm that timing of the next scheduled 

inspection will occur before a loss of SC intended function.

. LRA Section B.2.2.3 states that the program incorporates the 

inspection schedules and frequencies for the nickel-alloy components in accordance with the 

ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and, 

where applicable, ASME Code Case N-722, subject to the conditions specified in 

10 CFR 50.55a(g)(6)(ii)(E). This section also provides a list of inspections to be conducted 

including the frequency of those inspections.

In this review, the staff determined that this program element adequately describes the 

monitoring and trending that is proposed. The staff also determined that the governing 

documents for the inspections to be monitored and trended provide sufficient guidance 

concerning inspection frequency and the modification of that frequency based on past 

inspections, or other plant-specific or industry operating experience, to provide timely corrective 

action or mitigation or additional inspections prior to loss of intended function. The staff further 

determined that the program element and the governing documents provided sufficient 

guidance to allow collected data to be compared to applicable acceptance standards.

Based on the above evaluation, the staff confirmed that the “monitoring and trending” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.5; therefore, the staff finds it 

acceptable.

Acceptance Criteria

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states the acceptance criteria of the program and its basis 

should be described to include ensuring that the structure and component intended function(s) 

are maintained under all CLB design conditions during the period of extended operation. 

Acceptance criteria could be specific numerical values, or could consist of a discussion of the 

process for calculating specific numerical values of conditional acceptance criteria to ensure 

that the structure and component intended function(s) will be maintained under all CLB design 

. LRA Section B.2.2.3 states that acceptance criteria for this program are 

contained in governing documents, e.g., ASME Code and Code Cases.
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conditions. Information from available references may be cited. The criteria also states that 

acceptance criteria, which do permit degradation, are based on maintaining the intended 

function under all CLB design loads. The criteria further states that qualitative inspections 

should be performed to the same predetermined criteria as quantitative inspections by 

personnel in accordance with ASME Code and through approved site-specific programs.

In its review, the staff determined that the acceptance criteria for these inspections are clearly 

defined in the program element or in the governing documents. The staff also has no reason to 

believe that these values, many of which carry the force of regulation, would not allow for the 

intended function of the components under consideration to be maintained during the period of 

extended operation under all CLB design loads.

Based on the above review, the staff confirmed that the “acceptance criteria” program element 

satisfies the criterion defined in SRP-LR Section A.1.2.3.6; therefore, the staff finds it 

acceptable.

Operating Experience

The staff reviewed this information against the acceptance criteria in SRP-LR

Section A.1.2.3.10, which states that the operating experience information provided should 

provide objective evidence that the effects of aging will be adequately managed so that the 

intended function(s) of the in-scope components and structures are maintained during the 

period of extended operation.

. LRA Section B.2.2.3 summarizes operating experience related to the 

Nickel-Alloy Nozzles and Penetrations Program. In this program element, the applicant 

provided results from six different inspections and, when necessary, the corrective actions that 

were taken as a result of these inspections. The inspections described included hot leg 

nozzles, lower head penetrations, pressurizer butt welds, steam generator bowl drain 

connections, pressurizer nozzles, and reactor vessel nozzle butt welds. During these 

inspections, one axial flaw was discovered in 82/182 weld material in the reactor vessel Loop 

“D” hot leg nozzle. This flaw was mitigated via the mechanical stress improvement process. 

Additionally, six pressurizer nozzles were preemptively mitigated via the installation of Alloy 52M 

full structural weld overlays.

In this review, the staff found that the applicant was conducting the inspections in accordance 

with the regulation, the ASME Code, and this AMP. The staff also found that the applicant was 

correctly responding to the findings of the inspections. Based on the preemptive mitigation 

conducted by the applicant, the staff concluded that the applicant was appropriately addressing 

the issue of PWSCC.

Based on this review, the staff finds that operating experience related to the applicant’s program 

demonstrated that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking appropriate corrective actions. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

The staff reviewed this UFSAR supplement description of the program and noted that it provides 

an adequate description of the program. However, the staff also noted that the applicable 

. LRA Section A.2.2.3 provides the UFSAR supplement for the Nickel-Alloy 

Nozzles and Penetrations Program.
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bulletins, generic letters, and staff-accepted industry guidelines are not included in the UFSAR 

description of the program or commitments.

By letter dated December 14, 2010, the staff issued RAI B.2.2.3-1 requesting that the applicant 

provide justification to why the applicable bulletins, generic letters, and staff-accepted industry 

guidelines are not necessary in the UFSAR supplement or commitment. 

In its response dated January 13, 2011, the applicant provided a commitment to implement 

applicable bulletins, generic letters, and staff-accepted industry guidelines.

The staff finds this response acceptable because the applicant committed to the implementation 

of applicable bulletins, generic letters, and staff-accepted industry guidelines, and is consistent

with GALL Report Table 3.1-1, IDs 31 and 34, and their subordinate items. The staff’s concern 

described in RAI B.2.2.3-1 is resolved.

The staff determined that the information in the UFSAR supplement, as amended by the 

commitment provided, is an adequate summary description of the program, as required by 

10 CFR 54.21(d) and is, therefore, acceptable.

Conclusion

3.0.3.3.5 Pressurized-Water Reactor Vessel Internals Program

. On the basis of its technical review of the applicant’s Nickel-Alloy Nozzles and 

Penetrations Program, the staff concludes that the applicant demonstrated that, through the use 

of this AMP, the effects of aging of nickel alloys may be adequately managed so that the 

intended function(s) of the components under consideration 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).

Summary of Technical Information in the Application. LRA Section B.2.1.7 describes the PWR 

Vessel Internals Program as plant-specific. The applicant stated that the PWR Vessel Internals 

Program is a new program which manages the aging effect of cracking due to 

irradiation-assisted stress corrosion cracking (IASCC), PWSCC, intergranular stress corrosion 

cracking (IGSCC), reduction in fracture toughness due to radiation and thermal embrittlement, 

void swelling, and loss of preload in RVI components.

Staff Evaluation. The staff reviewed program elements one through six and ten of the 

applicant’s program against the acceptance criteria for the corresponding elements, as stated in 

SRP-LR Section A.1.2.3. The staff’s review focused on how the applicant’s program manages 

aging effects through the effective incorporation of these program elements. The staff’s 

evaluation of each of these elements follows.

Scope of the Program. LRA Section B.2.1.7 states that the PWR Vessel Internals Program is a 

new program that manages the effects of aging of bolted and non-bolted RVI components in the 

upper and lower internals assemblies. The scope of the program element contains a specific 

list of components, which are not included within the scope. This section also states that the 

AMP will follow the NRC-approved inspection and evaluation guidelines with primary 

inspections on components that are highly susceptible to at least one of the aging mechanisms 

and have a relatively high consequence of failure. When primary inspections detect significant 

aging, the program requires inspection expansion to include additional highly and moderately 

susceptible components that have moderate consequence of failure. Some susceptible 

components are already covered by existing AMPs that are capable of managing the effects of 
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aging and are specifically not included. No additional measures are appropriate for other 

components because they would have little consequence if they did happen to fail. This 

categorization of components does not supersede the ASME Code Section XI ISI requirements.

The staff reviewed the applicant’s “scope of the program” program element against the criteria 

in SRP-LR Section A.1.2.3.1, which states that the program should include the specific 

structures and components for which the program manages aging.

Based on the applicant’s commitment to follow the NRC-approved inspection and evaluation 

guidelines, which addresses materials and components included within the scope of the AMP, 

the staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.1; therefore, the staff finds it acceptable.

Preventive Actions

The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that activities for prevention and mitigation programs 

should be described.

. LRA Section B.2.1.7 states that the PWR Vessel Internals Program is a 

Condition Monitoring Program to perform inspections, and it does not include preventive

actions. The Water Chemistry Program, LRA Section B.2.1.2, is used to prevent and mitigate 

cracking by controlling the concentrations of detrimental contaminants below the levels that are 

known to cause degradation. The Water Chemistry Program includes the specifications for 

chemical species, test frequency for sampling and analysis, as well as corrective actions to 

maintain control of the water chemistry within the vessel.

Based on the description of the existing AMP in LRA Section B.2.1.2, the staff confirmed that 

the “preventive actions” program element satisfies the criterion defined in SRP-LR

Section A.1.2.3.2; therefore, the staff finds it acceptable.

Parameters Monitored or Inspected

Where visual inspections are required, the applicant stated that VT-3 visual techniques are 

credited for the inspections. The applicant also states that the program performs either VT-1 or 

enhanced VT-1 (EVT-1) visual inspections when surface discontinuities and imperfections on 

the surface must be detected while subsurface discontinuities and imperfections will be detected 

with volumetric inspections. Visual inspections and physical measurements will detect changes 

in clearances, settings, and displacements associated with aging effects.

. LRA Section B.2.1.7 states that the program monitors the 

extent of aging degradation of the reactor internals with one-time, periodic, and conditional 

inspections (visual, surface, or volumetric examinations and physical measurements), and other 

aging management methodologies, as needed, in accordance with the NRC-approved 

inspection and evaluation guidelines and the ASME Code Section XI ISI Program.

The removable core support structures in the reactor vessel require a VT-3 visual inspection in 

accordance with ASME Code Section XI, Table IWB-2500-1, Examination Category B-N-3 once 

every ISI interval.

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which states that the parameters to be 

monitored or inspected should be identified and linked to the degradation of the particular 

structure and component intended function(s). Additionally, for a Condition Monitoring Program, 

the parameters monitored or inspected should detect the presence and extent of aging effects.
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The staff finds that, where cracking is the physical evidence of the degradation mechanism that 

will affect the intended function of a given component, the inspections included in the program 

will be capable of directly detecting cracks. Where other parameters such as changes in 

clearances, settings, and displacements are associated with aging mechanisms, the staff finds 

the VT-3 visual inspections with physical measurements are acceptable methods to detect the 

presence and extent of an aging mechanism. The staff also noted that the applicant has 

committed to following the NRC-approved inspection and evaluation guidelines and the ASME 

Code Section XI ISI Program as well as submitting a detailed inspection plan for NRC approval 

either 2 years after the renewed license has been issued or 2 years before entering into the 

period of extended operation, whichever comes first. Based on these findings, the staff 

confirmed that the “parameters monitored or inspected” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.3; therefore, the staff finds it acceptable.

Detection of Aging Effects

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that detection of aging effects should occur 

before there is a loss of the structure and component intended function(s). The criteria also 

states that parameters to be monitored or inspected should be appropriate to ensure that the 

structure and component intended function will be adequately maintained for license renewal 

under all CLB design conditions. The criteria further states that a program based solely on 

detecting structure and component failure should not be considered as an AMP for license 

renewal. The criteria states that this program element describes “when,” “where,” and “how” 

program data are collected (i.e., all aspects of activities to collect data as part of the program). 

The criteria continue by stating that the method or technique and frequency may be linked to 

plant-specific or industry-wide operating experience.

. LRA Section B.2.1.7 states that the applicant’s program is based on 

the methodologies described in MRP-227, “Material Reliability Program: Pressurized Water 

Reactor Internals Inspection and Evaluation Guidelines,” where visual, surface, and volumetric 

exams are used to detect cracking and other aging mechanisms that could impact the intended 

function of internal components. All of the inspections are based on well-documented and 

frequently demonstrated examination procedures with which the industry has considerable 

experience. MRP-227 describes when inspections on internals should be performed (initial 

baseline and ongoing ISI on components in the primary category as well as expansion criteria), 

where the inspections should focus to find degradation in terms of sampling and coverage, and 

how the results of the inspections should be reported so that the industry is updated on any 

findings. In addition, the program identifies those components for which no additional measures 

are required because the existing AMPs—like the ASME Code, Section XI inspections—are 

capable of detecting the degradation before the loss of function of the component.

In its review, the staff determined that cracking and general condition monitoring are appropriate 

parameters to monitor to ensure the maintenance of intended function of the components under 

consideration. The staff also determined that a combination of visual, surface, and volumetric 

test methods were capable of detecting cracks or other signs of damage related to degradation 

mechanisms, such as loss of preload or void swelling, prior to the loss of intended function. The 

staff additionally determined that the AMP refers to the NRC-approved, MRP-227 inspection 

and evaluation guidelines, and the ASME Code Section XI Code so that the specifications (how, 

where, when) for these inspections are explicitly stated.

Based on the above evaluation, the staff confirmed that the “detection of aging effects” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.4; therefore, the staff finds it 

acceptable.
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Monitoring and Trending

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities should 

be described, and they should provide predictability of the extent of degradation and, thus,

effect timely corrective or mitigative actions. The criteria also states that plant-specific or

industry-wide operating experience or both may be considered in evaluating the 

appropriateness of the technique and frequency. The criteria further states that this program 

element describes “how” the data collected are evaluated and may also include trending for a 

forward look, including an evaluation of the results against the acceptance criteria and a 

prediction regarding the rate of degradation in order to confirm that timing of the next scheduled 

inspection will occur before a loss of SC intended function.

. LRA Section B.2.1.7 states that the program incorporates the 

inspection schedules and frequencies for the primary PWR internal components, in accordance 

with the NRC-approved, MRP-227 inspection and evaluation guidelines and the ASME Code

Section XI ISI. If significant aging is detected in the primary components, the AMP also 

provides the procedures for disposition of any indications in accordance with the acceptance 

criteria and the threshold for and the scope of inspection expansion.

In this review, the staff determined that this program element adequately describes the 

monitoring and trending that is proposed. The staff also determined that the governing 

documents for the inspections to be monitored and trended provide sufficient guidance 

concerning inspection frequency and the modification of that frequency based on past 

inspections, or other plant-specific or industry operating experience, to provide timely corrective 

action or mitigation or additional inspections prior to loss of intended function. The staff further 

determined that the program element and the governing documents provided sufficient 

guidance to allow collected data to be compared to applicable acceptance standards.

Based on the above evaluation, the staff confirmed that the “monitoring and trending” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.5; therefore, the staff finds it 

acceptable.

Acceptance Criteria

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states the acceptance criteria of the program and its basis 

should be described to include ensuring that the structure and component intended function(s) 

are maintained under all CLB design conditions during the period of extended operation. 

Acceptance criteria could be specific numerical values or could consist of a discussion of the 

process for calculating specific numerical values of conditional acceptance criteria to ensure 

that the structure and component intended function(s) will be maintained under all CLB design 

conditions. Information from available references may be cited. The criteria also states that 

acceptance criteria, which do permit degradation, are based on maintaining the intended 

function under all CLB design loads. The criteria further states that qualitative inspections 

should be performed to the same predetermined criteria as quantitative inspections by 

personnel in accordance with ASME Code and through approved site-specific programs.

. LRA Section B.2.1.7 states that acceptance criteria for this program are 

contained in the ASME Code, Section XI, Article IWB-3500, with additional guidance coming 

from the NRC-approved MRP-227. Detected conditions that do not meet the acceptance 

criteria will be dispositioned using the applicant’s Corrective Action Program. Detected 

conditions that do meet the acceptance criteria will be documented as acceptable because the 

intended function of the component will be maintained during the period of extended operation.
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In its review, the staff determined that the acceptance criteria for these inspections are clearly 

defined in the program element or in the governing documents. The staff also has no reason to 

believe that these values would not allow for the intended function of the components under 

consideration to be maintained during the period of extended operation under all CLB design 

loads.

Based on the above review, the staff confirmed that the “acceptance criteria” program element 

satisfies the criterion defined in SRP-LR Section A.1.2.3.6; therefore, the staff finds it 

acceptable.

Operating Experience

The staff reviewed this information against the acceptance criteria in SRP-LR

Section A.1.2.3.10, which states that the operating experience information provided should 

provide objective evidence that the effects of aging will be adequately managed so that the 

intended function(s) of the in-scope components and structures are maintained during the 

period of extended operation.

. LRA Section B.2.1.7 summarizes operating experience related to the

PWR Vessel Internals Program. In this program element, the applicant stated that the previous 

ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, Table IWB-2500-1, 

Category B-N-3 inspections for Seabrook RVIs, have not found any unacceptable indications. 

They will continue to participate in industry programs related to the aging effects on PWR vessel 

internals and will implement applicable results into their plant-specific AMP.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if 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 if the applicant 

adequately incorporated and evaluated operating experience related to this program.

During its review, the staff identified operating experience, which could indicate that the 

applicant’s program may not be effective in adequately managing aging effects during the 

period of extended operation. The staff determined the need for additional clarification, which 

resulted in the issuance of RAI B.2.1.7-1, where the staff asked the applicant to do the following:

• list all the components in the Seabrook RPV internals that are fabricated from 

Alloy X-750

• discuss any plant-specific experience with components fabricated with Alloy X-750

• discuss how the plant will manage aging of the Alloy X-750 components

The applicant responded on January 13, 2011, by stating that the only components in the 

Seabrook RPV internals fabricated from Alloy X-750 are the clevis insert bolts identified in the 

UFSAR Table 5.2-4. When the plant began operation, the control rod drive mechanism (CRDM) 

guide tube support pins were fabricated from Alloy X-750. Subsequent industry experience 

showed that the Alloy X-750 CRDM support pins were susceptible to PWSCC. Based on the 

industry experience, Seabrook decided to replace these CRDM support pins during RFO 11 

(October of 2006) with new, Westinghouse-designed CRDM support pins fabricated from cold 

worked stainless steel that demonstrated no susceptibility to PWSCC. Seabrook plans to 

manage the future age-related degradation for the clevis insert bolts by the implementation of 

MRP-227, “Material Reliability Program: Pressurized Water Reactor Internals Inspection and 

Evaluation Guidelines,” and the ASME Code Section XI ISI, Subsections IWB, IWC, and IWD 

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

RAI B.2.1.7-1, the staff finds that operating experience related to the applicant’s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking appropriate corrective actions. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds 

the response acceptable and the issue resolved.

Based on this review, the staff finds that operating experience related to the applicant’s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program and that implementation of the program has resulted in the applicant 

taking appropriate corrective actions. The staff confirmed that the “operating experience” 

program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable.

UFSAR Supplement

The staff noted that the applicant committed (LRA Section A.3, Commitment No. 1) to submit an 

inspection plan for RVIs for NRC review and approval at least 24 months prior to entering the 

period of extended operation. Since the LRA was submitted, the NRC completed its review of 

the MRP-227. In the safety evaluation, one of the plant-specific action items calls for each 

applicant to perform an evaluation of its plant’s operating history, demonstrate the applicability 

of the approved version of MRP-227 to the facility, and submit this evaluation for NRC review 

and approval as part of its LRA to implement the approved version of MRP-227. For plants that 

have submitted their LRA, but have not received their renewed license, the NRC asked those 

plants to update their commitment to indicate that they will do the evaluation and create a 

plant-specific plan to implement the NRC-approved version within 24 months of receiving the 

renewed license or entering the period of extended operation, whichever comes first.

. LRA Section A.2.1.7 provides the UFSAR supplement for the PWR 

Vessel Internals AMP. The staff reviewed this UFSAR supplement description of the program 

and noted that it provides an adequate description of the program, as described in SRP-LR

Section 3.6.3.4 and Table 3.6.2.

By letter dated April 22, 2011, the applicant provided an updated commitment (Commitment 

No. 01) to do the evaluation of the NRC-approved version of MRP-227 and create a 

plant-specific plan to implement the AMP within 24 months of receiving the renewed license or 

entering the period of extended operation, whichever comes first.

The staff determined that the information in the UFSAR supplement, as amended by the 

updated commitment, provided an adequate summary description of the program, as required 

by 10 CFR 54.21(d) and is, therefore, acceptable.

Conclusion. On the basis of its technical review of the applicant’s PWR Vessel Internals Aging 

Management Program, the staff concludes that the applicant demonstrated that, through the 

use of this AMP, the effects of aging of the RVI components may be adequately managed so 

that the intended function(s) of the components under consideration 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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3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

3.0.4.1 Summary of Technical Information in the Application 

In Appendix A, “Updated Final Safety Analysis Report Supplement,” Section A.1.5, “Quality 

Assurance Program and Administrative Controls,” and Appendix B, “Aging Management 

Programs,” Section B.1.3, “Quality Assurance Program and Administrative Controls,” of the 

LRA, the applicant described the elements of corrective action, confirmation process, and 

administrative controls that are applied to the AMPs for both safety-related and 

nonsafety-related components. The FPL/NextEra Energy Quality Assurance Program (QAP) is 

used, which includes the elements of corrective action, confirmation process, and administrative 

controls. Corrective actions, confirmation process, and administrative controls are applied in 

accordance with the QAP regardless of the safety classification of the components. 

Appendix A, Section A.1.5 and Appendix B, Section B.1.3, of the LRA state that the QAP 

implements the requirements of 10 CFR 50, Appendix B, “Quality Assurance Criteria for Nuclear 

Power Plants and Fuel Reprocessing Plants,” and is consistent with the NUREG-1800, 

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

(SRP-LR),” Revision 1.

3.0.4.2 Staff Evaluation 

Pursuant to 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. Of these 10 attributes, 3 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 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 
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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 the applicant’s AMPs described in Appendix A and Appendix B of the LRA, 

AMP basis documents, and the associated implementing procedures. The purpose of this 

review was to confirm that the QA attributes (corrective action, confirmation process, and 

administrative controls) were consistent with the staff’s guidance described in Branch Technical 

Position IQMB-1. Based on the staff’s evaluation, the descriptions of the AMPs and their 

associated quality attributes provided in Appendix A, Section A.1.5, and Appendix B,

Section B1.3, of the LRA are consistent with the staff’s position regarding QA for aging 

management.

3.0.4.3 Conclusion 

On the basis of the staff’s evaluation, the descriptions and applicability of the plant-specific 

AMPs and their associated quality attributes provided in Appendix A, Section A.1.5, and 

Appendix B, Section B1.3 of the LRA, were determined to be consistent with the staff’s position 

regarding QA for aging management. The staff concludes that the QA attributes (corrective 

action, confirmation process, and administrative control) of the applicant's AMPs are consistent 

with 10 CFR 54.21(a)(3).

3.0.5 Operating Experience

3.0.5.1 Summary of Technical Information in the Application 

LRA Section B.1.4 describes the consideration of operating experience for AMPs. The LRA 

states that operating experience for existing programs and activities was reviewed as an input to 

the AMP evaluations. 

This review included plant records, such as reports generated under the corrective action 

program, and was focused on degradation due to aging-related issues. The LRA also states 

that the operating experience review considered the results of plant-specific and industry 

operating experience and interviews with site personnel. Further, LRA Section 3.0.3 states that, 

“ongoing review of plant-specific and industry operating experience is performed in accordance 

with the plant Operating Experience Program and as a part of selected Seabrook Station aging 

management programs.” 

3.0.5.2 Staff Evaluation 

The staff issued its final License Renewal Interim Staff Guidance LR-ISG-2011-05, “Ongoing

Review of Operating Experience,” dated March 16, 2012, which clarifies that AMPs should be 

informed, and enhanced when necessary, based on the ongoing review of both plant-specific 

and industry operating experience. Also, pursuant to 10 CFR 54.21(a)(3), an applicant is 

required to demonstrate that the effects of aging on systems, structures, and components

subject to an AMR will be adequately managed so that its 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. 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 managed adequately 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 managed adequately so that the structure- and componentintended 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 evaluation 

below discusses the staff’s review of the first attribute, which concerns the consideration of 

future operating experience and is applicable to both new and existing programs.

The staff reviewed LRA Sections B.1.4 and B.2.1.1 through B.2.3.2 to determine whether the 

applicant will implement adequate activities for the continual review of both plant-specific and 

industry operating experience to identify areas where AMPs should be enhanced or new AMPs 

developed. The staff determined that these LRA sections describe how the applicant 

incorporated operating experience into its AMPs, but they do not fully describe how the 

applicant will use future operating experience to ensure that the AMPs will remain effective for 

managing the aging effects during the period of extended operation. While the program 

descriptions contain statements indicating that future operating experience will be used to adjust 

the programs as appropriate, the details of this process are not fully described. 

It was not clear to the staff whether the applicant intends to implement actions to monitor 

operating experience on an ongoing basis and use it to ensure the continued effectiveness of 

these AMPs. Further, the LRA does not state whether new AMPs will be developed, as 

necessary.
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By letter dated December 12, 2011, the staff issued RAI B.1.4-2 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.

By letter dated January 20, 2012, the applicant provided its response to the staff’s RAI. 

Subsequent to receipt of the applicant’s response, the staff also issued its final License 

Renewal Interim Staff Guidance LR-ISG-2011-05, “Ongoing Review of Operating Experience.” 

The staff is currently reviewing the applicant’s response to determine its adequacy. This issue 

is identified as OI B.1.4-2.

3.0.5.3 UFSAR Supplement

The staff reviewed the UFSAR 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. As the staff found no such description, it also 

requested in RAI B.1.4-1 that the applicant provide a description of these activities for the 

UFSAR supplement required by 10 CFR 54.21(d).

In its response dated August 25, 2011, the applicant provided the following summary description 

of the operating experience review activities for the UFSAR supplement: 

The existing Corrective Action Program and the Operating Experience Program 

ensure, through the continual review of both plant-specific and industry operating 

experience, that the license renewal aging management programs are effective 

to manage the aging effects for which they are credited. The programs are either 

enhanced or new programs are developed when the review of operating 

experience indicates that the programs may not be effective. For each aging 

management program, operating experience is reviewed on a continuing basis.

The staff reviewed this UFSAR supplement description against the acceptance criteria in 

SRP-LR Sections 3.1.2.5, 3.2.2.5, 3.3.2.5, 3.4.2.5, 3.5.2.5, and 3.6.2.5. In accordance with 

these sections, the summary description should be sufficiently comprehensive such that later 

changes can be controlled by 10 CFR 50.59. With respect to these criteria, the staff determined 

that this summary description is not sufficiently comprehensive. 

The applicant described generally how it intends to consider operating experience on an 

ongoing basis; however, it did not provide specific information on how its operating experience 

review activities address issues related to aging. Similarly, the above entry for UFSAR 

supplement also lacks detail on how aging is considered in the ongoing operating experience 

reviews. By letter dated December 12, 2011, the staff requested the applicant to clarify the 

UFSAR summary description provided in the applicant’s letter dated August 25, 2011.

By letter dated January 20, 2012, the applicant provided its response to the staff’s RAI. 

Subsequent to receipt of the applicant’s response, the staff also issued its final License 

Renewal Interim Staff Guidance LR-ISG-2011-05, “Ongoing Review of Operating Experience.” 

The staff is currently reviewing the applicant’s response to determine its adequacy. This issue 

is identified as OI B.1.4-2.

3.0.5.4 Conclusion

The staff’s conclusion regarding the applicant’s programmatic activities for the ongoing review of 

operating experience is pending resolution of the OI B.1.4-2.
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3.1

This section of the SER documents the staff’s review of the applicant’s AMR results for the RCS 

components and component groups of the following:

Aging Management of Reactor Coolant System

• RCS

• reactor vessel

• RVIs

• steam generator

3.1.1 Summary of Technical Information in the Application

LRA Section 3.1 provides AMR results for the RCS, reactor vessel, RVIs, and steam generator. 

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 RCS, reactor vessel, RVIs, and steam generator 

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 

issue 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 if the applicant provided sufficient information 

to demonstrate that the effects of aging for the RCS, reactor vessel, RVIs, and steam generator 

components within the scope of license renewal and subject to an AMR will be adequately 

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

period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff reviewed the AMRs to confirm the applicant’s claim that certain identified 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 had identified the appropriate GALL Report AMRs. Details of 

the staff’s evaluation are discussed in SER Section 3.1.2.1.

The staff reviewed 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 3.1.2.2 acceptance criteria. The staff’s evaluations are documented in 

SER Section 3.1.2.2.

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. 

The technical review evaluated whether all plausible aging effects were identified and whether 

the aging effects listed were appropriate for the specified material-environment combinations.

Details of the staff’s evaluation are presented in SER Section 3.1.2.3.

For components 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.
Aging Management Review Results

3-194

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 GALL Report

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Steel pressure 

vessel support skirt 

and attachment 

welds 

(3.1.1-1)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Yes Not applicable Not applicable to 

PWRs 

(See SER 

Section 3.1.2.1.1)

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy RV

components: 

flanges; nozzles; 

penetrations; safe 

ends; thermal 

sleeves; vessel 

shells, heads, and 

welds 

(3.1.1-2)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Yes Not applicable Not applicable to 

PWRs 

(See SER 

Section 3.1.2.1.1)

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

RCPB piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant

(3.1.1-3)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Yes Not applicable Not applicable to 

PWRs 

(See SER

Section 3.1.2.1.1)

Steel pump and 

valve closure bolting

(3.1.1-4)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and Code limits 

checked for 

allowable cycles 

(less than 

7,000 cycles) of 

thermal stress 

range

Yes Not applicable Not applicable to 

PWRs 

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy RVI 

components

(3.1.1-5)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Yes TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)
Aging Management Review Results

3-195

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Ni-alloy tubes and 

sleeves in a reactor 

coolant and 

secondary 

feedwater/steam 

environment

(3.1.1-6)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Yes TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel and stainless 

steel RCPB closure 

bolting, head closure 

studs, support skirts 

and attachment 

welds; pressurizer 

relief tank 

components; steam 

generator 

components; piping 

and components 

external surfaces 

and bolting

(3.1.1-7)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Yes TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel; stainless steel; 

Ni-alloy RCPB 

piping, piping 

components, piping 

elements; flanges; 

nozzles and safe 

ends; pressurizer 

vessel shell heads 

and welds; heater 

sheaths and sleeves; 

penetrations; thermal 

sleeves

(3.1.1-8)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Yes TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

reactor vessel 

components: 

flanges; nozzles; 

penetrations; 

pressure housings; 

safe ends; thermal 

sleeves; vessel 

shells, heads, and 

welds

(3.1.1-9)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Yes TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)
Aging Management Review Results

3-196

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

steam generator 

components 

(flanges; 

penetrations; 

nozzles; safe ends, 

lower heads, and 

welds)

(3.1.1-10)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Yes TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c) 

and 

environmental 

effects addressed 

for Class 1 

components

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel top head 

enclosure (without 

cladding) and top 

head nozzles (vent, 

top head spray, or 

reactor core isolation 

cooling, and spare) 

exposed to reactor 

coolant

(3.1.1-11)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel steam 

generator shell 

assembly exposed to 

secondary feedwater 

and steam

(3.1.1-12)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Once-through 

steam generator 

(OTSG) only

Applicable to 

OTSGs, 

therefore, not 

applicable to 

Seabrook

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel isolation 

condenser 

components exposed 

to reactor coolant

(3.1.1-13)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel; Ni 

alloy; steel with Nialloy or stainless 

steel cladding RV

flanges, nozzles, 

penetrations, safe 

ends, vessel shells, 

heads, and welds

(3.1.1-14)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

RCPB components 

exposed to reactor 

coolant

(3.1.1-15)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-197

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Steel steam 

generator upper and 

lower shell and 

transition cone 

exposed to 

secondary feedwater 

and steam

(3.1.1-16)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry. 

For Westinghouse 

Model 44 and 51 

steam generators, 

if general and 

pitting corrosion of 

the shell is known 

to exist, additional 

inspection 

procedures are to 

be developed.

Yes ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program; Water 

Chemistry 

Program; and 

Steam Generator 

Tube Integrity 

Program

Consistent with 

the GALL Report 

(See SER Section

3.1.2.2.2) 

Steel (with or without 

stainless steel 

cladding) RV beltline 

shell, nozzles, and 

welds

(3.1.1-17)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement

TLAA, 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, evaluated 

in accordance 

with 

10 CFR 54.21(c), 

Appendix G of 

10 CFR 50, and 

RG 1.99

Loss of fracture 

toughness due to

neutron irradiation 

is a TLAA (See 

SER Section

3.1.2.2.3)

Steel (with or without 

stainless steel 

cladding) RV beltline 

shell, nozzles, and 

welds; safety 

injection nozzles

(3.1.1-18)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement

Reactor Vessel 

Surveillance

Yes RV Surveillance 

Program

Consistent with 

the GALL Report

(See SER Section

3.1.2.2.3)

Stainless steel and 

Ni-alloy top head 

enclosure vessel 

flange leak detection 

line

(3.1.1-19)

Cracking due to 

SCC and 

IGSCC

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel 

isolation condenser 

components exposed 

to reactor coolant

(3.1.1-20)

Cracking due to 

SCC and 

IGSCC

ISI (IWB, IWC, 

and IWD), Water 

Chemistry, and 

plant-specific 

verification 

program

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-198

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

RV shell fabricated of 

SA508-Cl 2 forgings 

clad with stainless 

steel using a highheat-input welding 

process

(3.1.1-21)

Crack growth 

due to cyclic 

loading

TLAA Yes Not Applicable—

Seabrook’s RV

shell is not 

fabricated of 

SA508-Cl 2 

forgings clad with 

stainless steel 

using a high-heatinput welding 

process.

Not applicable to 

Seabrook

(See SER 

Section 3.1.2.2.5)

Stainless steel and 

Ni-alloy RVI 

components exposed 

to reactor coolant 

and neutron flux

(3.1.1-22)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement, 

void swelling

UFSAR 

supplement 

commitment 

to participate in 

industry RVI aging 

programs; 

implement 

applicable results; 

and submit for 

staff approval, 

greater than 

24 months before 

the period of 

extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No PWR Vessel 

Internals Program

Consistent with 

the GALL Report

(See SER 

Section 3.1.2.2.6)

Stainless steel 

reactor vessel 

closure head flange 

leak detection line 

and bottom-mounted 

instrument guide 

tubes

(3.1.1-23)

Cracking due to 

SCC

A plant-specific 

AMP is to be 

evaluated.

Yes ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program

Consistent with 

the GALL Report 

(See SER Section

3.1.2.2.7)

Class 1 CASS 

piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant

(3.1.1-24)

Cracking due to 

SCC

Water Chemistry 

and, for CASS 

components that 

do not meet the 

NUREG-0313 

guidelines, a 

plant-specific 

AMP

Yes ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program, and 

Water Chemistry 

Program

Consistent with 

the GALL Report 

(See SER 

Section 3.1.2.2.7)

Stainless steel jet 

pump sensing line

(3.1.1-25)

Cracking due to 

cyclic loading

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable Not applicable to 

PWRs 

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel isolation 

condenser 

components exposed 

to reactor coolant

(3.1.1-26)

Cracking due to 

cyclic loading

ISI (IWB, IWC, 

and IWD) and 

plant-specific 

verification 

program

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-199

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Stainless steel and 

Ni-alloy RVI screws, 

bolts, tie rods, and 

hold down springs

(3.1.1-27)

Loss of preload 

due to stress 

relaxation

UFSAR 

supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 

24 months before 

the period of 

extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No PWR Vessel 

Internals Program

Consistent with 

the GALL Report

(See SER 

Section 3.1.2.2.9)

Steel steam 

generator feedwater 

impingement plate 

and support exposed 

to secondary 

feedwater

(3.1.1-28)

Loss of material 

due to erosion

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable to 

Seabrook

Not applicable to 

Seabrook

(See SER Section

3.1.2.2.10)

Stainless steel steam 

dryers exposed to 

reactor coolant

(3.1.1-29)

Cracking due to 

flow-induced 

vibration

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel RVI 

components 

(e.g., upper internals 

assembly, rod cluster 

control assembly 

guide tube 

assemblies, 

baffle/former 

assembly, lower 

internal assembly, 

shroud assemblies, 

plenum cover and 

plenum cylinder, 

upper grid assembly, 

control rod guide 

tube assembly, core 

support shield 

assembly, core 

barrel assembly, 

lower grid assembly, 

flow distributor 

assembly, thermal 

shield, 

instrumentation 

support structures)

(3.1.1-30)

Cracking due to 

SCC and 

IASCC

Water Chemistry 

and UFSAR 

supplement 

commitment to: 

(1) participate in 

industry, RVI 

aging programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 

24 months before 

the period of 

extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No PWR Vessel 

Internals and 

Water Chemistry 

programs

Consistent with 

the GALL Report

(See SER Section

3.1.2.2.12)
Aging Management Review Results

3-200

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Ni alloy and steel 

with Ni-alloy cladding 

piping, piping 

component, piping 

elements, 

penetrations, 

nozzles, safe ends, 

and welds (other 

than RV head); 

pressurizer heater 

sheaths, sleeves, 

diaphragm plate, 

manways, and 

flanges; core support 

pads/core guide lugs

(3.1.1-31)

Cracking due to 

PWSCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry 

and UFSAR 

supplement 

commitment to 

implement 

applicable plant 

commitments to

NRC Orders, 

bulletins, and GLs 

associated with Ni 

alloys and staffaccepted industry 

guidelines.

No ASME Code

Section XI ISI

Subsections IWB, 

IWC, and IWD 

Program, NickelAlloy Nozzles and 

Penetrations 

Program, and the 

Water Chemistry 

Program

Consistent with 

the GALL Report

(See SER Section

3.1.2.2.13)

Steel steam 

generator feedwater 

inlet ring and 

supports

(3.1.1-32)

Wall thinning 

due to flowaccelerated 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Steam Generator 

Tube Integrity 

Program

Consistent with 

GALL Report

(See SER Section

3.1.2.2.14)

Stainless steel and 

Ni-alloy RVI 

components

(3.1.1-33)

Changes in 

dimensions due 

to void swelling

UFSAR 

supplement 

commitment to

participate in 

industry RVI aging 

programs; 

implement 

applicable results; 

and submit for 

staff approval, 

greater than 

24 months before 

the period of 

extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No PWR Vessel 

Internals Program

Consistent with 

the GALL Report

(See SER Section

3.1.2.2.15)

Stainless steel and 

Ni-alloy reactor 

control rod drive 

(CRD) head 

penetration pressure 

housings

(3.1.1-34)

Cracking due to 

SCC and 

PWSCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry. 

For Ni alloy, 

UFSAR 

supplement 

commitment to 

implement 

applicable plant 

commitments to

NRC Orders, 

bulletins, and GLs 

associated with Ni 

alloys and staffaccepted industry 

guidelines.

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program and 

Water Chemistry 

Program 

Consistent with 

the GALL Report

(See SER Section

3.1.2.2.16)
Aging Management Review Results

3-201

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Steel with stainless 

steel or Ni-alloy 

cladding primary side 

components; steam 

generator upper and 

lower heads; 

tubesheets; and 

tube-to-tubesheet 

welds

(3.1.1-35)

Cracking due to 

SCC and 

PWSCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry. 

For Ni alloy, 

UFSAR 

supplement 

commitment to 

implement 

applicable plant 

commitments to

NRC Orders, 

bulletins, and GLs 

associated with Ni 

alloys and staffaccepted industry 

guidelines.

No Submit plantspecific AMP to 

manage tubetubesheet welds 

at least 

24 months prior 

to the period of 

extended 

operation 

(Commitment 

No. 54) 

Applicable to 

OTSGs;

therefore, not 

applicable to 

Seabrook except 

for tube-totubesheet welds 

between Ni-alloy 

cladding and Nialloy tubes in the 

steam generator

(see SER Section 

3.1.2.2.16)

Ni-alloy, stainless 

steel pressurizer 

spray head

(3.1.1-36)

Cracking due to 

SCC and 

PWSCC

Water Chemistry 

and One-Time 

Inspection. For 

Ni-alloy welded 

spray heads, 

provide 

commitment in 

UFSAR 

supplement to 

submit AMP 

delineating 

commitments to 

NRC Orders, 

bulletins, or GLs 

that inspect 

stipulated 

components for 

cracking of wetted 

surfaces.

No One-Time 

Inspection and 

Water Chemistry 

Programs

Consistent with 

the GALL Report

(See SER Section

3.1.2.2.16)

Stainless steel and 

Ni-alloy RVI 

components 

(e.g., upper internals 

assembly, rod cluster 

control assembly

guide tube 

assemblies, lower 

internal assembly, 

control element 

assembly (CEA)

shroud assemblies, 

core shroud 

assembly, core 

support shield 

assembly, core 

barrel assembly, 

lower grid assembly, 

flow distributor 

assembly)

(3.1.1-37)

Cracking due to 

SCC, PWSCC, 

and IASCC

Water Chemistry 

and UFSAR 

supplement 

commitment to

participate in 

industry RVI aging 

programs; 

implement 

applicable results; 

and submit for 

staff approval, 

greater than 

24 months before 

the period of 

extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No The PWR Vessel 

Internals Program 

and the Water 

Chemistry 

Program, 

including 

Commitment 

No. 01

Consistent with 

the GALL Report

(See SER Section

3.1.2.2.17)
Aging Management Review Results

3-202

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Steel (with or without 

stainless steel 

cladding) CRD return 

line nozzles exposed 

to reactor coolant

(3.1.1-38)

Cracking due to 

cyclic loading

BWR CRD Return 

Line Nozzle

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel (with or without 

stainless steel 

cladding) feedwater 

nozzles exposed to

reactor coolant

(3.1.1-39)

Cracking due to 

cyclic loading

BWR Feedwater 

Nozzle

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy penetrations 

for CRD stub tubes 

instrumentation, jet 

pump 

instrumentation, 

standby liquid 

control, flux monitor, 

and drain line 

exposed to reactor 

coolant

(3.1.1-40)

Cracking due to 

SCC, IGSCC, 

and cyclic 

loading

BWR 

Penetrations and 

Water Chemistry

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy piping, piping 

components, and 

piping elements 

≥ 4′′ nominal pipe 

size (NPS); nozzle 

safe ends and 

associated welds

(3.1.1-41)

Cracking due to 

SCC and 

IGSCC

BWR SCC and 

Water Chemistry

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy vessel shell 

attachment welds 

exposed to reactor 

coolant

(3.1.1-42)

Cracking due to 

SCC and 

IGSCC

BWR Vessel ID 

Attachment Welds 

and Water 

Chemistry

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel fuel 

supports and CRD 

assemblies and CRD 

housing exposed to 

reactor coolant

(3.1.1-43)

Cracking due to 

SCC and 

IGSCC

BWR Vessel 

Internals and 

Water Chemistry

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-203

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Stainless steel and 

Ni-alloy core shroud, 

core plate, core plate 

bolts, support 

structure, top guide, 

core spray lines, 

spargers, jet pump 

assemblies, CRD 

housing, and nuclear 

instrumentation 

guide tubes

(3.1.1-44)

Cracking due to 

SCC, IGSCC, 

and IASCC

BWR Vessel 

Internals and 

Water Chemistry

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant

(3.1.1-45)

Wall thinning 

due to flowaccelerated

corrosion

Flow-Accelerated 

Corrosion

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Ni-alloy core shroud 

and core plate 

access hole cover 

(mechanical covers)

(3.1.1-46)

Cracking due to 

SCC, IGSCC, 

and IASCC

ISI (IWB, IWC, 

and IWD), and 

Water Chemistry

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy RVIs 

exposed to reactor 

coolant

(3.1.1-47)

Loss of material 

due to pitting 

and crevice 

corrosion

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel Class 1 piping, 

fittings, and branch 

connections 

< 4′′ NPS exposed to 

reactor coolant

(3.1.1-48)

Cracking due to 

SCC, IGSCC 

(for stainless 

steel only), and 

thermal and 

mechanical 

loading

ISI (IWB, IWC, 

and IWD) Water 

chemistry, and 

One-Time 

Inspection of 

ASME Code 

Class 1 SmallBore Piping

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Ni-alloy core shroud 

and core plate 

access hole cover 

(welded covers)

(3.1.1-49)

Cracking due to 

SCC, IGSCC, 

and IASCC

ISI (IWB, IWC, 

and IWD), Water 

Chemistry, and, 

for BWRs with a 

crevice in the 

access hole 

covers, 

augmented 

inspection using 

UT or other 

demonstrated 

acceptable 

inspection of the 

access hole cover 

welds

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-204

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

High-strength lowalloy steel top head 

closure studs and 

nuts exposed to air 

with reactor coolant 

leakage

(3.1.1-50)

Cracking due to 

SCC and 

IGSCC

Reactor Head 

Closure Studs

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

CASS jet pump 

assembly castings

and orificed fuel 

support

(3.1.1-51)

Loss of fracture 

toughness due 

to thermal aging 

and neutron 

irradiation 

embrittlement

Thermal Aging 

and Neutron 

Irradiation 

Embrittlement of 

CASS

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel RCPB pump 

and valve closure 

bolting, manway and 

holding bolting, 

flange bolting, and 

closure bolting in 

high-pressure and 

high-temperature 

systems

(3.1.1-52)

Cracking due to 

SCC, loss of 

material due to 

wear, loss of 

preload due to 

thermal effects, 

gasket creep, 

and selfloosening

Bolting Integrity No Bolting Integrity 

Program

Consistent with 

the GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water

(3.1.1-53)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System Program

Consistent with 

the GALL Report

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water

(3.1.1-54)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook

(See SER 

Section 3.1.2.1.1)

CASS Class 1 pump 

casings and valve 

bodies and bonnets 

exposed to reactor 

coolant > 482 °F 

(250 °C)

(3.1.1-55)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

ISI (IWB, IWC, 

and IWD). 

Thermal aging 

susceptibility 

screening is not 

necessary, ISI 

requirements are 

sufficient for 

managing these 

aging effects. 

ASME Code Case 

N-481 also 

provides an 

alternative for 

pump casings.

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program 

Consistent with 

the GALL Report
Aging Management Review Results

3-205

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Copper-alloy

> 15% Zn piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water

(3.1.1-56)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Not applicable Not applicable to 

Seabrook

(See SER 

Section 3.1.2.1.1)

CASS Class 1 

piping, piping 

components, and 

piping elements and 

CRD pressure 

housings exposed to 

reactor coolant 

> 482 °F (250 °C)

(3.1.1-57)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Thermal Aging 

Embrittlement of 

CASS

No Not applicable Not applicable to 

Seabrook

(See SER 

Section 3.1.2.1.1)

Steel RCPB external 

surfaces exposed to 

air with borated 

water leakage

(3.1.1-58)

Loss of material 

due to boric 

acid corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion 

Program

Consistent with 

the GALL Report

Steel steam 

generator steam 

nozzle and safe end, 

feedwater nozzle and 

safe end, auxiliary 

feedwater nozzles 

and safe ends 

exposed to 

secondary 

feedwater/steam

(3.1.1-59)

Wall thinning 

due to flowaccelerated 

corrosion

Flow-Accelerated 

Corrosion

No Flow-Accelerated 

Corrosion 

Program

Consistent with 

the GALL Report

Stainless steel flux 

thimble tubes (with or 

without chrome 

plating)

(3.1.1-60)

Loss of material 

due to wear

Flux Thimble 

Tube Inspection

No Not applicable Not applicable to 

Seabrook

(See SER Section 

3.1.2.1.1)

Stainless steel and

steel pressurizer 

integral support 

exposed to air with 

metal temperature up 

to 550 °F (288 °C)

(3.1.1-61)

Cracking due to 

cyclic loading

ISI (IWB, IWC, 

and IWD)

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program

Consistent with 

the GALL Report

Stainless steel, steel 

with stainless steel 

cladding RCS cold 

leg, hot leg, surge 

line, and spray line 

piping and fittings 

exposed to reactor 

coolant

(3.1.1-62)

Cracking due to 

cyclic loading

ISI (IWB, IWC, 

and IWD)

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program

Consistent with 

the GALL Report
Aging Management Review Results

3-206

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Steel reactor vessel 

flange and stainless 

steel and Ni-alloy 

RVIs exposed to 

reactor coolant 

(e.g., upper and 

lower internals 

assembly, CEA 

shroud assembly, 

core support barrel, 

upper grid assembly, 

core support shield 

assembly, and lower 

grid assembly)

(3.1.1-63)

Loss of material 

due to wear

ISI (IWB, IWC, 

and IWD)

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program

Consistent with 

the GALL Report

Stainless steel and 

steel with stainless 

steel or Ni-alloy 

cladding pressurizer 

components

(3.1.1-64)

Cracking due to 

SCC and 

PWSCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program and 

Water Chemistry 

Program

Consistent with 

the GALL Report

Ni-alloy reactor 

vessel upper head 

and CRD penetration 

nozzles, instrument 

tubes, head vent 

pipe (top head), and 

welds

(3.1.1-65)

Cracking due to 

PWSCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry 

and Ni-Alloy 

Penetration 

Nozzles Welded 

to the Upper 

Reactor Vessel 

Closure Heads of 

Pressurized 

Water Reactors

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program, NickelAlloy Penetration 

Nozzles Welded 

to the Upper RV 

Closure Heads of 

PWRs Program, 

and Water 

Chemistry 

Program

Consistent with 

the GALL Report

Steel steam 

generator secondary 

manways and 

handholds 

(cover only) exposed 

to air with leaking 

secondary-side water 

or steam or both

(3.1.1-66)

Loss of material 

due to erosion

ISI (IWB, IWC, 

and IWD) for 

Class 2 

components

No Not applicable Not applicable to 

Seabrook,

applicable to 

OTSGs (See SER 

Section 3.1.2.1.1)

Steel with stainless 

steel or Ni-alloy 

cladding or stainless 

steel pressurizer 

components exposed 

to reactor coolant

(3.1.1-67)

Cracking due to 

cyclic loading

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program and 

Water Chemistry 

Program

Consistent with 

the GALL Report
Aging Management Review Results

3-207

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Stainless steel; steel 

with stainless steel 

cladding Class 1 

piping, fittings, pump 

casings, valve 

bodies, nozzles, safe 

ends, manways, 

flanges, CRD 

housing; pressurizer 

heater sheaths, 

sleeves, diaphragm 

plate; pressurizer 

relief tank 

components, RCS 

cold leg, hot leg, 

surge line, and spray 

line piping and 

fittings

(3.1.1-68)

Cracking due to 

SCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program, and 

Water Chemistry 

Program 

Consistent with 

the GALL Report 

Stainless steel, Nialloy safety injection 

nozzles, safe ends, 

and associated 

welds and buttering 

exposed to reactor 

coolant

(3.1.1-69)

Cracking due to

SCC and 

PWSCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program and 

Water Chemistry 

Program 

Consistent with 

the GALL Report 

(See SER Section

3.1.2.1.2)

Stainless steel; steel 

with stainless steel 

cladding Class 1 

piping, fittings, and 

branch connections 

< 4′′ NPS exposed to 

reactor coolant 

(3.1.1-70)

Cracking due to 

SCC and

thermal and 

mechanical 

loading

ISI (IWB, IWC, 

and IWD), Water 

Chemistry, and 

One-Time 

Inspection of 

ASME Code 

Class 1 SmallBore Piping

No ASME Code

Section XI ISI, 

Subsections IWB, 

IWC, and IWD 

Program, Water 

Chemistry 

Program, and 

One-Time 

Inspection of 

ASME Code 

Class 1 SmallBore Piping 

Program 

Consistent with 

the GALL Report

High-strength lowalloy steel closure 

head stud assembly 

exposed to air with 

reactor coolant 

leakage

(3.1.1-71)

Cracking due to 

SCC and loss of 

material due to 

wear

Reactor Head 

Closure Studs

No Reactor Head 

Closure Studs 

Program 

Consistent with 

the GALL Report
Aging Management Review Results

3-208

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Ni-alloy steam 

generator tubes and 

sleeves exposed to 

secondary 

feedwater/steam

(3.1.1-72)

Cracking due to 

outsidediameter stress

corrosion 

cracking and 

intergranular 

attack and loss 

of material due 

to fretting and 

wear

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity 

Program and 

Water Chemistry 

Program

Consistent with 

the GALL Report

Ni-alloy steam 

generator tubes, 

repair sleeves, and 

tube plugs exposed 

to reactor coolant

(3.1.1-73)

Cracking due to 

PWSCC

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity 

Program and 

Water Chemistry 

Program

Consistent with 

the GALL Report

Chrome plated steel, 

stainless steel, Nialloy steam 

generator antivibration bars 

exposed to 

secondary 

feedwater/steam

(3.1.1-74)

Cracking due to 

SCC and loss of 

material due to 

crevice 

corrosion and 

fretting

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity 

Program and 

Water Chemistry 

Program

Consistent with 

the GALL Report

Ni-alloy OTSG-tubes 

exposed to 

secondary 

feedwater/steam

(3.1.1-75)

Denting due to 

corrosion of 

carbon steel 

tube support 

plate

Steam Generator 

Tube Integrity and 

Water Chemistry

No Not applicable Not applicable to 

Seabrook, 

applicable to 

OTSGs (See SER 

Section 3.1.2.1.1)

Steel steam 

generator tube 

support plate and 

tube bundle wrapper 

exposed to 

secondary 

feedwater/steam

(3.1.1-76)

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion and

ligament 

cracking due to 

corrosion

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity 

Program and 

Water Chemistry 

Program

Consistent with 

the GALL Report

Ligament 

cracking due to 

corrosion is not 

applicable to the 

tube support 

plates since they 

are stainless steel

(See SER Section 

3.1.2.1.1)

Ni-alloy steam 

generator tubes and 

sleeves exposed to 

phosphate chemistry 

in secondary 

feedwater/steam

(3.1.1-77)

Loss of material 

due to wastage 

and pitting 

corrosion

Steam Generator 

Tube Integrity and 

Water Chemistry

No Not applicable Not applicable

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-209

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Steel steam 

generator tube 

support lattice bars 

exposed to 

secondary 

feedwater/steam

(3.1.1-78)

Wall thinning 

due to flowaccelerated 

corrosion

Steam Generator 

Tube Integrity and 

Water Chemistry

No Not applicable Not applicable

(See SER 

Section 3.1.2.1.1)

Ni-alloy steam 

generator tubes 

exposed to 

secondary 

feedwater/steam

(3.1.1-79)

Denting due to 

corrosion of 

steel tube 

support plate

Steam Generator 

Tube Integrity and 

Water Chemistry. 

For plants that 

could experience 

denting at the 

upper support 

plates, evaluate 

potential for 

rapidly 

propagating 

cracks and then 

develop and take 

corrective actions 

consistent with 

Bulletin 88-02.

No Not applicable Not applicable

(See SER 

Section 3.1.2.1.1)

CASS RVIs 

(e.g., upper internals 

assembly, lower 

internal assembly, 

CEA shroud 

assemblies, control 

rod guide tube 

assembly, core 

support shield 

assembly, lower grid 

assembly)

(3.1.1-80)

Loss of fracture 

toughness due 

to thermal aging 

and neutron 

irradiation 

embrittlement

Thermal Aging 

and Neutron 

Irradiation 

Embrittlement of 

CASS

No Not applicable Not applicable

(See SER 

Section 3.1.2.1.2)

Ni alloy or Ni-alloy 

clad steam generator 

divider plate exposed 

to reactor coolant

(3.1.1-81)

Cracking due to 

PWSCC

Water Chemistry No Water Chemistry 

Program and 

one-time 

inspection of SG 

divider plates 

Consistent with 

the GALL Report

(See SER 

Section 3.1.2.1)

Stainless steel steam 

generator primary 

side divider plate 

exposed to reactor 

coolant

(3.1.1-82)

Cracking due to 

SCC

Water Chemistry No Not applicable Not applicable to 

Seabrook, (See 

SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

RVIs and RCPB 

components exposed 

to reactor coolant

(3.1.1-83)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry No Water Chemistry 

Program

Consistent with 

the GALL Report
Aging Management Review Results

3-210

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation in 

GALL Report

AMP in LRA, 

supplements, or 

amendments

Staff evaluation

Ni-alloy steam 

generator 

components, such as 

secondary-side 

nozzles (vent, drain, 

and instrumentation) 

exposed to 

secondary 

feedwater/steam

(3.1.1-84)

Cracking due to 

SCC

Water Chemistry 

and One-Time 

Inspection or ISI

(IWB, IWC, and 

IWD)

No Not applicable Not applicable to 

Seabrook, 

applicable to 

OTSGs (See SER 

Section 3.1.2.1.1)

Ni-alloy piping, piping 

components, and 

piping elements 

exposed to air-indoor 

uncontrolled 

(external)

(3.1.1-85)

None None No None Consistent with 

the GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air-indoor 

uncontrolled 

(external); air with 

borated water 

leakage; concrete; 

gas

(3.1.1-86)

None None No None Consistent with 

the GALL Report

Steel piping, piping 

components, and 

piping elements in 

concrete

(3.1.1-87)

None None No Not applicable Not applicable to 

Seabrook 

(See SER 

Section 3.1.2.1.1)

The staff’s review of the RCS component groups followed one of several approaches. One 

approach, documented in SER Section 3.1.2.1, discusses the staff’s review of 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, discusses the staff’s 

review of 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 3.1.2.3, discusses the staff’s review of 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 RCS components is documented in 

SER Section 3.0.3.

3.1.2.1 Aging Management Review Results That Are 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 RCS, reactor vessel, RVIs, and steam generator components:

• ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program
Aging Management Review Results

3-211

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Closed-Cycle Cooling Water System Program

• External Surfaces Monitoring Program

• Flow-Accelerated Corrosion Program

• Nickel-Alloy Nozzles and Penetrations Program

• Nickel-Alloy Penetration Nozzles Welded to the Upper RV Closure Heads of PWRs 

Program

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program

• One-Time Inspection Program

• PWR Vessel Internals Program

• Reactor Head Closure Studs Program

• Reactor Vessel Surveillance Program

• Steam Generator Tube Integrity Program

• Water Chemistry Program

LRA Tables 3.1.2-1 through 3.1.2-4 summarize the results of AMRs for the RCS, reactor vessel, 

RVIs, and steam generator components and indicate AMRs claimed to be consistent with the 

GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine if the plant-specific components in these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR item describing how the information in the tables 

aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A–E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these items to verify consistency with the GALL Report and the validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff reviewed these items to verify consistency with the 

GALL Report and to ensure that it had reviewed and accepted the identified exceptions to the 

GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the 

site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the AMP identified by the GALL Report. This note indicates that the applicant 
Aging Management Review Results

3-212

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

items to verify consistency with the GALL Report. The staff also determined whether the AMR 

item of the different component applied to the component under review and whether the AMR 

was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the AMP identified in the GALL Report. The staff reviewed 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 exceptions 

to the GALL Report AMPs was reviewed and accepted by the staff. The staff also determined 

whether the AMP identified by the applicant was consistent with the AMP identified in the GALL 

Report and whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff reviewed these items 

to verify consistency with the GALL Report and determined whether the identified AMP would 

manage the aging effect consistent with the AMP identified in the GALL Report and whether the 

AMR was valid for the site-specific conditions.

The staff 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 3.1.1-81, addresses nickel alloy or nickel-alloy clad steam generator 

divider plates exposed to reactor coolant, which are being managed for cracking due to primary 

water stress corrosion cracking (PWSCC). The LRA credits the Water Chemistry Program to 

manage the aging effect. The GALL Report recommends GALL Report AMP XI.M2, “Water 

Chemistry,” to ensure that this aging effect is adequately managed.

In its review of components associated with item 3.1.1-81, for which the applicant cited generic 

note A, the staff noted that, subsequent to the publication date of GALL Report Revision 1 

(September 2005), foreign operating experience in steam generators with a similar design to 

that of the applicant’s steam generators found cracking due to PWSCC in the steam generator 

divider plate assemblies made of Alloy 600, even with proper primary water chemistry. 

Specifically, cracks were detected in the stub runner, very close to the tubesheet/stub runner 

weld and with depths of almost a third of the divider plate thickness. Therefore, the staff noted 

that the Water Chemistry Program, alone, may not be effective in managing cracking due to 

PWSCC in steam generator divider plate assemblies.

The staff further noted that, based on the foreign steam generator divider plate experience, the 

domestic PWR industry has issued technical studies, such as EPRI report 1014982, “Divider 

Plate Cracking in Steam Generators—Results of Phase 1: Analysis of Primary Water Stress 

Corrosion Cracking and Mechanical Fatigue in the Alloy 600 Stub Runner to Divider Plate Weld 

Material,” June 2007, to address cracking due to PWSCC for nickel-alloy divider plates and 

potential for propagation of divider plate cracks into other adjacent components.

By letter dated December 14, 2010, the staff issued RAI B.2.1.10-2 requesting that the applicant 

discuss the materials of construction for its steam generator divider plate assemblies and the 
Aging Management Review Results

3-213

susceptibility of its divider plate assemblies to cracking. The staff also asked the applicant to 

describe an inspection program to ensure that there are no cracks that could propagate into and 

challenge the integrity of other components that are part of the RCPB (e.g., tube sheet and 

channel head).

Details of the applicant’s response to RAI B.2.1.10-2 and the staff’s evaluation of that response 

are documented in SER Section 3.0.3.2.2. In its response, the applicant stated that it has 

Westinghouse Model F steam generators, and the steam generators’ divider plates and weld 

materials are Inconel (ASME-SB-168) Alloy 600/82/182. The applicant further stated that it will 

perform an inspection of each steam generator, including a one-time inspection of the divider 

plate assemblies, prior to entering the period of extended operation and that any evidence of 

divider plate cracking will be documented and evaluated under the Corrective Action Program. 

The applicant also stated that the inspection techniques used will be capable of detecting 

PWSCC in the steam generator divider plate assemblies and their associated welds. The 

applicant committed (Commitment No. 55) that, prior to entering the period of extended 

operation, it will perform inspections of each steam generator, including the one-time inspection 

of divider plate assemblies.

The staff’s evaluation of the applicant’s response to RAI B.2.1.10-2 is documented in SER 

Section 3.0.3.2.2, and Open Item OI 3.0.3.2.2-1 was identified for the applicant to provide 

additional information regarding its one-time inspection of the divider plate assembly in its 

UFSAR Supplement. Resolution for OI 3.0.3.2.2-1 will be documented in Section 3.0.3.2.2.

3.1.2.1.1 Aging Management Review Results Identified as Not Applicable

Based on its initial review, the staff identified several items of LRA Table 3.1.1 in which the 

applicant stated the items were not applicable to Seabrook. This subsection discusses the 

evaluation of those items.

LRA Table 3.1.1, items 3.1.1-1, 3.1.1-2, 3.1.1-3, 3.1.1-4, 3.1.1-11, 3.1.1-13, 3.1.1-14, 3.1.1-15, 

3.1.1-19, 3.1.1-20, 3.1.1-25, 3.1.1-26, 3.1.1-29, 3.1.1-38, 3.1.1-39, 3.1.1-40, 3.1.1-41, 3.1.1-42, 

3.1.1-43, 3.1.1-44, 3.1.1-45, 3.1.1-46, 3.1.1-47, 3.1.1-48, 3.1.1-49, 3.1.1-50, and 3.1.1-51

discuss the applicant’s determination on GALL Report AMR items that are applicable only to 

BWR-designed reactors. In the applicant AMR discussions for these items, no additional 

information is provided. The staff confirmed that these AMR items in Table 1 of the GALL 

Report, Volume 1, are only applicable to BWR-designed reactors and that Seabrook is a PWR 

with a dry ambient containment. Based on this determination, the staff finds that the applicant 

provided an acceptable basis for concluding AMR items 3.1.1-1, 3.1.1-2, 3.1.1-3, 3.1.1-4, 

3.1.1-11, 3.1.1-13, 3.1.1-14, 3.1.1-15, 3.1.1-19, 3.1.1-20, 3.1.1-25, 3.1.1-26, 3.1.1-29, 3.1.1-38, 

3.1.1-39, 3.1.1-40, 3.1.1-41, 3.1.1-42, 3.1.1-43, 3.1.1-44, 3.1.1-45, 3.1.1-46, 3.1.1-47, 3.1.1-48, 

3.1.1-49, 3.1.1-50, and 3.1.1-51 in Table 1 of the GALL Report, Volume 1, are not applicable to 

Seabrook.

LRA Table 3.1.1, items 3.1.1-12, 3.1.1-66, 3.1.1-75, and 3.1.1-84 discuss the applicant’s 

determination on GALL Report AMR items that are applicable only to once-through steam 

generators (OTSGs). The staff confirmed that these AMR items in Table 1 of the GALL Report, 

Volume 1, are only applicable to OTSGs and confirmed, by reviewing various sections of the 

LRA and UFSAR, that Seabrook has recirculating steam generators. Based on this 

determination, the staff finds that the applicant provided an acceptable basis for concluding 

AMR items 12, 35, 66, 75, and 84 in Table 1 of the GALL Report, Volume 1, are not applicable 

to Seabrook.
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LRA Table 3.1.1, item 3.1.1-35 addresses cracking due to stress corrosion cracking (SCC) and 

PWSCC in steel with stainless steel or Ni-alloy cladding primary side components and steam 

generator upper and lower heads, tubesheets, and tube-to-tubesheet welds. The staff 

confirmed, with one exception noted below, that this AMR item in Table 1 of the GALL Report, 

Volume 1, is only applicable to OTSGs, and confirmed, by reviewing various sections of the 

LRA and the UFSAR, that Seabrook has recirculating steam generators. Based on this 

determination, the staff finds that the applicant provided an acceptable basis for concluding 

AMR item 35 in Table 1 of the GALL Report, Volume 1, is not applicable to Seabrook with one 

exception—the tube-to-tubesheet welds for the steam generators. This issue is discussed and 

resolved in SER Section 3.1.2.2.16.1.

LRA Table 3.1.1, item 3.1.1-54 addresses the loss material due to pitting, crevice, and galvanic 

corrosion of copper-alloy piping, piping components, and piping elements exposed to 

closed-cycle cooling water. The applicant stated that these items are not applicable to 

Seabrook because there are no copper-alloy components exposed to closed-cycle cooling 

water in the RCS, RC, RVIs, or steam generator.

The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any 

AMR results that are applicable for this item.

LRA Table 3.1.1, item 3.1.1-56 addresses copper-alloy (with greater than 15 percent Zn) piping, 

piping components, piping elements, and heat exchanger components exposed to closed-cycle 

cooling water. The GALL Report recommends the use of GALL Report AMP XI.M33, “Selective 

Leaching of Materials,” to manage loss of material due to selective leaching for this component 

group. The applicant stated that this item is not applicable because there are no RCS 

components fabricated from copper alloy greater than 15 percent Zn and exposed to 

closed-cycle cooling water. 

The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any 

AMR results that are applicable for this item. 

LRA Table 3.1.1, item 3.1.1-57 describes the aging effect in cast austenitic stainless steel

(CASS) Class 1 piping, piping components, piping elements, and CRD pressure housings 

exposed to reactor coolant greater than 482 °F (250 °C). The applicant stated that the RCS has 

fittings made of SA-351 Grade CF8A material with service conditions greater than 482 °F. 

Additionally, the aging effect in the GALL Report for this material and environment combination 

is not applicable because the molybdenum and ferrite contents for these components are below 

the industry-accepted thresholds for loss of fracture toughness due to thermal aging 

embrittlement.

The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any 

AMR results that are applicable for this item.

LRA Table 3.1.1, item 3.1.1-60, addresses loss of material due to wear for stainless steel flux 

thimble tubes (with or without chrome plating) exposed to reactor coolant. The applicant stated 

that this item is not applicable because it uses a double-concentric thimble tube design 

fabricated from wear-resistant, seamless nickel-alloy material (Inconel 600).

The staff noted that GALL Report AMR item IV.B2-13 recommends GALL Report AMP XI.M37, 

“Flux Thimble Tube Inspection,” to manage the loss of material due to wear for stainless steel 

flux thimble tubes (with or without chrome plating). However, the GALL Report does not include 

a generic AMR item for the management of loss of material due to wear in nickel-alloy flux 
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thimble tubes. The “detection of aging effects” program element in GALL Report AMP XI.M37 

states that, for Westinghouse design flux thimble tubes, if design changes are made to use 

more wear-resistant thimble tube materials (e.g., chrome-plated stainless steel), sufficient 

inspections will be conducted at an adequate inspection frequency for the new materials. In 

addition, the staff also noted that LRA Table 3.1.2-3 includes an AMR item to manage cracking 

in the nickel-alloy flux thimble tubes. The applicant credited its PWR Vessel Internals Program 

and Water Chemistry Program to manage cracking. The applicant's PWR Vessel Internals 

Program is described in LRA Section B.2.1.7 and is based on recommendations in “Materials 

Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines 

(MRP-227, Revision 0).” The staff reviewed MRP-227, Revision 0 and noted that it does not 

include guidance for managing cracking of flux thimble tubes.

By letter dated January 5, 2011, the staff issued RAI 3.1.1-60-01 requesting that the applicant 

justify not including an applicable AMR item to manage loss of material due to wear in the 

nickel-alloy flux thimble tubes. The staff also asked the applicant to justify why a Flux Thimble 

Tube Inspection Program is not credited to manage loss of material due to wear for these 

components. 

In addition, the staff also issued RAI 3.1.1-60-02, by letter dated January 5, 2011, requesting 

that the applicant justify its crediting of the PWR Vessel Internals Program to manage cracking 

in flux thimble tubes, considering that MRP-227, Revision 0 does not contain recommendations 

for managing cracking in Westinghouse-design flux thimble tubes.

In its response to RAI 3.1.1-60-01, by letter dated February 3, 2011, the applicant stated that its 

design is unique and can accommodate both fixed and movable incore detectors housed, 

respectively, in the outer and inner tubes of the double-concentric thimble tube design. The 

applicant also stated that since its Operating Cycle 5, the movable incore detectors have not 

been used and were placed into a lay-up condition during RFO 7 (fall of 2000). The applicant 

also stated that since RFO 7, as part of a design change, “Movable Incore Detector System 

Lay-up,” the seal table tubing between the inner calibration tubing and the isolation valves has 

been removed, and the inner calibration tubing has been capped. The applicant further stated 

that, based on the unique design features of the incore detector, the aging effects managed by 

GALL Report AMP XI.M37 do not apply. The staff found the applicant’s response inadequate 

because, per the plant’s licensing basis (License Amendment No. 27 (ML011870008)), the 

applicant is allowed and has the option to place the movable incore detectors back in service, 

putting the inner tubes in a condition that is susceptible to wear.

In its response to RAI 3.1.1-60-02, by letter dated February 3, 2011, the applicant stated that 

the design change has disconnected the movable detector and has installed a qualified 

pressure-retaining cap. The applicant further stated that flux thimble tubes do not have a 

license renewal-intended RCPB function. For this reason, the applicant subsequently deleted 

the pressure boundary function for these thimble tubes from LRA Table 2.3.1-3 and the AMR 

items on cracking of these thimble tubes from the scope of LRA Table 3.1.2-3. The staff also 

found this response inadequate because it did not change the staff’s previously stated concern 

that, per the plant’s licensing basis, the applicant still has the option to place the movable incore 

detectors back in service, putting the inner tubes in a condition that is susceptible to wear as 

well as making it a pressure boundary.

By letter dated March 30, 2011, the staff issued an additional followup RAI 3.1.1-60-01/02 to 

request that the applicant further justify why an AMP is not required to manage loss of material 

due to wear of the inner tube flux thimble tubes during the period of extended operation if the 
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movable detectors were placed back into service. In addition, the staff also asked the applicant 

to justify its deletion of the AMR items associated with cracking of the flux thimble tubes from 

LRA Table 3.1.2-3.

To resolve the staff's concern that the applicant would place the movable incore detectors back 

in service, the applicant submitted its response to followup RAI 3.1.1-60-01/02, dated 

April 22, 2011, committing to implement measures prior to entering the period of extended 

operation to ensure that the movable detectors are not returned to service during the period of 

extended operation (Commitment No. 65). In addition, as part of its response, the applicant 

provided a drawing illustrating the design of the incore detector assembly. The applicant stated 

that when the incore detector assembly is inserted, the thimble housing tube (outer tube) 

provides the RCPB. The applicant also stated that the thimble calibration tube (inner tube), 

although considered an RCPB, is not in actual contact with reactor coolant. The applicant 

stated that the original fixed incore detector assemblies were not designed for the life of the 

plant, and, therefore, a replacement program was developed. For the replacement detector 

thimble assemblies, the inner tubes are solid from the seal table to below the core support plate. 

The applicant also stated that it plans to replace all 58 incore detector assemblies using the 

improved design. The applicant further stated that the plant’s technical specifications (TSs)

require performance of an incore/excore comparison every 31 effective full power days (EFPD)

when the power level is greater than 50 percent and an incore/excore calibration every 

92 EFPD when power is greater than 75 percent.

Following review of the applicant’s response to followup RAI 3.1.1-60-01/02, the staff needed 

further clarification as to where exactly the RCS pressure boundary is for the applicant’s 

replacement detector assemblies and the original capped detector assemblies. Therefore, by 

letter dated October 7, 2011, the staff issued followup RAI 3.1.1-60-02, requesting that the 

applicant verify the RCS pressure boundary for the replacement and original capped incore 

detector assemblies.

In its response to followup RAI 3.1.1-60-02, dated November 2, 2011, the applicant stated that 

for the original incore detector assembly design, the RCS pressure boundary consists of the 

reactor vessel bottom instrument penetration, the incore instrument guide tube, the high 

pressure instrument connection, the portion of the calibration tube that extends above the high 

pressure instrument connection, and the pressure-retaining cap. The applicant also stated that 

for replacement incore detector assembly design, the RCS pressure boundary consists of the 

reactor vessel bottom instrument penetration, the incore instrument guide tube, and the high 

pressure instrument connection. As part of its response, the applicant revised LRA 

Table 3.1.2-1 and added three additional AMR Items under component type “Calibration Tube,” 

on page 3.1-44 of the LRA. In addition, as part of its response, the applicant also revised the 

boundary description on page 2.3-5 of the LRA to reflect its response to followup 

RAI 3.1.1-60-02.

Based on its review, the staff finds the applicant’s response to followup RAI 3.1.1-60-02 

acceptable because the applicant has revised LRA sections related to its flux thimble tubes in 

order to include portions of the incore detector assemblies that constitute the RCS pressure 

boundary and are subject to an AMR per 10 CFR 54.21(a)(1). The staff evaluated the 

applicant’s revisions to LRA Tables 3.1.1 and 3.1.2-1 and finds that for the portion of the 

applicant’s flux thimble assemblies that constitute the RCS pressure boundary, there are no 

applicable aging effects. Specifically, the staff noted that two of the AMR items added 

correspond to NUREG-1801, Volume 2, item IV.E-1(RP-03), for which the aging effect is 
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consistent with the applicant’s disposition of Note A. For the third AMR item added, the 

applicant cited Note G and plant-specific note 1. Plant-specific note 1 states the following:

NUREG-1801 does not include air with borated water leakage for nickel-alloy 

components. Similar to V.F-13 for stainless steel, there are no aging effects for 

nickel alloy in air with borated water leakage. Additionally, the American Welding 

Society (AWS) “Welding Handbook,” (Seventh Edition, Volume 4, 1982, Library 

of Congress) identifies that nickel chromium alloy materials that are alloyed with 

iron, molybdenum, tungsten, cobalt or copper in various combinations have 

improved corrosion resistance.

The staff reviewed the associated item and confirmed that the applicant’s use of generic note G 

for this item is appropriate in that the GALL Report, Revision 1 does not include entries for 

nickel-alloy components exposed to air with borated water leakage. The staff noted that the 

GALL Report, Revision 2, dated December 2010, includes entries for nickel-alloy components

exposed to air with borated water leakage. These entries indicate that no aging effect requiring 

management is present for this material-environment combination. The staff also noted that

these AMR items in the GALL Report, Revision 2 are based in part on EPRI Report 1000975, 

“Boric Acid Corrosion Guidebook, Revision 1.” This report contains data (pages 4–43) showing 

that “[t]here was no measurable corrosion of stainless steel piping surfaces or Inconel weld 

metal joining the stainless steel and carbon steel piping sections.” The staff, therefore, finds the 

applicant’s identification of aging effects for these components to be acceptable.

The staff also finds that the design modifications, and the applicant’s commitment (Commitment 

No. 65) that the movable detectors will not be returned to service during the period of extended 

operation, eliminate the possibility of wear and RCS pressure boundary leakage through the 

prior movable detector dry path. Therefore, the staff’s concerns described in RAIs 3.1.1-60-01, 

3.1.1-60-02, and followup RAI 3.1.1-60-01/02 are resolved.

The staff noted that applicant’s current and replacement incore detector assemblies are 

sufficiently different from the standard Westinghouse designed thimble tubes for movable 

detectors, in that: 

• Failure of both the inner and outer flux thimble tubes inside of the reactor vessel, either 

due to wear or cracking, would not result in an RCS pressure boundary leakage.

• The applicant’s capping and replacement program with the solid inner tubes has 

eliminated the possibility of RCS pressure boundary leakage through the prior movable 

detector dry path.

• Wear will not initiate in the inner tubes based on the placement of the applicant’s 

commitment (Commitment No. 65).

• Periodic monitoring of the flux detectors would ensure that aging effects are detected 

prior to loss of intended function(s) as part of the applicant's technical specifications.

Therefore, the staff finds that the applicant has provided an acceptable basis that a Flux 

Thimble Tube Inspection Program is not needed to manage wear or cracking of the applicant’s 

flux thimble tubes.

LRA Table 3.1.1, item 3.1.1-76 addresses, in part, ligament cracking due to corrosion of steel 

tube support plates exposed to secondary feedwater or steam. The applicant stated that such 

ligament cracking is not applicable because its tube support plates are made of stainless steel.
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The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR 

Section 5.4 in order to verify the design of the plant’s steam generators and confirmed that the 

applicant’s steam generators (Westinghouse Model F steam generators) have tube support 

plates made of stainless steel. Therefore, the staff finds that this item is not applicable.

LRA Table 3.1.1, item 3.1.1-77 addresses the loss of material due to wastage and pitting 

corrosion in Ni-alloy steam generator tubes and sleeves exposed to phosphate chemistry in 

secondary feedwater and steam. The applicant stated that this item is not applicable because it 

does not use phosphate chemistry.

The staff reviewed the description of the applicant’s Water Chemistry Program in LRA 

Section B.2.1.28 in order to verify which water chemistry is used for the plant’s steam 

generators and confirmed that the applicant’s plant does not use a Phosphate Chemistry 

Program. Therefore, the staff finds that this item is not applicable.

LRA Table 3.1.1, item 3.1.1-78 addresses the wall thinning due to flow-accelerated corrosion in 

steel steam generator tube support lattice bars exposed to secondary feedwater and steam. 

The applicant stated that this item is not applicable because the Seabrook steam generators do 

not contain tube support lattice bars.

The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR 

Section 5.4 in order to verify the design of the plant’s steam generators and confirmed that the 

applicant’s steam generators (Westinghouse Model F steam generators) do not contain tube 

support lattice bars. Therefore, the staff finds that this item is not applicable.

LRA Table 3.1.1, item 3.1.1-79 addresses tube denting due to corrosion of steel tube support 

plates with Ni-alloy steam generator tubes exposed to secondary feedwater and steam. The 

applicant stated that this item is not applicable because the steam generator tube support plates 

are made of stainless steel.

The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR 

Section 5.4 to verify the design of the plant’s steam generators. Based on this review, the staff 

confirmed that the applicant’s plant steam generators (Westinghouse Model F steam 

generators) have tube support plates made of ferritic stainless steel with quatrefoil tube holes 

and a design resistant to corrosion, which is expected to preclude denting. Therefore, the staff 

finds that this item is not applicable.

LRA Table 3.1.1, item 3.1.1-80 addresses the loss of fracture toughness due to thermal aging 

and neutron irradiation embrittlement of CASS RVI components. The applicant stated that 

these items are not applicable to Seabrook because the facility does not have CASS 

components in the RVIs.

The staff reviewed the reactor vessel internals description in LRA Section 2.3.1.3 and UFSAR 

Section 4.5 and 5.2 in order to verify the component material of the plant’s reactor vessel 

internals and confirmed that the applicant’s reactor vessel internals do not have CASS 

components. Therefore, the staff finds that this item is not applicable.

LRA Table 3.1.1, item 3.1.1-82 addresses crancking due to stress corrosion cracking in 

stainless steel steam generator primary side divider plate exposed to reactor coolant. The 

applicant stated that this item is not applicable because the Seabrook steam generators primary 

channel divider plate is not made of stainless steel.
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The staff reviewed the steam generator description in LRA Section 2.3.1.4 and UFSAR 

Section 5.2 in order to verify the component material of the plant’s steam generators and 

confirmed that the applicant’s steam generators divider plate is not made of stainless steel but is 

made of SA-533 steel. Therefore, the staff finds that this item is not applicable.

LRA Table 3.1.1, item 3.1.1-87 addresses steel piping, piping components, and piping elements 

exposed to concrete and states that there are no aging effects, aging mechanisms, or AMPs. 

The GALL Report, Table IV, item IV.E-6 (RP-01) recommends that there is no aging effect or

aging mechanism and that no AMP is recommended for this component group exposed to this 

environment, and, therefore, the staff finds the applicant’s determination acceptable.

The staff reviewed the LRA and the UFSAR and concludes that the applicant does not have any 

AMR results that are applicable for these items.

3.1.2.1.2 Cracking Due to Stress-Corrosion Cracking and Primary Water Stress-Corrosion 

Cracking

LRA Table 3.1.1, item 3.1.1-69, addresses nickel-alloy reactor vessel primary inlet and outlet 

nozzle welds exposed to reactor coolant, which are being managed for cracking. The LRA 

credits the ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program, the Water 

Chemistry Program, and the Nickel-Alloy Nozzles and Penetrations Program to manage the 

aging effect. The GALL Report recommends GALL Report AMP XI.M1, “ASME Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD,” and GALL Report AMP XI.M2, “Water 

Chemistry,” to ensure that these aging effects are adequately managed. The associated AMR 

item cites generic note A for the ASME Code Section XI ISI Subsections IWB, IWC, and IWD 

Program and Water Chemistry Program. The associated AMR item cites generic note E for the 

Nickel-Alloy Nozzles and Penetrations Program.

For the item associated with generic note E, GALL Report AMPs XI.M1 and XI.M2 recommend 

using visual inspections, volumetric inspections, and water chemistry maintenance within the 

EPRI water chemistry guidelines to manage the aging of these items. In its review of 

components associated with item 3.1.1-69, for which the applicant cited generic note E, the staff 

noted that the ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program, the Water 

Chemistry Program, and the Nickel-Alloy Nozzles and Penetrations Program all propose to 

manage the aging of nickel-alloy reactor vessel primary inlet and outlet nozzle welds through 

the use of visual inspections, volumetric inspections, repair and replacement activities, along 

with maintaining the water chemistry within the EPRI water chemistry guidelines.

The staff’s evaluation of the applicant’s ASME Code Section XI ISI Subsections IWB, IWC, and 

IWD Program, Water Chemistry Program, and Nickel-Alloy Nozzles and Penetrations Program 

are documented in SER Sections 3.0.3.1.1, 3.0.3.1.2, and 3.0.3.3.4, respectively. In its review 

of components associated with item 3.1.1-69, the staff finds the applicant’s proposal to manage 

aging using the ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program, Water 

Chemistry Program, and Nickel-Alloy Nozzles and Penetrations Program acceptable for the 

following reasons:

• The Water Chemistry Program establishes the plant water chemistry control parameters 

and their limits to mitigate the environmental effect on the aging and identifies the 

actions required if the parameters exceed the limits.
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• The ASME Code Section XI ISI Subsection IWB, IWC, and IWD Program uses 

volumetric or visual inspection, which is adequate to detect and manage the aging effect 

consistent with the guidance in the GALL Report.

• The Nickel-Alloy Nozzles and Penetrations Program complies with the applicable NRC 

Orders and implements applicable NRC bulletins, generic letters, and staff-accepted 

industry guidelines.

• The use of these three programs is sufficient to manage the aging effects of the 

nickel-alloy reactor vessel primary inlet and outlet nozzle welds.

The staff concludes that the applicant 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).

3.1.2.1.3 Conclusion for Aging Management Reviews Consistent with the GALL Report

The staff evaluated the applicant’s claim of consistency with the GALL Report. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing the associated aging effects. On the basis of its review, the staff 

concludes that the AMR results that the applicant claimed to be consistent with the GALL 

Report are consistent with the GALL Report AMRs. Therefore, the staff concludes that the 

applicant demonstrated that the aging effects for these components will be adequately managed 

so that their intended functions will be maintained consistent with the CLB for the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2 Aging Management Review Results That Are Consistent with the GALL Report

for Which Further Evaluation is Recommended

LRA Section 3.1.2.2 provides further evaluation of aging management, as recommended by the 

GALL Report for the RCS components. The applicant provided information concerning how it 

will manage the following aging effects:

• cumulative fatigue damage

• loss of material due to general, pitting, and crevice corrosion

• loss of fracture toughness due to neutron irradiation embrittlement

• cracking due to SCC and IGSCC

• crack growth due to cyclic loading

• loss of fracture toughness due to neutron irradiation embrittlement and void swelling

• cracking due to SCC

• cracking due to cyclic loading

• loss of preload due to stress relaxation

• loss of material due to erosion

• cracking due to flow-induced vibration

• cracking due to SCC and irradiation-assisted stress corrosion cracking (IASCC)

• cracking due to PWSCC

• wall thinning due to flow-accelerated corrosion

• changes in dimensions due to void swelling

• cracking due to SCC and PWSCC

• cracking due to SCC, PWSCC, and IASCC
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For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the GALL Report and for which the report recommends further evaluation, the 

staff audited and reviewed the applicant’s evaluation. The staff determined whether the 

applicant adequately addressed the issues for which further evaluation is recommended. 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 describes the applicant’s AMR for managing cumulative fatigue damage 

in ASME Code Class 1 components and other non-Class 1 components that were analyzed to 

ASME Code Section III, Classes 1, fatigue evaluations. The applicant stated that fatigue is a 

TLAA as defined in 10 CFR 54.3, and these TLAAs are evaluated in accordance with 

10 CFR 54.21(c)(1). Further evaluation of these TLAAs is discussed separately in LRA 

Section 4.3.

The applicant identified that the following AMRs in LRA Table 3.1.1 are applicable and stated 

the following for each applicable item:

• Item 3.1.1-5—The applicant stated that the TLAAs for stainless steel and nickel-alloy 

RVIs components were evaluated in accordance with 10 CFR 54.21(c).

• Item 3.1.1-6—The applicant stated that the TLAAs for nickel-alloy tubes and sleeves in a 

reactor coolant and secondary feedwater and steam environment were evaluated in 

accordance with 10 CFR 54.21(c).

• Item 3.1.1-7—The applicant stated that steel and stainless steel RCPB closure bolting, 

head closure studs, support skirts and attachment welds, pressurizer relief tank 

components, steam generator components, piping, and components external surfaces 

and bolting were evaluated in accordance with 10 CFR 54.21(c).

• Item 3.1.1-8—The applicant stated that steel; stainless steel; and nickel-alloy RCPB

piping, piping components, piping elements; flanges; nozzles and safe ends; pressurizer 

vessel shell heads and welds; heater sheaths and sleeves; penetrations; and thermal 

sleeves were evaluated in accordance with 10 CFR 54.21(c).

• Item 3.1.1-9—The applicant stated that steel; stainless steel; steel with nickel alloy or 

stainless steel cladding; nickel-alloy reactor vessel components such as flanges; 

nozzles; penetrations; pressure housings; safe ends; thermal sleeves; and vessel shells, 

heads and welds were evaluated in accordance with 10 CFR 54.21(c).

• Item 3.1.1-10—The applicant stated that steel; stainless steel; steel with nickel alloy or 

stainless steel cladding; nickel-alloy steam generator components such as flanges; 

penetrations; nozzles; safe ends, and vessel lower heads and welds were evaluated in 

accordance with 10 CFR 54.21(c).

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 these 

TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements in 

10 CFR 54.21(c) and in accordance with SRP-LR Section 4.3, “Metal Fatigue Analysis.” The 

staff reviewed the applicant’s AMR items and finds that the AMR results are consistent with the 

recommendations of the GALL Report and SRP-LR except for the area identified below.
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In its review of the components associated with item 3.1.1-8, the staff noted that LRA 

Tables 3.2.2-3, 3.2.2-4, and 3.3.2-3 included several AMR items that referenced item 3.1.1-8. 

The staff noted that LRA Section 4.3.7 indicated that these systems were designed in 

accordance with ASME Code Section III Class 2 and Class 3 requirements. By letter dated 

January 21, 2010, the staff issued RAI 3.3.2.2.1-2 asking the applicant to clarify which portions 

of these systems are represented by item 3.1.1-8 in LRA Tables 3.2.2-3, 3.3.2-4, and 3.3.2-3. 

The staff’s review of the applicant’s response to RAI 3.3.2.2.1-2 is documented in SER 

Sections 3.2.2.2.1 and 3.3.2.2.1.

Based on the staff’s review, the staff concludes that the applicant 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 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAAs 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 criteria in SRP-LR Section 3.1.2.2.2. LRA 

Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion for 

certain portions (for PWRs) of the steam generators.

(1) Table 3.1.1, item 3.1.1-12, is only applicable to Babcock & Wilcox Co. OTSGs. 

Therefore, it is not applicable to Seabrook.

(2) Table 3.1.1, item 3.1.1-13, is applicable to BWRs only, as discussed in SER 

Section 3.1.2.1.1 above.

(3) Table 3.1.1, items 3.1.1-14 and 3.1.1-15, are applicable to BWRs only, as discussed in 

SER Section 3.1.2.1.1 above.

(4) LRA Section 3.1.2.2.2.4, is associated with LRA Table 3.1.1, item 3.1.1-16, and 

addresses steel steam generator components (feedwater and main steam nozzles, 

lower shell, secondary handholes, secondary manways, shell penetrations, top head, 

transition cone, and upper shell) exposed to secondary feedwater and steam, which are 

being managed for loss of material due to general, pitting, and crevice corrosion by the 

Water Chemistry Program and the ASME Code Section XI ISI, Subsections IWB, IWC, 

and IWD Program. The criteria in SRP-LR Section 3.1.2.2.2, item 4, states that loss of 

material due to general, pitting and crevice corrosion could occur for steel PWR steam 

generator upper and lower shell and transition cone exposed to secondary feedwater 

and steam. The SRP-LR also states that the existing program relies on control of 

chemistry to mitigate corrosion and ISI to detect loss of material. The SRP-LR further 

states that, in accordance with NRC IN 90-04, “Cracking of the Upper Shell-to-Transition 

Cone Girth Welds in Steam Generators,” the program may not be sufficient to detect 

pitting and crevice corrosion if general and pitting corrosion of the shell is known to exist,

and augmented inspections may be needed to manage the aging effect. The SRP-LR 

clarifies that this special concern about capability of standard ASME Code Section XI

inspections to detect pitting and crevice corrosion is limited to Westinghouse Model 44 

and 51 steam generators, where a high stress region exists at the shell to transition cone 

weld.
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The staff noted that the discussion in LRA Table 3.1.1, item 3.1.1-16, states that the 

steam generators are Westinghouse Model F and that additional inspection procedures 

(beyond those specified in ASME Code Section XI) are not required. The staff 

confirmed that the applicant’s UFSAR Section 5.4.2.2 states that the steam generators 

are Model F and the NRC IN 90-04 recommendation regarding augmented inspections 

is limited to only Westinghouse steam generator Models 44 and 51. Because the 

applicant’s steam generators are not Westinghouse Model 44 or 51, the staff finds 

acceptable the applicant’s determination that augmented inspections are not needed.

The staff noted that in the GALL Report, AMR item IV.D1-12(R-34) is the only 

component related to SRP-LR Table 3.1.1, item 3.1.1-16. Specifically, AMR 

item IV.D1-12(R-34) is the steel steam generator upper and lower shell and transition 

cone exposed to secondary feedwater and steam. However, the applicant extended the 

AMR results for this item to include other secondary steam generator components made 

of the same material and exposed to the same environment. The staff also noted that 

ASME Code Section XI, Examination Category C-A, item C1.10, is applicable for the 

steam generator upper and lower shell and transition cone and requires volumetric 

examination of shell circumferential welds at locations of gross structural discontinuity, 

specifically at the cylindrical shell to conical shell junctions. It was not clear to the staff if 

the applicant proposed this solely to rely on the code-required volumetric inspection, 

item C1.10, or whether it also intended to use visual examinations to confirm 

effectiveness of secondary water chemistry to mitigate loss of material due to general, 

pitting, and crevice corrosion for these components. By letter dated January 5, 2011, 

the staff issued RAI 3.1.2.2.2.4-01 asking the applicant to describe the examinations that 

will be used for this AMR item.

In its response dated February 3, 2011, the applicant stated that the Steam Generator 

Tube Integrity Program includes visual inspections for degradation of secondary 

handholds, secondary manways, shell penetrations, steam generator shell internal 

surface, transition cone internal surface, top head, and shell weld internal surfaces. The 

applicant further stated that the design of the steam generators prevents internal access 

to the feedwater and main steam nozzles for visual inspection and that, for these 

components, only volumetric examinations will be performed.

The applicant revised LRA Table 3.1.1, item 3.1.1-16, to state that both the ASME Code

Section XI ISI, Subsections IWB, IWC, and IWD Program and the Steam Generator 

Tube Integrity Program will be used to verify the effectiveness of the Water Chemistry 

Program to manage loss of material due to general, pitting, and crevice corrosion in the 

steel components of the steam generators exposed to secondary feedwater or steam. In 

LRA Table 3.1.2-4, the applicant revised many AMR lines for steel components that refer 

to LRA Table 3.1.1, item 3.1.1-16. For three AMR lines applicable to the steel steam 

generator lower shell, transition cone, and upper shell, respectively, the AMP was 

revised to credit the Steam Generator Tube Integrity Program in addition to the ASME 

Code Section XI ISI, Subsections IWB, IWC, and IWD Program and the Water 

Chemistry Program for management of loss of material. For four AMR lines applicable 

to the steel steam generator secondary handholes, secondary manways, shell 

penetrations, and top head, respectively, the AMP was revised to credit the Steam 

Generator Tube Integrity Program and the Water Chemistry Program for management of 

loss of material. The staff noted that, for components where ASME Code Section XI

specifies ISIs, the applicant is crediting the required ASME Code Section XI volumetric 

inspections and is supplementing those inspections with additional Steam Generator 
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Tube Integrity Program visual inspections. Additionally, for components where ASME 

Code Section XI does not specify inspections, the applicant is crediting Steam Generator 

Tube Integrity Program visual inspections for verification of Water Chemistry Program 

effectiveness.

The staff’s evaluations of the applicant’s ASME Code Section XI ISI, Subsections IWB, 

IWC, and IWD Program, Water Chemistry Program, and Steam Generator Tube Integrity 

Program are documented in SER Sections 3.0.3.1.1, 3.0.3.1.2, and 3.0.3.2.2, 

respectively. The staff noted that the applicant’s Water Chemistry Program follows EPRI 

secondary water chemistry guidelines, which is consistent with recommendations in the 

GALL Report, and provides monitoring and control of secondary water chemistry to 

mitigate the potential for general, pitting, and crevice corrosion of steel secondary-side 

steam generator components. The staff also noted that the applicant’s ASME Code

Section XI ISI, Subsections IWB, IWC and IWD Program is consistent with 

recommendations in the GALL Report and provides the Code-required volumetric 

inspections and visual inspections of the steel secondary-side steam generator 

components. In addition, the staff noted that the applicant’s Steam Generator Tube 

Integrity Program is based on NEI 97-02, Revision 2, “Steam Generator Program 

Guidelines,” which is consistent with staff recommendations documented in the GALL 

Report. This program includes visual inspections that are capable of detecting loss of 

material due to general, pitting and crevice corrosion in steel secondary-side steam 

generator components.

The staff finds that the applicant met the further evaluation criteria, and the applicant’s 

proposal to manage aging using the Water Chemistry Program, the ASME Code

Section XI ISI, Subsections IWB, IWC, and IWD Program, and the Steam Generator 

Tube Integrity Program is acceptable for the following reasons:

• The Water Chemistry Program provides mitigation of the aging effect for 

steel secondary-side steam generator exposed to feedwater and steam.

• The ASME Code Section XI ISI, Subsections IWB, IWC, and IWD 

Program and the Steam Generator Tube Integrity Program provide 

examination of the components to confirm effectiveness of the Water 

Chemistry Program to mitigate the aging effects.

• The combination of programs proposed by the applicant is consistent with 

the recommendations in the GALL Report for aging management of these 

components.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.2, item 4, criteria. For those items that apply to LRA 

Section 3.1.2.2.2.4, the staff determined 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 be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

(1) LRA Section 3.1.2.2.3 is associated with LRA Table 3.1.1, item 3.1.1-17, and states that 

TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1) and that the evaluation of 
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this TLAA is addressed in Section 4.2. This is consistent with SRP-LR Section 3.1.2.2.3,

item 1, and is, therefore, acceptable.

(2) LRA Section 3.1.2.2.3 is associated with LRA Table 3.1.1, item 3.1.1-18, and addresses 

steel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, and

welds exposed to reactor coolant and neutron flux, which are being managed for loss of 

fracture toughness due to neutron irradiation embrittlement by Seabrook AMP B.2.1.19, 

“Reactor Vessel Surveillance.” The criteria in SRP-LR Section 3.1.2.2.3, item 2, states 

that loss of fracture toughness due to neutron irradiation embrittlement could occur for 

steel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, and 

welds exposed to reactor coolant and neutron flux. The SRP-LR also states that the 

applicant should submit its proposed withdrawal schedule for approval prior to 

implementation. Untested capsules placed in storage must be maintained for future 

insertion. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the required information is included in the applicant’s Reactor Vessel 

Surveillance Program.

The staff’s evaluation of the applicant’s Reactor Vessel Surveillance Program (LRA 

Section B.2.1.19) is documented in SER Section 3.0.3.2.11. The staff noted that the 

applicant did submit a Surveillance Program in 1983, and the LRA does include a 

commitment to follow the requirements of 10 CFR Part 50, Appendix H, and ASTM 

E185-82 protocol for the capsule withdrawal schedule (Commitment No. 20). In 

addition, the staff noted that Section B.2.1.19 includes a commitment (Commitment 

No. 21) to maintain untested capsules in storage for future insertion, if needed. The staff 

also noted that Table 3.1.1, item 3.1.1-18, is aligned with the applicant’s commitments,

as described in LRA Section B.2.1.19

Based on the acceptance of the Reactor Vessel Surveillance Program discussed in 

Section 3.0.3.2.11 and the commitments listed in LRA Appendix A, Section A.3, the staff 

concludes that the applicant’s programs meet SRP-LR Section 3.1.2.2.3, item 2, criteria. 

For those items that apply to LRA Section 3.1.2.2.3.2, the staff concludes 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 functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.2.4 Cracking Due to Stress-Corrosion Cracking and Intergranular Stress-Corrosion 

Cracking

Table 3.1.1, items 3.1.1-19 and 3.1.1-20 are not applicable to Seabrook, as they are applicable 

to BWRs only. See SER Section 3.1.2.1.1 above.

3.1.2.2.5 Crack Growth Due to Cyclic Loading

LRA Section 3.1.2.2.5 states that item 3.1.1-21 is not applicable because the stainless steel 

cladding is not fabricated with a high-heat-input welding process. SRP-LR Section 3.1.2.2.5 

states that cyclic crack growth could occur if the cladding was welded to the RPV SA-508, 

Class 2 forgings using a high-heat-input welding process. After review, the staff concluded that 

item 3.1.1-21, crack growth due to cyclic loading, is not applicable because the cladding 

procedure used for the applicant’s RV was qualified to ensure underclad cracking and the 

subsequent crack growth due to cyclic loading would not occur. The staff noted that the 

applicant used a special procedure qualification for its welding of the cladding to those RV 
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components that were fabricated from SA-508, Class 2 low alloy steel forgings. The staff also 

noted that the procedure qualification included a special evaluation to assure freedom from 

underclad cracking in these cladding-to-forging welds. Specifically, the staff verified that 

UFSAR Sections 5.2.3 and 5.3.1.4 indicate that the applicant applied the NRC’s recommended 

weld control process in Regulatory Guide (RG) 1.43, “Control of Stainless Steel Weld Cladding 

of Low Alloy Steel Components,” as the process for controlling the welding fabrication of the 

cladding to those RV components that were fabricated from SA 508, Class 2 forging materials. 

The staff also verified that UFSAR Section 1.8 identifies that the applicant’s procedural 

qualification was performed both in accordance with the weld fabrication requirements in 

Sections III and XI of the ASME Code and in accordance with supplemental qualification criteria 

(i.e., Position C.2) of RG 1.43, which provides the staff’s recommended welding qualification 

process controls for avoiding underclad cracking in these cladding-to-forging welds. The staff 

determined that the RPV underclad cracking and the subsequent crack growth due to cyclic 

loading would not occur and, therefore, item 3.1.1-21 is not applicable. The staff evaluation of 

the absence of a TLAA for reactor vessel underclad cracking is documented in SER 

Section 4.7.1.2.

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void 

Swelling

The staff reviewed LRA Section 3.1.2.2.6 and Table 3.1.1, Item 3.1.1-22, against the criteria in 

SRP-LR 3.1.2.2.6, which recommends no further AMR if the applicant provides a commitment in 

the UFSAR supplement to do the following: 

• participate in the industry programs for investigating and managing aging effects on 

reactor internals

• evaluate and implement the results of the industry programs as applicable to the reactor 

internals

• upon completion of these programs, but not less than 24 months before entering the 

period of extended operation, submit an inspection plan for reactor internals to the NRC 

for review and approval

The staff noted that the applicant’s commitment (Commitment No. 1) in LRA Appendix A, 

Section A3, is consistent with the commitment described in SRP-LR 3.1.2.2.6.

The staff also noted that all of the AMR results lines that refer to Table 3.1.1, Item 3.1.1-22,

align with the applicant’s commitment as described in LRA Appendix A, Section A3. The staff 

finds the applicant’s proposal acceptable because the discussion of the AMR item refers to the 

applicant’s AMP (PWR Reactor Vessel Internals Program), which includes the appropriate 

commitment in the UFSAR supplement.

Based on the staff’s evaluation, the staff concludes that the applicant’s program meets the 

SRP-LR Section 3.1.2.2.6 criteria. For those AMR items that apply to LRA Section 3.1.2.2.6, 

the staff concludes that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).
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3.1.2.2.7 Cracking Due to Stress-Corrosion Cracking

(1) LRA Section 3.1.2.2.7.1 is associated with LRA Table 3.1.1, item 3.1.1-23, and 

addresses stainless steel reactor vessel flange leak detection lines exposed to reactor

coolant, which are being managed for cracking due to SCC by the ASME Code

Section XI ISI, Subsections IWB, IWC, and IWD Program. SRP-LR Section 3.1.2.2.7, 

item 1, states that cracking due to SCC could occur for stainless steel exposed to 

reactor coolant. The SRP-LR also states that a plant-specific AMP should be evaluated 

to ensure that this aging effect is adequately managed. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that Seabrook will implement VT-2 

examinations to identify and evaluate the degradation of stainless steel reactor vessel 

flange leak detection lines to ensure that there is no loss of intended function.

The staff’s evaluation of the applicant’s ASME Code Section XI ISI, Subsections IWB, 

IWC, and IWD Program is documented in SER Section 3.0.3.1.1. The staff noted that 

SCC will start at the surface and could be found with visual inspections as long as the 

critical flaw size is relatively large. The staff also noted that the stainless steel used for 

these components is extremely tough, such that the critical flaw size is normally large 

and easy to find with VT-2 inspections. In its review of components associated with 

item 3.1.1-23, the staff finds that the applicant met the further evaluation criteria; the 

applicant’s proposal to manage aging using the ASME Code Section XI ISI, 

Subsections IWB, IWC, and IWD Program is acceptable because the proposed VT-2 

inspections should find any cracking due to SCC.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.7, item 1, criteria. For those items that apply to LRA 

Section 3.1.2.2.7.1, the staff determined that the LRA is consistent with the GALL 

Report. The staff also finds that the applicant demonstrated that the effects of aging will 

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

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) LRA Section 3.1.2.2.7.2 is associated with LRA Table 3.1.1, item 3.1.1-24, and 

addresses Class 1 PWR CASS piping, piping components, and piping elements 

exposed to reactor coolant, which are being managed for cracking due to SCC by the 

Water Chemistry Program and the ASME Code Section XI ISI, Subsections IWB, IWC, 

and IWD Program. The criteria in SRP-LR Section 3.1.2.2.7 item 2, states that the 

cracking due to SCC could occur for Class 1 PWR CASS piping, piping components, 

and piping elements exposed to reactor coolant. SRP-LR Section 3.1.2.2.7 also states 

that the existing program relies on the control of water chemistry to mitigate SCC that 

could occur for CASS components that do not meet the NUREG–0313 guidelines with 

regard to ferrite and carbon contents. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that the ASME Code Section XI ISI, Subsections IWB, 

IWC, and IWD Program will be used to verify the effectiveness of the Water Chemistry 

Program.

In its review of components associated with LRA Table 3.1.1, item 3.1.1-24, the staff 

noted that the applicant related the AMR items to GALL Report, item IV.C2-3. The staff 

also noted that, for the CASS components that do not meet NUREG-0313 guidelines on 

material susceptibility, GALL AMR item IV.C2-3 recommends a plant-specific program to 

include adequate inspection methods and a flaw evaluation methodology for the CASS 

components that are susceptible to thermal aging embrittlement. LRA 
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Section 3.1.2.2.7.2 states that the ASME Code Section XI ISI, Subsections IWB, IWC 

and IWD Program rely on VT-2 examinations to identify and evaluate cracking of the 

CASS components. The staff noted that a VT-2 examination is used to detect leakage 

from pressure-retaining components, whereas a volumetric examination can detect a 

crack before there is leakage. The staff also noted that a surface examination or VT-1 

examination can provide better resolution for detecting cracking than a VT-2 

examination.

By letter dated January 5, 2011, the staff issued RAI 3.1.2.1-1 requesting that the 

applicant clarify whether a VT-2 examination is the only method used to detect this aging 

effect in CASS Class 1 piping, piping elements, and components. The staff also 

requested that, if another examination method such as volumetric, surface or VT-1 

examination is used, the applicant should clarify what the examination method is and 

justify why the aging management method is adequate to detect and manage the aging 

effect. The staff further requested that, if the VT-2 examination is the only examination 

method used, the applicant should justify why a VT-2 examination without volumetric, 

surface, and VT-1 examinations is adequate to detect and manage cracking.

In its response dated February 3, 2011, the applicant stated that, as shown in LRA 

Table 3.1.1-23, the ASME Code Section XI ISI, Subsections IWB, IWC and IWD 

Program is credited to manage SCC of the Class 1 CASS piping, piping components,

and piping elements. The applicant also stated that the VT-2 examination method was 

inadvertently identified as the only inspection method and that the ASME Code

Section XI ISI, Subsections IWB, IWC and IWD Program is implemented in accordance 

with the requirements of 10 CFR 50.55a, with specified limitations, modifications, NRC 

approved alternatives, and applicable provisions of ASME Code Section XI. The 

applicant further indicated that it is revising LRA Section 3.1.2.2.7.2 accordingly to clarify 

that VT-2 examination is not the only examination credited to manage this aging effect. 

In addition, the applicant indicated that, during the period of extended operation, should 

the ISI Program require that volumetric examinations be performed per ASME Code

Section XI, Table IWB-2500-1, Examination Category B-J, on the Class 1 pipe welds, 

then an ultrasonic examination method, qualified under ASME Code Section XI, 

Appendix VIII, will be used or an NRC-approved alternative (such as enhanced visual 

examination) will be implemented.

Based on its review, the staff finds the applicant’s response to RAI 3.1.2.1-1 acceptable 

because the applicant clarified the following:

• The ASME Code Section XI ISI, Subsections IWB, IWC and IWD 

Program is implemented in accordance with the requirements of 

10 CFR 50.55a, which is adequate to detect SCC of the components.

• A VT-2 examination is not the only inspection method used to manage 

this aging effect.

• If volumetric examinations are required per the ASME Code, an ultrasonic 

examination method qualified under ASME Code Section XI, 

Appendix VIII, will be used or an NRC-approved alternative (such as 

enhanced visual examination) will be implemented, which is adequate to 

detect cracking due to SCC of the components.

The staff’s concerns described in RAI 3.1.2.1-1 are resolved.
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The staff’s evaluations of the applicant’s Water Chemistry Program and ASME Code

Section XI ISI, Subsections IWB, IWC and IWD Program are documented in SER 

Sections 3.0.3.1.2 and 3.0.3.1.1, respectively. The applicant stated that the Water 

Chemistry Program controls water chemistry parameters by periodic monitoring and 

control of detrimental contaminants below the established limits that are known to cause 

material degradation. This program is based on EPRI guidelines, and periodic sampling 

is performed and analyzed for levels of chlorides, fluorides, sulfates, lithium, and 

dissolved oxygen and hydrogen so that cracking due to SCC in the CASS components is 

mitigated. The applicant further stated that the ASME Code Section XI ISI, 

Subsections IWB, IWC and IWD Program includes visual, surface, and volumetric 

inspections to detect and manage cracking due to SCC. The applicant stated that 

indications or relevant conditions are evaluated in accordance with IWB-3000 for Class 1 

components. On the basis of its review, the staff finds that the applicant met the further 

evaluation criteria. Additionally, the applicant’s proposal to manage aging using the 

Water Chemistry Program and ASME Code Section XI ISI, Subsections IWB, IWC and 

IWD Program is acceptable because the Water Chemistry Program monitors and 

controls water chemistry to mitigate cracking due to SCC, and the ASME Code

Section XI ISI, Subsections IWB, IWC and IWD Program will perform inspections using 

visual, surface, and volumetric examinations in accordance with the requirements of the 

ASME Code Section XI, as modified and limited in 10 CFR 50.55a, which is adequate to 

verify the effectiveness of the Water Chemistry Program and manage cracking due to 

SCC.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.7 criteria. For those items that apply to LRA 

Section 3.1.2.2.7.2, the staff determined that the LRA is consistent with the GALL 

Report. The staff also finds that the applicant 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).

3.1.2.2.8 Cracking Due to Cyclic Loading

Table 3.1.1, items 3.1.1-25 and 3.1.1-26, are applicable to BWRs only, as discussed in SER 

Section 3.1.2.1.1 above.

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9. LRA 

Section 3.1.2.2.9 addresses loss of preload due to stress relaxation that could occur in stainless 

steel and Ni-alloy PWR RVIs screws, bolts, and hold down springs exposed to reactor coolant 

as an aging effect that the applicant will manage, consistent with the SRP-LR, by the ASME 

Code Section XI ISI, Subsections IWB, IWC, and IWD Program. This AMP is enhanced with 

Commitment No. 1, which is also identified in the UFSAR supplement description of the 

program.

The staff reviewed LRA Section 3.1.2.2.9 and Table 3.1.1, item 3.1.1-27, against criteria in 

SRP-LR 3.1.2.2.9. LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation 

that could occur in stainless steel and Ni-alloy PWR RVIs screws, bolts, and hold down springs 

exposed to reactor coolant. The SRP-LR recommends no further AMR if the applicant provides 

a commitment in the UFSAR supplement to do the following: 
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• participate in the industry programs for investigating and managing aging effects on 

reactor internals

• evaluate and implement the results of the industry programs as applicable to the reactor 

internals

• upon completion of these programs, but not less than 24 months before entering the 

period of extended operation, submit an inspection plan for reactor internals to the NRC 

for review and approval

The staff noted that the applicant’s commitment (Commitment No. 1) in LRA Appendix A, 

Section A3, is consistent with the commitment described in SRP-LR 3.1.2.2.9.

The staff also noted that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1-27,

align with the applicant’s commitment as described in LRA Appendix A, Section A3. The staff 

finds the applicant’s proposal acceptable because the discussion of the AMR item refers to the 

applicant’s AMP (PWR Vessel Internals Program), which includes the appropriate commitment 

in the UFSAR supplement.

Based on the staff’s evaluation, the staff concludes that the applicant’s program meets the 

SRP-LR Section 3.1.2.2.9 criteria. For those AMR items that apply to LRA Section 3.1.2.2.9, 

the staff concludes that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.1.2.2.10 Loss of Material Due to Erosion

LRA Section 3.1.2.2.10, associated with LRA Table 3.1.1, item 3.1.1-28, addresses loss of 

material due to erosion in steel steam generator impingement plates and supports exposed to 

secondary feedwater. The applicant stated that this item is not applicable because steel steam 

generator feedwater impingement plates and supports do not exist in its steam generators. The 

staff reviewed UFSAR Section 5.4.2 and confirmed that the design of the applicant’s steam 

generators do not contain steel steam generator feedwater impingement plates and supports; 

therefore, it finds the applicant’s claim acceptable.

3.1.2.2.11 Cracking Due to Flow-Induced Vibration

Table 3.1.1, item 3.1.1-29, is applicable to BWRs only, as discussed in SER Section 3.1.2.1.1 

above.

3.1.2.2.12 Cracking Due to Stress-Corrosion Cracking and Irradiation-Assisted 

Stress-Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.12 and Table 3.1.1, item 3.1.1-30, against criteria in 

SRP-LR 3.1.2.2.12. LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC that 

may occur in stainless steel PWR reactor internals exposed to reactor coolant. This LRA 

section states that the existing program relies on control of water chemistry to mitigate cracking 

due to SCC and IASCC. SRP-LR 3.1.2.2.12 recommends no further AMR if the applicant 

provides a commitment in the UFSAR supplement to do the following: 

• participate in the industry programs for investigating and managing aging effects on 

reactor internals
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• evaluate and implement the results of the industry programs as applicable to the reactor 

internals

• upon completion of these programs, but not less than 24 months before entering the 

period of extended operation, submit an inspection plan for reactor internals to the NRC 

for review and approval

The staff noted that the applicant’s commitment (Commitment No. 1) in LRA Appendix A, 

Section A3, is consistent with the commitment described in SRP-LR 3.1.2.2.12.

The staff also noted that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1-30,

align with the applicant’s commitment, as described in LRA Appendix A, Section A3. The staff

finds the applicant’s proposal acceptable because the discussion of the AMR item refers to the 

applicant’s AMP (PWR Vessel Internals Program), which includes the appropriate commitment 

in the UFSAR supplement.

In LRA Section 3.1.2.2.12, the applicant stated that, for managing the aging of cracking due to 

SCC and IASCC of stainless steel reactor internals components exposed to reactor coolant, the 

facility’s Water Chemistry Program is augmented by the commitment described above. When 

augmented by the commitment above, the staff finds the facility’s Water Chemistry Program 

acceptable for managing SCC and IASCC of stainless steel reactor internals components 

exposed to reactor coolant because the Water Chemistry Program will control contaminants that 

can contribute to SCC of stainless steel.

The staff’s evaluation of the applicant’s Water Chemistry Program is documented in SER 

Section 3.0.3.1.2. In its review of components associated with item 3.1.1-30, the staff finds the 

applicant’s proposal to manage aging using the Water Chemistry Program acceptable because 

use of the Water Chemistry Program to manage cracking is consistent with GALL when 

combined with the commitment described above.

Based on the programs identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.12 criteria. For those items that apply to LRA Section 3.1.2.2.12, the 

staff determined that the LRA is consistent with the GALL Report. The staff also finds that the 

applicant 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).

3.1.2.2.13 Cracking Due to Primary Water Stress-Corrosion Cracking

LRA Section 3.1.2.2.13 and LRA Table 3.1.1, item 3.1.1-31, address PWR components made of 

nickel alloy and steel with nickel-alloy cladding, including RCPB components and penetrations 

inside the RCS, such as pressurizer heater sheaths and sleeves, nozzles, and other internal 

components, with the exception of reactor vessel upper head nozzles and penetrations exposed 

to reactor coolant. These components are being managed for cracking due to PWSCC by the 

ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program, the Nickel-Alloy Nozzles 

and Penetrations Program, and the Water Chemistry Program. SRP-LR Section 3.1.2.2.13 

states that cracking due to PWSCC could occur for PWR components made of nickel alloy and 

steel with nickel-alloy cladding exposed to reactor coolant. The SRP-LR also states that, with 

the exception of reactor vessel upper head nozzles and penetrations, the GALL Report 

recommends ASME Code Section XI ISI (for Class 1 components) and control of water 

chemistry. For nickel-alloy components, no further AMR is necessary if the applicant complies 

with applicable NRC Orders and provides a commitment in the UFSAR supplement to 
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implement applicable bulletins, generic letters, and staff-accepted industry guidelines. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that it will implement 

those programs mentioned above to manage the aging effects of cracking due to PWSCC in 

nickel-alloy components in the RCS, in the nickel-alloy bottom instrument tube and core support 

pads/core guide lugs in the reactor vessel, and the nickel-alloy steam generator primary nozzle 

weld in the steam generator.

The staff’s evaluations of the applicant’s three AMPs, ASME Code Section XI ISI, 

Subsections IWB, IWC, and IWD Program, Water Chemistry Program, and Nickel-Alloy Nozzles 

and Penetrations Program, are documented in SER sections 3.0.3.1.1, 3.0.3.3.4, and 3.0.3.1.2, 

respectively. In its review of these AMPs, the staff found them to be acceptable for managing 

aging. Additionally, the staff noted that the Nickel-Alloy Nozzles and Penetrations Program 

states that the applicant will comply with applicable NRC Orders. Additionally, Commitment 

No. 59, which is associated with the Nickel-Alloy Nozzles and Penetration Program (submitted 

by letter dated January 13, 2011, and contained in LRA Section A.2.2.3), commits to 

implementing bulletins, generic letters, and staff-accepted industry guidelines.

In its review of components associated with Table 3.1.1, item 3.1.1-31, the staff finds the 

applicant’s proposal to manage aging using the ASME Code Section XI ISI Program, the Water 

Chemistry Program, and the Nickel-Alloy Nozzles and Penetrations Program, acceptable. The 

components under consideration are consistent with those in the GALL Report, and the AMPs

proposed by the applicant are consistent with the GALL Report and contain the commitment 

recommended in SRP-LR Section 3.1.2.2.13.

Based on its review, the staff concludes that the AMP proposed by the applicant for those items 

which are currently under consideration meets the criteria contained in SRP-LR 

Section 3.1.2.2.13. Additionally, the staff concludes that the effects of aging will be adequately 

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

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion

LRA Section 3.1.2.2.14 is associated with LRA Table 3.1.1, item 3.1.1-32, and addresses the 

steel steam generator feedwater inlet ring and supports exposed to secondary feedwater and 

steam, which are being managed for wall thinning due to flow-accelerated corrosion by the 

Steam Generator Tube Integrity Program. The criteria in SRP-LR Section 3.1.2.2.14 states that 

wall thinning due to flow-accelerated corrosion could occur for steel feedwater inlet rings and 

supports. The SRP-LR and the GALL Report also state that NRC IN 91-19, “Steam Generator 

Feedwater Distribution Piping Damage,” cites evidence of flow-accelerated corrosion in steam 

generators and recommends that a plant-specific AMP be evaluated because existing programs 

may not be capable of mitigating or detecting wall thinning due to flow-accelerated corrosion. 

The applicant addressed the further evaluation criteria of the SRP-LR by stating that IN 91-19 

addresses wall thinning due to flow-accelerated corrosion in Combustion Engineering-designed 

steam generator feedwater inlet rings and supports, and it is not directly applicable to Seabrook, 

which uses Westinghouse Model F steam generators. The applicant further stated that it will 

manage wall thinning due to flow-accelerated corrosion in the steel steam generator feedwater 

inlet rings and supports by using the Steam Generator Tube Integrity Program. The Steam 

Generator Tube Integrity Program implements many industry guidelines and incorporates a 

balance of prevention, inspection, evaluation, repair, and leakage monitoring measures to 

assure that existing environmental conditions are not causing wall thinning that could result in a 

loss of component intended function.
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The staff’s evaluation of the applicant’s Steam Generator Tube Integrity Program is documented 

in SER Section 3.0.3.2.2. In its review of components associated with item 3.1.1-32 and the 

Steam Generator Tube Integrity Program described in LRA Section B.2.1.10, the staff noted that 

the applicant stated that the program includes management of wall thinning from flowaccelerated corrosion of steam generator components. However, the applicant does not 

describe the inspections or analytical techniques used to ensure that excessive wall thinning 

due to flow-accelerated corrosion does not occur in the components.

By letter dated January 5, 2011, the staff issued RAI 3.1.2.2.14-01 asking the applicant to 

describe its examination techniques and the evaluation methodology used to manage wall 

thinning in the steam generator feedwater inlet rings and supports.

In its response dated February 3, 2011, the applicant stated that the Steam Generator Tube 

Integrity Program uses visual inspections of the steam generators’ secondary-side internals, 

including the steam generator feedwater inlet ring and supports, and does not include predictive 

analytical methodology for wall thinning due to flow-accelerated corrosion. The applicant further 

stated that it performs a degradation assessment of the steam generators during each RFO,

and visual inspections are required for the degradation assessment. The applicant stated that 

the visual inspections identify the general condition of the steam generator components and 

allow the search for evidence of erosion-corrosion, irregular geometry, and structural changes,

and the acceptance criteria require that there be no visible signs of degradation. The applicant 

stated that its steam generator degradation assessment for the feedwater rings typically 

includes outside surface, supports, welds, cross-over pipe, feedwater nozzle knuckle region, 

feedwater ring to J-nozzle intersection on the outside diameter, J-nozzle to feedwater ring joint 

on the inside diameter, feedwater ring weld backing rings, and all welds. The degradation 

assessment ensures that degradation of components is identified, and corrective actions are 

taken before loss of component-intended functions.

The staff finds the applicant’s response to RAI 3.1.2.2.14-01 acceptable because the applicant 

met the further evaluation criteria, and the applicant’s proposal to manage aging using the 

Steam Generator Tube Integrity Program is acceptable for the following reasons:

• The applicant’s Steam Generator Tube Integrity Program includes visual inspections of 

the steel steam generator feedwater inlet rings and supports performed at each RFO.

• The visual inspections of the feedwater inlet rings and supports are capable of 

identifying loss of material and wall thinning that may occur in these components caused 

by flow-accelerated corrosion.

• Results of the visual inspections are used as input to a degradation assessment of 

steam generator components performed during each RFO so that corrective action, if 

needed, can be implemented before loss of component-intended function occurs.

The staff’s concern described in RAI 3.1.2.2.14-01 is resolved.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.14 criteria. For those items that apply to LRA Section 3.1.2.2.14, the 

staff determined that the LRA is consistent with the GALL Report, and the applicant 

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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3.1.2.2.15 Changes in Dimensions Due to Void Swelling

The staff reviewed LRA Section 3.1.2.2.15 and Table 3.1.1, item 3.1.1-33, against criteria in 

SRP-LR 3.1.2.2.15. LRA Section 3.1.2.2.15 addresses changes in dimensions due to void 

swelling that could occur in stainless steel and Ni-alloy PWR RVI components exposed to 

reactor coolant. The SRP-LR recommends no further AMR if the applicant provides a 

commitment in the UFSAR supplement to do the following: 

• participate in the industry programs for investigating and managing aging effects on 

reactor internals

• evaluate and implement the results of the industry programs as applicable to the reactor 

internals

• upon completion of these programs, but not less than 24 months before entering the 

period of extended operation, submit an inspection plan for reactor internals to the NRC 

for review and approval

The staff noted that the applicant’s commitment (Commitment No. 1) in LRA Appendix A,

Section A3, is consistent with the commitment described in SRP-LR 3.1.2.2.15. The staff also 

noted that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1.33, are aligned with 

the applicant’s commitment, as described in LRA Appendix A, Section A3. The staff finds the 

applicant’s proposal acceptable because the discussion of the AMR item refers to the 

applicant’s AMP (PWR Vessel Internals Program), which includes the appropriate commitment 

in the UFSAR supplement.

Based on its review, the staff concludes that the applicant demonstrated that the effects of aging 

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

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.16 Cracking Due to Stress-Corrosion Cracking and Primary Water Stress-Corrosion 

Cracking

(1) LRA Section 3.1.2.2.16.1 is associated with LRA Table 3.1.1, items 3.1.1-34 and 

3.1.1-35. It addresses stainless steel canopy seal pressure housing and nickel-alloy 

CRD pressure housing exposed to reactor coolant that are being managed for cracking 

due to SCC and PWSCC by the ASME Code Section XI ISI, Subsection IWB, IWC, and 

IWD Program and the Water Chemistry Program. The criteria in SRP-LR 

Section 3.1.2.2.16, item 1, state that cracking due to SCC and PWSCC could occur for 

steel steam generator components and steam generator tube-to-tube sheet welds made 

or clad with nickel alloy exposed to reactor coolant. The SRP-LR also states that the 

GALL Report recommends ASME Code Section XI ISI and control of water chemistry to 

manage this aging effect. Additionally, no further AMR of PWSCC of nickel alloys is 

needed if the applicant complies with applicable NRC Orders and provides a 

commitment in the UFSAR supplement to implement applicable bulletins, generic letters, 

and staff-accepted industry guidelines. In its review, the staff noted that the nickel-alloy 

CRD pressure housing is not a reactor vessel head penetration or nozzle for which the 

further evaluation criterion associated with the NRC Orders and UFSAR supplement is 

applicable. In addition, the staff noted that GALL Report, Revision 2, item IV.A2.RP-55

recommends the ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program

and Water Chemistry Program to manage cracking due to SCC and PWSCC of stainless 

steel and nickel-alloy CRD pressure housings. 
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By letter dated November 15, 2010, the applicant submitted Supplement 2 to the LRA. 

As described in this document, LRA Section 3.1.2.2.16.1 addresses the further 

evaluation criteria of the SRP-LR by stating that the GALL Report, Revision 1, 

recommends a commitment in the UFSAR supplement to implement applicable bulletins 

and letters and staff-accepted industry guidelines, which is met by crediting its 

Nickel-Alloy Nozzles and Penetrations Program to manage PWSCC of the nickel-alloy

nozzles and penetrations. The applicant also clarified that the commitment 

recommended by the SRP-LR is associated with the Nickel-Alloy Nozzles and 

Penetrations Program. However, the Nickel-Alloy Nozzles and Penetrations Program is 

not applicable to the nickel-alloy CRD pressure housing because the component is not a 

penetration or nozzle. The applicant further stated that cracking due to SCC and 

PWSCC of the CRD pressure housings is being managed by the ASME Code Section XI

ISI, Subsection IWB, IWC, and IWD Program and Water Chemistry Program. The staff 

finds the applicant’s claim acceptable because the applicant’s use of the ASME Code

Section XI ISI, Subsection IWB, IWC, and IWD Program and Water Chemistry Program 

is sufficient to manage SCC of the nickel-alloy CRD pressure housing, as evaluated 

below.

The staff’s evaluations of the applicant’s ASME Code Section XI ISI, Subsection IWB, 

IWC, and IWD Program and Water Chemistry Program are documented in SER 

Sections 3.0.3.1.1 and 3.0.3.1.2, respectively. In its review of components associated 

with item 3.1.1-34, the staff finds that the applicant met the further evaluation criteria and 

the applicant’s proposal to manage aging using the ASME Code Section XI ISI, 

Subsection IWB, IWC, and IWD Program and Water Chemistry Program is acceptable 

for the following reasons:

• The Water Chemistry Program establishes the plant water chemistry 

control parameters, and their limits to mitigate an environment that is 

conducive for cracking and takes corrective actions if the parameters 

exceed these limits.

• The ASME Code Section XI ISI, Subsection IWB, IWC, and IWD Program

is adequate to detect and manage cracking of these components, 

consistent with the GALL Report.

• The use of the Water Chemistry Program in conjunction with the ASME 

Code Section XI ISI, Subsection IWB, IWC, and IWD Program is sufficient 

to manage cracking due to SCC of the components through periodic 

inspections and water chemistry control.

LRA Section 3.1.2.2.16, item 1, also states that LRA Table 3.1.1, item 3.1.1-35, is not 

applicable because the plant does not have OTSGs and, therefore, does not have the 

components associated with these steam generators. 

By letter dated December 14, 2010, the staff also issued RAI B.2.1.10-1 to request 

additional information regarding the applicant's steam generator tube-to-tubesheet 

welds, The applicant provided a response by letter dated January 13, 2011, to clarify 

the dispositioning of its tube-to-tubesheet welds with respect to its RCPB and to also 

explain how it will manage cracking due to SCC and PWSCC of the steam generator 

tube sheets and tube-to-tubesheet welds made of steel with nickel-alloy cladding. The 

staff’s evaluation of the applicant’s response to RAI B.2.1.10-1 is documented in SER 

Section 3.0.3.2.2, and Open Item OI 3.0.3.2.2-1 was identified for the applicant provide 
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additional information regarding aging management of the welds. Resolution for 

OI 3.0.3.2.2-1 will be documented in Section 3.0.3.2.2.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.16, item 1, criteria. For those items that apply to LRA 

Section 3.1.2.2.16.1, the staff determined 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 be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) LRA Section 3.1.2.2.16.2 is associated with LRA Table 3.1.1, item 3.1.1-36, and 

addresses nickel alloy and stainless steel pressurizer spray heads exposed to reactor 

coolant that are being managed for cracking due to SCC for stainless steel components

and PWSCC for nickel-alloy components by the Water Chemistry and One-Time 

Inspection Programs. SRP-LR Section 3.1.2.2.16, item 2, states that cracking due to 

SCC could occur on stainless steel pressurizer spray heads, and cracking due to 

PWSCC could occur on nickel-alloy pressurizer spray heads. The SRP-LR also states 

that the existing program relies on control of water chemistry to mitigate this aging effect. 

The GALL Report recommends one-time inspection to confirm that cracking does not 

occur. Furthermore, for nickel-alloy welded spray heads, the GALL Report recommends 

no further AMR if the applicant complies with applicable NRC Orders and provides a 

commitment in the UFSAR supplement to implement applicable bulletins, generic letters, 

and staff-accepted industry guidelines. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that it will implement the One-Time Inspection Program 

to verify the effectiveness of the Water Chemistry Program to manage cracking due to 

SCC in the stainless steel pressurizer spray head exposed to reactor coolant.

The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection

Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In 

these evaluations, the staff found these programs to be acceptable means to manage 

aging.

In its review of components associated with LRA Table 3.1.1, item 3.1.1-36, the staff 

noted that all of the associated components were constructed from stainless steel, i.e., 

there are no nickel-alloy components included in this AMR item. The staff, therefore, 

finds that the applicant met the further evaluation criteria. The applicant’s proposal to 

manage aging using the Water Chemistry and One-Time Inspection Programs is 

acceptable for the following reasons:

• The applicant’s proposed programs are consistent with those 

recommended by LRA Section 3.1.2.2.16, item 2, for stainless steel 

components.

• The Water Chemistry and One-Time Inspection Programs were evaluated 

by the staff and found to be acceptable to manage aging.

• There are no nickel-alloy components included in this AMR item, making 

the provisions of LRA Section 3.1.2.2.16, item 2, which apply to 

nickel-alloy components, not applicable.

Based on its review, the staff concludes that the aging management proposed by the 

applicant for those items which are currently under consideration meets the criteria 
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contained in item 2 of SRP-LR Section 3.1.2.2.16. The staff concludes 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).

3.1.2.2.17 Cracking Due to Stress-Corrosion Cracking, Primary Water Stress-Corrosion 

Cracking, and Irradiated-Assisted Stress-Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.17 and Table 3.1.1, item 3.1.1-37, against the criteria in 

SRP-LR 3.1.2.2.17, which addresses cracking due to SCC, PWSCC, and IASCC that could 

occur in stainless steel and Ni-alloy PWR reactor internal components exposed to reactor 

coolant. LRA Section 3.1.2.2.17 noted that the existing program relies on control of water 

chemistry to mitigate cracking due to SCC, PWSCC, and IASCC of these PWR reactor internals 

components exposed to reactor coolant. SRP-LR 3.1.2.2.17 recommends no further AMR if the 

applicant provides a commitment in the UFSAR supplement to do the following: 

• participate in the industry programs for investigating and managing aging effects on 

reactor internals

• evaluate and implement the results of the industry programs as applicable to the reactor 

internals

• upon completion of these programs, but not less than 24 months before entering the 

period of extended operation, submit an inspection plan for reactor internals to the NRC 

for review and approval

The staff noted that the applicant’s commitment (Commitment No. 1) in LRA Appendix A, 

Section A3, is consistent with the commitment described in SRP-LR 3.1.2.2.17. The staff also 

noted that all of the AMR results lines that refer to Table 3.1.1, item 3.1.1-37, align with the 

applicant’s commitment as described in LRA Appendix A, Section A3. The staff finds the 

applicant’s proposal acceptable because the discussion of the AMR item refers to the 

applicant’s AMP (PWR Vessel Internals Program), which includes the appropriate commitment 

in the UFSAR supplement.

In LRA Section 3.1.2.2.17, the applicant stated that, for managing the aging of cracking due to 

SCC, PWSCC, and IASCC of stainless steel and nickel-alloy reactor internals components 

exposed to reactor coolant, the applicant’s Water Chemistry Program is augmented by the 

commitment described above. When augmented by the commitment above, the staff finds the 

applicant’s Water Chemistry Program acceptable for managing SCC and IASCC of stainless 

steel reactor internals components exposed to reactor coolant because the Water Chemistry 

Program will control contaminants that can contribute to SCC of stainless steel.

The staff’s evaluation of the applicant’s Water Chemistry Program is documented in SER 

Section 3.0.3.1.2. In its review of components associated with item 3.1.1-37, the staff finds the 

applicant’s proposal to manage aging using the Water Chemistry Program acceptable because 

use of the Water Chemistry Program to manage cracking is consistent with the GALL Report 

when combined with the commitment described above.

Based on the programs identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.17 criteria. For those items that apply to LRA Section 3.1.2.2.17, the 

staff determined that the LRA is consistent with the GALL Report and that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 
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function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff’s evaluation of the applicant’s QA Program.

3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL 

Report

In LRA Tables 3.1.2-1 through 3.1.2-4, the staff reviewed additional details of 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 3.1.2-4, the applicant indicated, via Notes F–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 concerning how the aging 

effects will be managed. 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 if the applicant demonstrated 

that the aging effects will be adequately managed so that the intended functions will be 

maintained consistent with the CLB during the period of extended operation. The staff’s 

evaluation is discussed in the following sections.

3.1.2.3.1 Reactor Coolant System, Summary of Aging Management Evaluation, LRA 

Table 3.1.2-1

In LRA Tables 3.1.2-1, 3.1.2-2, 3.1.2-3, and 3.1.2-4, the applicant stated that for Ni-alloy 

components exposed to air with borated water leakage, there is no aging effect, and no AMP is 

proposed. The AMR items cite generic note G and plant-specific note 1. Plant-specific note 1 

states the following:

NUREG-1801 does not include air with borated water leakage for nickel-alloy 

components. Similar to V.F-13 for stainless steel, there are no aging effects for 

nickel alloy in air with borated water leakage. Additionally, the American Welding 

Society (AWS) “Welding Handbook,” (Seventh Edition, Volume 4, 1982, Library 

of Congress) identifies that nickel chromium alloy materials that are alloyed with 

iron, molybdenum, tungsten, cobalt or copper in various combinations have 

improved corrosion resistance.

The staff reviewed the associated items in the LRA and confirmed that the applicant’s use of 

generic note G for these items is appropriate in that the GALL Report, Revision 1, does not 

include entries for nickel alloys exposed to air with borated water leakage. The staff noted that 

the GALL Report, Revision 2, dated December 2010, includes entries for nickel alloys exposed 
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to air with borated water leakage. These entries indicate that no AERM is present for this 

material-environment combination. The staff also noted these items in the GALL Report, 

Revision 2, are based in part on EPRI Report 1000975, “Boric Acid Corrosion Guidebook, 

Revision 1.” This report contains data (pages 4–43) showing that “[t]here was no measurable 

corrosion of stainless steel piping surfaces or Inconel weld metal joining the stainless steel and 

carbon steel piping sections.” The staff, therefore, concurs with the applicant’s assessment that 

aging management is not necessary for nickel-alloy components exposed to air with borated 

water leakage, as described above.

In LRA Table 3.1.2-1, the applicant stated that the AERM for CASS RCS piping and fittings 

exposed to reactor coolant (internal) greater than 482 °F (250 °C), which is susceptible to loss 

of fracture toughness due to thermal aging embrittlement, is not applicable, and no AMP is 

proposed. The AMR item cites generic note I. The applicant addressed the CASS piping and 

fitting components in LRA Table 3.1.2-1 for the RCS and related these components to LRA 

item 3.1.1-57. The applicant also stated that these components have molybdenum and ferrite 

contents below the threshold for susceptibility to thermal aging embrittlement.

The staff reviewed the associated items in the LRA and confirmed that loss of fracture 

toughness due to thermal aging embrittlement is not applicable to the component, material and 

environment combination. LRA Table 3.1.1, item 3.1.1-57, indicates that the molybdenum and 

ferrite contents for this component are below the threshold (less than 0.5 percent molybdenum 

and less than 20 percent ferrite), such that the components are not susceptible to this aging 

effect, consistent with GALL Report AMP XI.M12.

The staff also noted that UFSAR Table 5.2-2 indicates that the piping in the RCS is made of 

SA-376, Grade 304N, or centrifugally-cast SA-351, Grade CF8A. The staff noted that SA-376, 

Grade 304N, material is not a CASS material and, therefore, finds that this material is not 

susceptible to thermal aging embrittlement, consistent with the GALL Report. The staff also 

finds that centrifugally-cast SA-351, Grade CF8A, is a low-molybdenum CASS material, which is 

not susceptible to thermal aging embrittlement, consistent with the GALL Report AMP XI.M12. 

In a teleconference held on March 3, 2011, the applicant further clarified that the reactor coolant 

piping, described in UFSAR Table 5.2-2, is made of SA-376, Grade 304N, material, and the 

listed centrifugal casting material has not been used for the reactor coolant piping.

In LRA Table 3.1.2-1, the applicant stated that the stainless steel bolting exposed to air-indoor is 

being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic 

note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because,

even though stainless steel bolting exposed to air-indoor is not specifically addressed in the 

GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent 

of environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to 

a variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion and cracking due to SCC. The staff noted that the environment of interest, air-indoor, 

would not induce SCC or loss of material in stainless steel material because stainless steel is 

inherently resistant to corrosion in the air-indoor environment. Therefore, the aging effect of 

concern is loss of preload, which is addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for stainless steel bolting exposed to air-indoor in the 
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RCS, the GALL Report has items for other material bolting exposed to air-indoor managed by 

the Bolting Integrity Program. The staff finds the applicant’s proposal to manage aging using 

the Bolting Integrity Program acceptable because the Bolting Integrity Program conducts bolting 

assembly and maintenance control such as application of appropriate gasket alignment, torque, 

lubricants, and preload. It also inspects for leakage and loose or missing nuts, which verify that 

the aging effect, loss of preload, will be adequately managed so that the intended functions will 

be maintained consistent with the CLB for the period of extended operation.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.1.2.3.2 Reactor Vessel, Summary of Aging Management Evaluation, LRA Table 3.1.2-2

The staff’s evaluation for Ni-alloy components exposed to borated water leakage that are not 

subject to an aging effect requiring management, with generic note G, is documented in SER 

Section 3.1.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.1.2.3.3 Reactor Vessel Internals, Summary of Aging Management Evaluation, LRA 

Table 3.1.2-3

Table 3.1.2-3, “Reactor Vessel Internals, Summary of Aging Management Evaluation,” item 366,

addresses Ni-Alloy flux thimble tubes exposed to air with borated water leakage (internal) and 

assigns Note G to this component. The staff’s evaluation for Ni-alloy components exposed to 

borated water leakage that are not subject to an aging effect requiring management, with 

generic note G, is documented in SER Section 3.1.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.1.2.3.4 Steam Generator, Summary of Aging Management Evaluation, LRA Table 3.1.2-4

In LRA Table 3.1.2-4, the applicant stated that the nickel-alloy steam generator tubes exposed 

to reactor coolant are being managed for reduction of heat transfer by the Water Chemistry 

Program. The AMR item cites generic note H. The AMR items also cite plant-specific note 4, 

which states that reduction of heat transfer due to fouling is not in the GALL Report for this 
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3-241

component, material, and environment but that reduction of heat transfer is applicable to this 

combination and, therefore, will be managed by the Water Chemistry Program.

The staff reviewed the associated items in the LRA. However, it was not clear to the staff how 

the Water Chemistry Program alone would ensure that reduction of heat transfer is 

appropriately managed. Typically, for reduction of heat transfer, both a Water Chemistry 

Program and an Inspection Program are used to manage this aging effect. By letter date 

January 5, 2011, the staff issued RAI 3.1.2.4-1, requesting that the applicant justify how the 

Water Chemistry Program alone is sufficient to determine that steam generator tubes are not 

affected by reduction of heat transfer when exposed to reactor coolant.

In its response dated February 3, 2011, the applicant stated that reduction of heat transfer due 

to fouling was inadvertently added as an AMR item and that neither plant-specific nor any 

industry operating experience has indicated that this aging effect is applicable to steam 

generator tubes exposed to reactor coolant. The applicant has removed the AMR item from the 

LRA. The staff finds the applicant’s response acceptable because reduction of heat transfer 

due to fouling for tubes internally exposed to reactor coolant is not an aging affect that has been 

observed in steam generators, which is consistent with the GALL Report. The staff’s concern 

described in RAI 3.1.2.4-1 is resolved.

In LRA Table 3.1.2-4, the applicant stated that the nickel-alloy steam generator tubes exposed 

to secondary feedwater or steam are being managed for reduction of heat transfer by the Water 

Chemistry Program and Steam Generator Tube Integrity Program. The AMR item cites generic 

note H. The AMR items also cite plant-specific note 3, which states that reduction of heat 

transfer due to fouling is not in the GALL Report for this component, material, and environment, 

but that reduction of heat transfer is applicable to this combination and, therefore, will be 

managed by the Water Chemistry Program and Steam Generator Tube Integrity Program.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

steam generator tubes are likely places where fouling can occur due to buildup of corrosion 

products, and evidence of fouling has been shown to occur in certain locations in the steam 

generators (ASM International, Environments and Industries, pp. 362–385, 2006).

The staff’s evaluations of the applicant’s Water Chemistry Program and Steam Generator Tube 

Integrity Program are documented in SER Sections 3.0.3.1.2 and 3.0.3.2.2, respectively. The 

staff noted that the Water Chemistry Program relies upon periodic monitoring and control of 

detrimental contaminants in the water to manage reduction of heat transfer. The staff also 

noted that the Steam Generator Tube Integrity Program uses visual inspections to evaluate 

sludge buildup and other corrosion phenomena. The staff finds the applicant’s proposal to 

manage aging using the Water Chemistry Program and Steam Generator Tube Integrity 

Program acceptable because the maintenance of water chemistry will prevent buildup of 

products that can lead to reduction of heat transfer, and the visual inspections will be able to 

identify the occurrence of fouling that could lead to a reduction of heat transfer.

The staff’s evaluation for Ni-alloy components exposed to borated water leakage that are not 

subject to an aging effect requiring management, with generic note G, is documented in SER 

Section 3.1.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 
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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).

3.1.3 Conclusion

The staff concludes that the applicant provided sufficient information to demonstrate that the 

effects of aging for the reactor vessel, RVIs, RCS, and steam generator components, within the 

scope of license renewal and subject to an AMR, will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.2

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

ESFs systems components and component groups of the following systems:

Aging Management of Engineered Safety Features

• combustible gas control system

• containment building spray system

• RHR system

• safety injection system

3.2.1 Summary of Technical Information in the Application 

LRA Section 3.2 provides AMR results for the engineered safety features (ESF) systems'

components. LRA Table 3.2.1, “Summary of Aging Management Evaluation for Engineered 

Safety Features,” is a summary comparison of the applicant’s AMRs with those evaluated in the 

GALL Report for the ESF 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 if 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 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 3.2.2.1.
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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 3.2.2.2 acceptance criteria. The staff’s audit 

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 which 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.

Table 3.2-1. Staff evaluation for engineered safety features systems components in the 

GALL Report 

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

ECCS

(3.2.1-1)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes TLAA Consistent with 

GALL Report (see 

SER Section 

3.2.2.2.1)

Steel with stainless 

steel cladding pump 

casing exposed to 

treated borated 

water

(3.2.1-2)

Loss of material 

due to cladding 

breach

A plant-specific 

AMP is to be 

evaluated.

Reference NRC 

IN 94-63, “Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks”

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.2.2) 

Stainless steel 

containment 

isolation piping and 

components internal 

surfaces exposed to 

treated water

(3.2.1-3)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.2.2.2.3)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil

(3.2.1-4)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.2.3)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel and 

aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.2.1-5)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.2.2.2.3)

Stainless steel and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil

(3.2.1-6)

Loss of material 

due to pitting 

and crevice 

corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.2.2.2.3)

Partially encased 

stainless steel tanks 

with breached 

moisture barrier 

exposed to raw 

water

(3.2.1-7)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated for pitting 

and crevice 

corrosion of tank 

bottoms because 

moisture and water 

can egress under 

the tank due to 

cracking of the 

perimeter seal from 

weathering.

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.2.3)

Stainless steel 

piping, piping 

components, piping 

elements, and tank 

internal surfaces 

exposed to 

condensation 

(internal)

(3.2.1-8)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Not applicable to 

Seabrook (see 

SER Section 

3.2.2.2.3)

Steel, stainless 

steel, and 

copper-alloy heat 

exchanger tubes 

exposed to 

lubricating oil

(3.2.1-9)

Reduction of 

heat transfer 

due to fouling

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent with 

GALL Report (see 

SER Section 

3.2.2.2.4)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water

(3.2.1-10)

Reduction of 

heat transfer 

due to fouling

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.2.4)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Elastomer seals and 

components in 

standby gas 

treatment system 

exposed to airindoor uncontrolled

(3.2.1-11)

Hardening and

loss of strength 

due to elastomer 

degradation

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.2.2.2.5)

Stainless steel highpressure safety 

injection (HPSI)

(charging) pump 

miniflow orifice 

exposed to treated 

borated water

(3.2.1-12)

Loss of material 

due to erosion

A plant-specific 

AMP is to be 

evaluated for 

erosion of the 

orifice due to 

extended use of the 

centrifugal HPSI 

pump for normal 

charging.

Yes Not applicable Consistent with 

GALL Report (see 

SER Section 

3.2.2.2.6)

Steel drywell and 

suppression 

chamber spray 

system nozzle and 

flow orifice internal 

surfaces exposed to 

air-indoor 

uncontrolled 

(internal)

(3.2.1-13)

Loss of material 

due to general 

corrosion and 

fouling

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.2.2.2.7)

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water

(3.2.1-14)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.2.2.2.8)

Steel containment 

isolation piping, 

piping components, 

and piping elements 

internal surfaces 

exposed to treated 

water

(3.2.1-15)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Not applicable to 

Seabrook (see 

SER Section 

3.2.2.2.8)

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil

(3.2.1-16)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see

SER Section 

3.2.2.2.8)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel (with or 

without coating or 

wrapping) piping, 

piping components, 

and piping elements 

buried in soil

(3.2.1-17)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion (MIC)

Buried Piping and 

Tanks Surveillance

or

Buried Piping and 

Tanks Inspection

No

Yes

Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.2.9)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 140 °F 

(> 60 °C)

(3.2.1-18)

Cracking due to 

SCC and 

IGSCC

BWR SCC and 

Water Chemistry

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.2.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water

(3.2.1-19)

Wall thinning 

due to flowaccelerated 

corrosion

Flow-Accelerated 

Corrosion

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.2.2.1.1)

CASS piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated or 

unborated) > 482 °F 

(> 250 °C)

(3.2.1-20)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Thermal Aging 

Embrittlement of 

CASS

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.2.2.1.1)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.2.1-21)

Cracking due to 

cyclic loading

and SCC

Bolting Integrity No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Steel closure bolting 

exposed to air with 

steam or water 

leakage

(3.2.1-22)

Loss of material 

due to general 

corrosion

Bolting Integrity No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Steel bolting and 

closure bolting 

exposed to airoutdoor (external), 

or air-indoor 

uncontrolled 

(external)

(3.2.1-23)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Bolting Integrity No Bolting Integrity Consistent with 

GALL Report
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel closure bolting 

exposed to airindoor uncontrolled 

(external)

(3.2.1-24)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Bolting Integrity No Bolting Integrity Consistent with 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water > 140 °F 

(>60 °C)

(3.2.1-25)

Cracking due to 

SCC

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water

(3.2.1-26)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Steel heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.2.1-27)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Stainless steel 

piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to closedcycle cooling water

(3.2.1-28)

Loss of material 

due to pitting 

and crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Copper-alloy piping, 

piping components, 

piping elements, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.2.1-29)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report
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3-248

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel and 

copper-alloy heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water

(3.2.1-30)

Reduction of 

heat transfer 

due to fouling

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

External surfaces of 

steel components 

including ducting, 

piping, ducting 

closure bolting, and 

containment 

isolation piping 

external surfaces 

exposed to airindoor uncontrolled 

(external); 

condensation 

(external) and airoutdoor (external)

(3.2.1-31)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring

Consistent with 

GALL Report

Steel piping and 

ducting components 

and internal 

surfaces exposed to 

air-indoor 

uncontrolled 

(Internal)

(3.2.1-32)

Loss of material 

due to general 

corrosion

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report

Steel encapsulation 

components 

exposed to airindoor uncontrolled 

(internal)

(3.2.1-33)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal)

(3.2.1-34)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Steel containment 

isolation piping and 

components internal 

surfaces exposed to 

raw water

(3.2.1-35)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion, and 

fouling

Open-Cycle 

Cooling Water 

System

No Fire Water 

System

Consistent with 

GALL Report (see 

SER Section 

3.2.2.1.2)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel heat 

exchanger 

components 

exposed to raw 

water

(3.2.1-36)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

MIC, and fouling

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.2.1-37)

Loss of material 

due to pitting, 

crevice, and 

MIC

Open-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Stainless steel 

containment 

isolation piping and 

components internal 

surfaces exposed to 

raw water

(3.2.1-38)

Loss of material 

due to pitting, 

crevice, and 

MIC, and fouling

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program

Consistent with 

GALL Report (see 

SER Section 

3.2.2.1.3)

Stainless steel heat 

exchanger 

components 

exposed to raw 

water

(3.2.1-39)

Loss of material 

due to pitting, 

crevice, and 

MIC, and fouling

Open-Cycle 

Cooling Water 

System

No Fire Water 

System 

Program

Consistent with 

GALL Report (see 

SER Section 

3.2.2.1.3)

Steel and stainless 

steel heat 

exchanger tubes 

(serviced by opencycle cooling water) 

exposed to raw 

water

(3.2.1-40)

Reduction of 

heat transfer 

due to fouling

Open-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Copper-alloy

> 15% Zn piping, 

piping components, 

piping elements, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.2.1-41)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Selective 

Leaching of 

Materials

Consistent with 

GALL Report
Aging Management Review Results

3-250

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water

(3.2.1-42)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil

(3.2.1-43)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Gray cast iron motor 

cooler exposed to 

treated water 

(3.2.1-44)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Aluminum, 

copper-alloy

> 15% Zn, and steel 

external surfaces, 

bolting, and piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage

(3.2.1-45)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion

Consistent with 

GALL Report

Steel encapsulation 

components 

exposed to air with 

borated water 

leakage (internal)

(3.2.1-46)

Loss of material 

due to general, 

pitting, crevice,

and boric acid 

corrosion

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report

CASS piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

> 482 °F (>250 °C )

(3.2.1-47)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Thermal Aging 

Embrittlement of 

CASS

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel or 

stainless-steel-clad 

steel piping, piping 

components, piping 

elements, and tanks 

(including safety 

injection 

tanks/accumulators) 

exposed to treated 

borated water 

> 140 °F (> 60 °C)

(3.2.1-48)

Cracking due to 

SCC

Water Chemistry No Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report

Stainless steel 

piping, piping 

components, piping 

elements, and tanks 

exposed to treated 

borated water

(3.2.1-49)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry No Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to airindoor uncontrolled 

(internal/external)

(3.2.1-50)

None None No None Consistent with 

GALL Report

Galvanized steel 

ducting exposed to 

air-indoor controlled 

(external)

(3.2.1-51)

None None No None Consistent with 

GALL Report

Glass piping 

elements exposed 

to air-indoor 

uncontrolled 

(external), 

lubricating oil, raw 

water, treated water, 

or treated borated 

water

(3.2.1-52)

None None No None Consistent with 

GALL Report

Stainless steel, 

copper-alloy, and 

nickel-alloy piping, 

piping components, 

and piping elements 

exposed to airindoor uncontrolled 

(external)

(3.2.1-53)

None None No None Consistent with 

GALL Report
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to airindoor controlled 

(external)

(3.2.1-54)

None None No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.2.1-55)

None None No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.2.2.1.1)

Steel, stainless 

steel, and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to gas

(3.2.1-56)

None None No None Consistent with 

GALL Report

Stainless steel and 

copper-alloy

< 15% Zn piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage

(3.2.1-57)

None None No None Consistent with 

GALL Report

The staff’s review of the ESF systems' component groups followed 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 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 system components is documented in SER Section 3.0.3.

3.2.2.1 Aging Management Review 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:

• ASME Code Section XI ISI Subsections IWB, IWC, and IWD Program

• Bolting Integrity Program

• Boric Acid Corrosion Program
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• Closed-Cycle Cooling Water System Program

• External Surfaces Monitoring Program

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program

• Lubricating Oil Analysis Program

• One-Time Inspection Program

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program

• Water Chemistry Program

LRA Tables 3.2.2-1 through 3.2.2-4 summarize AMRs for the ESF system components and 

indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine if the plant-specific components in these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR item describing how the information in the tables 

aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A–E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these items to verify consistency with the GALL Report and the validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff reviewed these items to verify consistency with the 

GALL Report and to ensure that it had reviewed and accepted the identified exceptions to the 

GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the 

site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

items to verify consistency with the GALL Report. The staff also determined whether the AMR 

item of the different component applied to the component under review and whether the AMR 

was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the AMP identified in the GALL Report. The staff reviewed these items to 

verify consistency with the GALL Report. The staff confirmed whether the AMR item of the 
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different component was applicable to the component under review and whether the exceptions 

to the GALL Report AMPs was reviewed and accepted by the staff. The staff also determined 

whether the AMP identified by the applicant was consistent with the AMP identified in the GALL 

Report and whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff reviewed these items 

to verify consistency with the GALL Report and determined whether the identified AMP would 

manage the aging effect consistent with the AMP identified in the GALL Report and whether the 

AMR was valid for the site-specific conditions.

The staff 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 3.2.1-48, addresses stainless steel or stainless steel clad steel piping, 

piping components, piping elements, and tanks exposed to treated borated water greater than 

140 °F (60 °C), which are being managed for cracking due to SCC. The LRA credits the Water 

Chemistry Program to manage the aging effect. The GALL Report recommends GALL Report 

AMP XI.M2, “Water Chemistry” to ensure that these aging effects are adequately managed. 

The associated AMR items cite generic note A.

In its review of components associated with item 3.2.1-48, for which the applicant cited generic 

note A, the staff noted that it was unclear if any of these components is a Class 1 valve. The 

staff noted that GALL Report item IV.C2-3 recommends both Water Chemistry Program and a 

plant-specific program to manage cracking of CASS Class 1 piping, piping components, and 

piping elements, which have carbon content greater than 0.035 percent or ferrite content less 

than 7.5 percent, based on the material susceptibility criteria described in NUREG-0313, 

Revision 2. The staff also noted that the recommendations of GALL Report item IV.C2-3 may 

be applicable for the CASS valve bodies exposed to treated borated water greater than 140 °F 

(60 °C) in LRA Tables 3.1.2-1, 3.2.2-3, and 3.3.2-3.

By letter dated January 5, 2011, the staff issued RAI 3.1.2.1-01 requesting that the applicant 

clarify whether any of the CASS valves in the RCS, RHR system, or chemical and volume 

control system is a Class 1 component, for which the GALL Report recommends a plant-specific 

program, in addition to the Water Chemistry Program, to manage SCC. The staff also 

requested the applicant to justify why the Water Chemistry Program alone, without a 

plant-specific program, is adequate to manage the cracking due to SCC for the CASS Class 1 

component if any of these CASS valves is a Class 1 component that has carbon content greater 

than 0.035 percent or ferrite content less than 7.5 percent.

In its response dated February 3, 2011, the applicant stated that the valves associated with the 

items for CASS valve bodies in the environment of treated borated water greater than 140 °F 

(60 °C) are not Class 1 components. The applicant further stated that no plant-specific program 

is required in addition to the Water Chemistry Program to manage cracking due to SCC based 

on the material susceptibility criteria described in NUREG-0313, Revision 2. The staff finds the 

applicant’s response acceptable because the applicant clarified that none of the CASS valve 

bodies are Class 1 components and that the applicant’s management of cracking using the 

Water Chemistry Program is consistent with the GALL Report. The staff finds the applicant’s 

response unacceptable because the guidance in the SRP-LR and GALL Report was revised in 

License Renewal Interim Staff Guidance (LR-ISG), LR-ISG-2011-01, “Aging Management of 
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Stainless Steel Structures and Components in Treated Borated Water,” to add the One-Time 

Inspection Program to verify the effectiveness of the Water Chemistry Program to manage 

stainless steel components for loss of material, cracking, and reduction of heat transfer in 

treated borated water environments that are not controlled to low oxygen levels. The staff noted 

that, prior to issuance of LR-ISG-2011-01; the SRP-LR and GALL Report guidance 

inappropriately credited the boron in borated water as a corrosion inhibitor in place of other 

aging management activities.

By letter dated May 29, 2012, the staff issued RAI 3.2.1.48-1 requesting that the applicant 

describe how the effectiveness of the Water Chemistry Program to manage cracking will be 

verified for stainless steel components exposed to treated borated water with greater than 5 ppb 

oxygen. Pending the staff’s review of the applicant’s response, this issue is identified as Open 

Item OI 3.2.2.1-1.

LRA Table 3.2.1, item 3.2.1-49 addresses stainless steel piping, piping components, piping 

elements, tanks, and heat exchanger components exposed to treated borated water which are 

being managed for loss of material due to pitting and crevice corrosion. The LRA credits the 

Water Chemistry Program to manage the aging effect. The GALL Report recommends GALL 

AMP XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately managed. 

The associated AMR items cite generic notes A or C. 

In its review of components associated with item number 3.2.1-49 for which the applicant cited 

generic notes A or C, the staff noted that the guidance in the SRP-LR and GALL Report was 

revised in LR-ISG-2011-01, “Aging Management of Stainless Steel Structures and Components 

in Treated Borated Water,” to add the One-Time Inspection Program to verify the effectiveness 

of the Water Chemistry Program to manage stainless steel components for loss of material, 

cracking, and reduction of heat transfer in treated borated water environments that are not 

controlled to low oxygen levels. The staff noted that, prior to the issuance of LR-ISG-2011-01, 

the SRP-LR and GALL Report guidance inappropriately credited the boron in borated water as a 

corrosion inhibitor in place of other aging management activities.

By letter dated May 29, 2012, the staff issued RAI 3.2.1.48-1 requesting that the applicant 

describe how the effectiveness of the Water Chemistry Program to manage loss of material will 

be verified for stainless steel components exposed to treated borated water with greater than 5 

ppb oxygen. Pending the staff’s review of the applicant’s response, this issue is identified as 

Open Item OI 3.2.2.1-1.

The staff evaluated the applicant’s claim of consistency with the GALL Report. 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, pending resolution of 

Open Item OI 3.2.2.1-1, the staff concludes that the AMR results, which the applicant claimed to 

be consistent with the GALL Report, are indeed consistent with its AMRs. Therefore, the staff 

concludes, pending resolution of Open Item OI 3.2.2.1-1, that the applicant 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).

3.2.2.1.1 Aging Management Review Results Identified as Not Applicable

LRA Table 3.2.1, items 3.2.1-18, 3.1.2-19, and 3.2.1-20, state that these items are applicable 

only to BWRs. The staff confirmed that these items do not apply because the unit is a PWR 
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design. Based on this determination, the staff finds that the applicant provided an acceptable 

basis for concluding AMR items 3.2.1-18, 3.1.2-19, and 3.2.1-20 are not applicable.

For LRA Table 3.2.1, items 3.2.1-21, 3.2.1-22, 3.2.1-33, 3.2.1-34, 3.2.1-36, 3.2.1-37, 3.2.1-40, 

3.2.1-42, 3.2.1-43, 3.2.1-44, and 3.2.1-47 the applicant claimed these items 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.

LRA Table 3.2.1, item 3.2.1-54 addresses steel piping, piping components, and piping elements 

exposed to controlled indoor air (external) and states that there are no aging effects, aging 

mechanisms, or AMPs. The GALL Report, Table V, item V.F-16 (EP-4) recommends that there 

is no aging effect or aging mechanism and that no AMP is recommended for this component 

group exposed to this environment, and, therefore, the staff finds the applicant’s determination 

acceptable.

LRA Table 3.2.1, item 3.2.1-55 addresses steel and stainless steel piping, piping components, 

and piping elements exposed to concrete and states that there are no aging effects, aging 

mechanisms, or AMPs. The GALL Report, Table V, items V.F-14 (EP-20) and V.F-17 (EP-5) 

recommend that there is no aging effect or aging mechanism and that no AMP is recommended 

for these component groups exposed to this environment, and, therefore, the staff finds the 

applicant’s determination acceptable.

3.2.2.1.2 Loss of Material Due To General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, and Fouling

LRA Table 3.2.1, item 3.2.1-35, addresses steel containment isolation piping and components 

internal surfaces exposed to raw water, which are being managed for loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion, and fouling. The applicant

credits the Fire Water System Program to manage the aging effect. The GALL Report 

recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that 

these aging effects are adequately managed. The associated AMR items cite generic note E 

with plant-specific notes that state the raw water environment is associated with the Fire Water

System; therefore, the Open-Cycle Cooling Water System Program is not applicable.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. In its review of components associated with LRA 

Table 3.2.1, item 3.2.1-35, for which the applicant cited generic note E, the staff noted that the 

Fire Water System Program proposes to manage the aging of steel isolation piping and 

components internal surfaces through the use of inspections, periodic flushing, system 

performance testing, and chemical additions to prevent microbiological growth.

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.2.8. In its review of components associated with LRA Table 3.2.1, item 3.2.1-35, 

the staff finds the applicant’s proposal to manage aging using the Fire Water System Program 

acceptable because the program conducts inspections roughly every outage and uses 

preventive actions including chemical additions and performance verification.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 
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consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.2.2.1.3 Loss of Material Due To Pitting, Crevice, and Microbiologically-Influenced Corrosion, 

and Fouling

LRA Table 3.2.1, item 3.2.1-38, addresses stainless steel containment isolation piping and 

components internal surfaces exposed to raw water, which are being managed for loss of 

material due to pitting, crevice, and microbiologically-influenced corrosion, and fouling. The 

applicant credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program to manage the aging effect. The GALL Report recommends GALL 

Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these aging effects 

are adequately managed. The associated AMR items cite generic note E with plant-specific 

noted that state the raw water environment is associated with radioactive liquid waste drainage; 

therefore, the Open-Cycle Cooling Water System Program is not applicable.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. In its review of components associated with LRA 

Table 3.2.1, item 3.2.1-38, for which the applicant cited generic note E, the staff noted that the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

proposes to manage the aging of stainless steel isolation piping and components' internal 

surfaces through the use of periodic inspection on the internal surfaces of components. It was 

not clear to the staff how the opportunistic visual inspections will be able to manage aging of 

components in a raw water system that does not include chemical treatments or surveillances. 

By letter dated January 5, 2011, the staff issued RAI 3.3.2.2-1 requesting that the applicant 

justify the use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Component Program, which is only a visual inspection program to manage aging in the raw 

water environment.

In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows for components exposed to raw water, which are not part of the open-cycle 

cooling water, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Component Program; therefore, the applicant’s proposal is in accordance with the 

current staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.2.1, item 3.2.1-38, the staff finds the applicant’s 

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program acceptable. The program conducts inspections during periodic 

system surveillances or maintenance activities when internal surfaces are accessible and 
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monitors parameters such as corrosion, corrosion byproducts, coating degradation, 

scale/deposits, pits, and surface discoloration and discontinuities, which is sufficient to manage 

aging of these components and is consistent with the staff’s current position.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

LRA Table 3.2.1, item 3.2.1-39, addresses stainless steel heat exchanger components exposed 

to raw water, which are being managed for loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion, and fouling. The applicant credits the Fire Water System 

Program to manage the aging effect. The GALL Report recommends GALL Report 

AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these aging effects are 

adequately managed. The associated AMR items cite generic note E with plant-specific notes 

that state the raw water environment is associated with the fire protection system; therefore, the 

Open-Cycle Cooling Water System Program is not applicable.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. In its review of components associated with LRA 

Table 3.2.1, item 3.2.1-39, for which the applicant cited generic note E, the staff noted that the 

Fire Water System Program proposes to manage the aging of stainless steel heat exchanger 

components through the use of inspections, periodic flushing, system performance testing, and 

chemical additions to prevent microbiological growth.

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.2.8. In its review of components associated with LRA Table 3.2.1, item 3.2.1-39, 

the staff finds the applicant’s proposal to manage aging using the Fire Water System Program 

acceptable because the program conducts inspections roughly every outage and uses 

preventive actions including chemical additions and performance verification.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.2.2.2 Aging Management Review 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 system components and provides information concerning how it 

will manage the following aging effects:

• cumulative fatigue damage

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• reduction of heat transfer due to fouling

• hardening and loss of strength due to elastomer degradation

• loss of material due to erosion
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• loss of material due to general corrosion and fouling

• loss of material due to general, pitting, and crevice corrosion

• loss of material due to general, pitting, crevice, and MIC

• 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 if 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.

3.2.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.2.2.2.1, which is associated with LRA Table 3.2.1, item 3.2.1-1, addresses steel 

and stainless steel piping, piping components, and piping elements in RHR and safety injection 

(SI) systems exposed to treated water and 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 this 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 ESF systems is a TLAA, and these TLAAs are to be evaluated in 

accordance with the TLAA acceptance criteria requirements of 10 CFR 54.21(c) and in 

accordance with SRP-LR Section 4.3, “Metal Fatigue Analysis.” The staff reviewed the 

applicant’s AMR items and finds that the AMR results are consistent with the recommendations 

of the GALL Report and SRP-LR for managing cumulative fatigue damage in steel and stainless 

steel piping, piping components, and piping elements exposed to treated water, except as 

identified below.

The staff noted that LRA Tables 3.2.2-3 and 3.2.2-4 do not include any applicable items for 

management of cumulative fatigue damage in the RHR and SI systems. By letter dated 

January 21, 2010, the staff issued RAI 3.3.2.2.1-1, Request 1, asking the applicant to include, in 

LRA Table 3.2.2-3 for RHR system and Table 3.2.2-4 for SI system, any applicable items 

related to the management of cumulative fatigue damage in non-Class 1 components or provide 

the basis for excluding these items from the LRA.

In its response dated February 18, 2011, the applicant amended LRA Tables 3.2.2-3 and 

3.2.2-4 to include the associated AMR items for the RHR and SI systems, consistent with GALL 

AMR item V.D1-27. The applicant stated that six rows representing TLAAs of stainless steel 

pressure boundary components such as orifice, piping and fittings, pump casing, thermowell, 

and valve body exposed to treated borated water have been added to LRA Table 3.2.2-3, and 

five rows have been added to LRA Table 3.2.2-4.

Based on its review of the amended LRA Tables 3.2.2-3 and 3.2.2-4, the staff finds the 

applicant’s response to RAI 3.3.2.2.1-1, Request 1, and the additions of the AMR items 

acceptable because they are consistent with GALL AMR item V.D1-27 for the RHR and SI

systems. The staff’s concern described in RAI 3.3.2.2.1-1, Request 1, is resolved.
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In its review of LRA Tables 3.2.2-3 and 3.2.2-4, the staff also noted AMR items associated with 

item 3.1.1-8 regarding TLAAs of piping and fittings (Class 1, including less than 4 in.), valve 

body, and orifice (Class 1). The staff noted that LRA Section 4.3.7 states that the RHR and SI 

system components were designed in accordance with ASME Code Section III, Class 2 and

Class 3, requirements. It is not clear to the staff which piping and piping components are 

represented in these rows in LRA Tables 3.2.2-3 and 3.2.2-4 and if these components represent 

the portions of the RHR and SI systems that are located inside the reactor containment.

By letter dated January 21, 2010, the staff issued RAI 3.3.2.2.1-2 asking the applicant to clarify 

which portions of the RHR and SI systems are represented by item 3.1.1-8 in LRA 

Tables 3.2.2-3 and 3.3.2-4. The staff also requested that the applicant clarify the inconsistency 

between LRA Section 4.3.7, which states that the RHR and SI systems components were 

designed to ASME Code Section III Class 2 and Class 3 requirements and LRA Table 3.1.1, 

item 3.1.1-8, which represents Class 1 components. Furthermore, the staff requested that the 

applicant identify the TLAA in LRA Section 4 that represents these AMR items. As part of the 

RAI 3.3.2.2.1-2, the staff also sent similar questions regarding the chemical and volume control 

system (CVCS). The staff’s evaluation of the applicant’s response to the portion of the RAI 

related to the CVCS is documented in SER Section 3.3.2.2.1.

In its response dated February 18, 2011, the applicant clarified that item 3.1.1-8 represents the 

Class 1 RCPB components in the RHR (LRA Table 3.2.2-3) and SI (Table 3.2.2-4) systems. 

The applicant also stated that AMR items that represents the Class 2 and Class 3 components 

in the RHR and SI systems were added to LRA Table 3.2.2-3 and Tables 3.2.2-4, as part of the 

response in RAI 3.3.2.2.1-1. The applicant stated that the Class 1 RCPB components in the 

RHR and SI systems, which are part of the NSSS, are evaluated in LRA Section 4.3.1 and 

4.3.2. The applicant also stated that the TLAAs for Class 2 and Class 3 components are 

evaluated in LRA Section 4.3.7.

Based on its review, the staff finds the applicant’s response to RAI 3.3.2.2.1-2 acceptable 

because the applicant clarified the AMR items and associated TLAAs for Class 1 RCPB

components and Class 2 and Class 3 components in the RHR and SI systems. The applicant’s 

AMR results are consistent with the recommendations of the GALL Report. The staff’s review of 

the applicant’s TLAAs associated with the Classes 1, 2, and 3 components are documented in 

SER Section 4.3. The staff’s concern described in RAI 3.3.2.2.1-2 is resolved.

Based on the staff’s review, it concludes that the applicant 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 the applicant 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 due to cladding breach in pump casings of steel with stainless steel cladding exposed 

to treated borated water. The applicant stated that this item is not applicable because the 

plant’s ESF systems do not contain pump casings comprised of steel with stainless steel 

cladding. The staff reviewed LRA Sections 2.3.2 and 3.2 and the UFSAR and confirmed that no 
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in-scope pump casings of steel with stainless steel cladding exposed to treated borated water 

are present in the ESF systems; therefore, it finds the applicant’s claim 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 3.2.2.2.3.1, is associated with LRA Table 3.2.1, item 3.2.1-3, and 

addresses stainless steel containment isolation piping, piping components, and piping 

elements exposed to treated water, which are being managed for loss of material due to 

pitting and crevice corrosion by the Water Chemistry and One-Time Inspection 

Programs. The criteria in SRP-LR Section 3.2.2.2.3, item 1, state that loss of material 

due to pitting and crevice corrosion could occur for internal surfaces of stainless steel 

containment isolation piping, piping components, and piping elements exposed to 

treated water. The SRP-LR also states that the Water Chemistry Program relies on 

monitoring and control of water chemistry to mitigate degradation, and a one-time 

inspection of select components at susceptible locations is an acceptable method to 

determine if an aging effect does not occur or progresses very slowly such that the 

component’s intended function will be maintained during the period of extended 

operation. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that loss of material due to pitting and crevice corrosion of stainless steel piping 

components exposed to treated water will be managed by the Water Chemistry and 

One-Time Inspection Programs.

The applicant stated that for item 3.2.1-3, the applicability is limited to stainless steel 

containment building spray and demineralized water system components exposed to 

treated water. The staff noted that a search of LRA Section 3.2 and the applicant’s 

UFSAR confirmed that no in-scope piping, piping components, and piping elements 

exposed to treated water are present in the containment isolation systems, except for 

those listed in LRA Section 3.2.2.2.3, item 1 and item 3.2.1-3.

The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its 

review of components associated with item 3.2.1-3, the staff finds that the applicant met 

the further evaluation criteria. The staff finds the applicant’s proposal to manage aging 

using the Water Chemistry and One-Time Inspection Program acceptable because the 

Water Chemistry Program uses chemical sampling and corrective actions to ensure that 

impurities are minimized to reduce aging due to loss of material. Additionally, the 

One-Time Inspection Program will perform visual, surface, volumetric, or other 

non-destructive examination methods of components determined to be most susceptible 

to degradation to verify the effectiveness of the Water Chemistry Program for managing 

the aging effects of loss of material.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.3, item 1, criteria. For those items that apply to LRA 

Section 3.2.2.2.3.1, the staff determined that the LRA is consistent with the GALL 

Report. The staff also finds that the applicant 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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(2) LRA Section 3.2.2.2.3.2, associated with LRA Table 3.2.1, item 3.2.1-4, addresses loss 

of material from pitting and crevice corrosion in stainless steel piping, piping 

components, and piping elements exposed to a soil environment. The applicant stated 

that this item is not applicable because there are no stainless steel components in the 

ESF systems that are exposed to soil. The staff reviewed LRA Sections 2.3.2 and 3.2 

and the applicant’s UFSAR and confirmed that no in-scope stainless steel piping, piping 

components and piping elements exposed to a soil environment are present in the ESF

systems; therefore, it finds the applicant’s claim acceptable.

(3) LRA Section 3.2.2.2.3, item 3, associated with LRA Table 3.2.1, item 3.2.1-5, addresses 

loss of material due to pitting and crevice corrosion in BWR stainless steel and 

aluminum piping, piping components, and piping elements exposed to treated water. 

The applicant stated that this item is not applicable because it is only applicable to 

BWRs. The staff reviewed the SRP-LR and LRA Section 3.2 and noted that this item is 

associated only with BWRs; therefore, it finds the applicant’s claim acceptable.

(4) LRA Section 3.2.2.2.3.4, referenced by LRA Table 3.2.1, item 3.2.1-6, addresses 

stainless steel and copper-alloy piping, piping components, and piping elements 

exposed to lubricating oil, which are being managed for loss of material due to pitting 

and crevice corrosion by the Lubricating Oil Analysis and One-Time Inspection 

Programs. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the One-Time Inspection Program will be used to verify the effectiveness of 

the Lubricating Oil Analysis Program to manage loss of material through examination of 

susceptible locations in stainless steel piping components in the RHR and SI systems, 

copper-alloy piping components and copper-alloy heat exchanger components in the SI

system, and stainless steel heat exchanger components in the SI system. In addition, 

the applicant stated that MIC will be managed on the stainless steel piping components 

exposed to lubricating oil in the RHR and SI systems as well as stainless steel heat 

exchanger components exposed to lubricating oil in the SI system.

The staff reviewed LRA Section 3.2.2.2.3.4 against the criteria in SRP-LR 

Section 3.2.2.2.3, item 4, which states loss of material from pitting and crevice corrosion 

could occur for stainless steel and copper-alloy piping, piping components, and piping 

elements exposed to lubricating oil. The SRP-LR also states that the existing program 

relies on the periodic sampling and analysis of lubricating oil to maintain contaminants 

within acceptable limits, thereby preserving an environment that is not conducive to 

corrosion. The SRP-LR further states that control of lube oil contaminants may not 

always have been adequate to preclude corrosion; therefore, the effectiveness of 

lubricating oil control should be confirmed to ensure that corrosion does not occur. The 

SRP-LR also states that the GALL Report recommends further evaluation to verify the 

effectiveness of the Lubricating Oil Program for which a one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion 

does not occur and that the component’s intended function will be maintained during the 

period of extended operation.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.2.1-6, that staff finds 

the applicant’s proposal to manage aging using the One-Time Inspection Program to 

verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the 

Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Time Inspection Program will be used to 
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examine stainless steel piping and copper-alloy piping components to verify the 

effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance 

criteria in SRP-LR Section 3.2.2.2.3, item 4; therefore, the applicant’s AMR is consistent 

with the GALL Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.3, item 4, criteria. For the items that apply to LRA 

Section 3.2.2.2.3.4, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

(5) LRA Section 3.2.2.2.3.5, associated with LRA Table 3.2.1, item 3.2.1-7, addresses loss 

of material from pitting and crevice corrosion in partially encased stainless steel tanks 

exposed to raw water due to cracking of the perimeter seal from weathering. The 

applicant stated that this item is not applicable because there are no partially encased 

stainless steel tanks in the ESF systems exposed to raw water. The staff reviewed LRA 

Sections 2.3.2 and 3.2 and the applicant’s UFSAR and confirmed that no in-scope 

partially encased stainless steel tanks exposed to raw water are present in the ESF

systems; therefore, it finds the applicant’s claim acceptable.

(6) LRA Section 3.2.2.2.3.6, associated with LRA Table 3.2.1, item 3.2.1-8, addresses loss 

of material due to pitting and crevice corrosion in stainless steel piping, piping 

components, piping elements, and tanks exposed to condensation (internal). The 

applicant stated that this item is not applicable because its ESF systems do not contain 

stainless steel piping, piping components, piping elements, and tanks exposed to 

condensation (internal). The staff reviewed LRA Sections 2.3.2 and 3.2 and the UFSAR 

and confirmed that no in-scope stainless steel piping, piping components, piping 

elements, and tanks exposed to condensation (internal) are present in the ESF systems; 

therefore, it finds the applicant’s claim acceptable.

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling 

The staff reviewed LRA Section 3.2.2.2.4 against the following criteria in SRP-LR 

Section 3.2.2.2.4:

(1) LRA Section 3.2.2.2.4.1, is associated with LRA Table 3.2.1, item 3.2.1-9, and 

addresses steel, stainless steel, and copper heat exchanger tubes exposed to 

lubricating oil, which are being managed for reduction of heat transfer due to fouling by 

the Lubricating Oil Analysis and One-Time Inspection Programs. 

The criteria in SRP-LR Section 3.2.2.2.4, item 1, state that reduction of heat transfer due 

to fouling may occur in steel, stainless steel, and copper-alloy heat exchanger tubes 

exposed to lubricating oil. The SRP-LR also states that the existing AMP controls lube 

oil chemistry to mitigate this aging effect, and the effectiveness should be confirmed

because the lube oil chemistry controls may not be effective in precluding fouling. The 

SRP-LR further states that a one-time inspection of selected components at susceptible 

locations is an acceptable method to verify the program’s effectiveness. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that it will implement 

the One-Time Inspection Program to verify the effectiveness of the Lubricating Oil 

Analysis Program to manage loss of heat transfer due to fouling in the chemical and 

volume control, diesel generator, and SI systems.
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The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.2.1-9, the staff finds 

that the applicant has met the further review criteria, and the applicant’s proposal to 

manage aging using the specified AMPs acceptable because the Lubricating Oil 

Analysis Program includes periodic sampling and analysis of lubricating oil to maintain 

contaminants within acceptable limits. Additionally, the One-Time Inspection Program 

will verify the effectiveness of the Lubricating Oil Analysis Program to manage this aging 

effect.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.4, item 1, criteria. For those items that apply to LRA 

Section 3.2.2.2.4.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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 3.2.2.2.4.2, is associated with LRA Table 3.2.1, item 3.2.1-10, and 

addresses stainless steel heat exchanger tubes exposed to treated water. The applicant 

stated that this item is not applicable because there are no stainless steel heat 

exchanger tubes exposed to treated water in the ESF systems. To verify this, the staff 

reviewed LRA Section 3.2 and noted that, although there were no in-scope stainless 

steel heat exchanger tubes exposed to treated water in the ESF systems, there were 

several systems with heat exchanger tubes exposed to treated borated water. Since the 

related item, EP-34, from SRP-LR Table 3.2.1, was derived from a previous SER for 

heat exchanger tubes exposed to treated borated water, the applicant’s determination 

that this item was not applicable did not appear appropriate. By letter dated 

February 24, 2011, the staff issued RAI 3.2.2.2.4.2-1 requesting that the applicant 

provide additional bases regarding the non-applicability of this item and address how the 

reduction in heat transfer would be managed for heat exchanger tubes identified as 

having a heat transfer function.

In its response dated March 22, 2011, the applicant stated that the “treated borated 

water” environment is different than the “treated water” environment. The applicant 

provided the definitions of treated water and treated boated water from the GALL Report 

Section IX.D, which states that, unlike the PWR reactor coolant environment (treated 

borated water), the BWR reactor coolant environment (treated water) does not contain 

boron, a recognized corrosion inhibitor. The applicant also referred to GALL Report 

Section IX.F, which describes fouling as an accumulation of deposits that may be due to 

biofouling or particulate fouling, such as sediment, silt, or corrosion products. The 

applicant further stated that none of the heat exchanger tubes in LRA Section 3.2 are 

exposed to treated water; however, the containment building spray and RHR heat 

exchanger tubes have an internal environment of treated borated water and an external 

environment of closed-cycle cooling water. The applicant also stated that reduction of 

heat transfer was applied to the tube side exposed to the closed-cycle cooling water but 

not to the tube side exposed to treated borated water, and it provided the following 

basis:

• The Seabrook Station’s determination that reduction of heat transfer is 

not an aging effect in treated borated water environment is based on plant 

and industry operating experience. Seabrook Station is not aware of any 
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fouling in treated borated water environment leading to reduction of heat 

transfer in stainless steel heat exchanger tubes. This conclusion is 

consistent with NUREG-1801 Rev.1. NUREG-1801 Rev 1 does not 

identify reduction of heat transfer as an aging effect for stainless steel 

heat exchanger tubes in treated borated water environment.

• Fouling of the stainless steel heat exchanger tubes on the treated borated 

water side would only occur through the buildup of corrosion products. 

Since the Seabrook Station’s treated borated water contains boron, a 

corrosion inhibitor, corrosion product buildup resulting in reduction of heat 

transfer in treated borated water environment is not a credible aging 

effect/mechanism. This is further validated by NUREG-1801, Rev 1 line 

items V.A-27, and V.D1-30 (NUREG-1800, Table 3.2-1, items 48 and 49), 

which state that Water Chemistry Program alone (for PWR primary water) 

is adequate for managing loss of material in stainless steel components 

exposed to treated borated water indicating that corrosion is not expected 

to occur in stainless steel components exposed to treated borated water. 

In the absence of corrosion, corrosion product buildup will not occur. 

Additionally, since reduction of heat transfer in treated borated water is 

not identified as a potential aging effect, no line items for reduction of heat 

transfer in treated borated water appear in the LRA.

• Seabrook’s conclusion is consistent with NUREG-1810 Rev 1 and Rev 2, 

as well as the NRC staff conclusions as stated in Beaver Valley Final 

SER (Section 3.2.2.3.2) and Prairie Island SER (Section 3.2.2.2.4).

The staff reviewed the applicant’s response and the cited portions of the GALL Report. 

The staff noted that, although the GALL Report, Revision 1, states that boron is a 

recognized corrosion inhibitor, the GALL Report, Revision 2, deleted that discussion 

from the definition of treated water. The staff also reviewed AMR items V.A-27 and 

V.D1-30 (SRP-LR, Table 3.2-1 item 49) and noted that the GALL Report credits Water 

Chemistry to manage loss of material due to pitting and crevice corrosion in stainless 

components exposed to treated borated water. The staff also noted that, although the 

basis for adding these items in the GALL Report, Revision 1, stated that a significant 

loss of material was not expected, the potential for corrosion and consequently corrosion 

product buildup still exists. The staff also reviewed the Beaver Valley and Prairie Island 

SERs and the associated LRAs cited by the applicant and noted that both LRAs 

identified reduction of heat transfer for stainless steel heat exchanger tubes in a treated 

borated water environment as an aging effect requiring managing. Based on the above, 

by letter dated May 23, 2011, the staff issued RAI 3.2.2.2.4.2-1A, requesting the 

applicant to provide its justification to demonstrate that heat exchanger tubes which have 

a heat transfer intended function do not need to include a reduction of heat transfer 

aging effect requiring management. In addition, the RAI requested the applicant to 

provide the plant-specific and industry operating experience cited in its previous 

response demonstrating that reduction in heat transfer was not a credible aging effect for 

the components in question. 

In its response dated June 2, 2011, the applicant revised LRA Tables 3.2.2-2 and 3.2.2-

3 to include AMR items for stainless steel heat exchanger components exposed to 

treated borated water that are being managed for reduction of heat transfer by the Water 

Chemistry Program. The AMR items cite generic note H and plant-specific note 4, which 

states that reduction of heat transfer due to fouling is not in the GALL Report for this 
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component, material and environment combination. The staff finds the applicant’s 

response unacceptable because the guidance in the SRP-LR and GALL Report was 

revised in LR-ISG-2011-01, “Aging Management of Stainless Steel Structures and 

Components in Treated Borated Water,” to add the One-Time Inspection Program to 

verify the effectiveness of the Water Chemistry Program to manage stainless steel 

components for loss of material, cracking, and reduction of heat transfer in treated 

borated water environments that are not controlled to low oxygen levels. The staff noted 

that, prior to the issuance of LR-ISG-2011-01, the SRP-LR and GALL Report guidance 

inappropriately credited the boron in borated water as a corrosion inhibitor in place of 

other aging management activities.

By letter dated May 29, 2012, the staff issued RAI 3.2.1.48-1 requesting that the 

applicant describe how the effectiveness of the Water Chemistry Program to manage 

reduction of heat transfer will be verified for stainless steel components exposed to 

treated borated water with greater than 5 ppb oxygen. Pending the staff’s review of the 

applicant’s response, this issue is identified as Open Item OI 3.2.2.1-1.

3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 

LRA Section 3.2.2.2.5 is associated with LRA Table 3.2.1, item 3.2.1-11, and addresses 

hardening and loss of strength due to elastomer degradation. The applicant states that this 

aging effect is not applicable to Seabrook because this item is applicable to BWRs only. 

SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer 

degradation could occur in elastomer seals and components associated with the BWR standby 

gas treatment system ductwork and filters exposed to uncontrolled indoor air. The staff finds 

that SRP-LR Section 3.2.2.2.5 is not applicable because Seabrook is a PWR, and the staff 

guidance in this SRP-LR section is only applicable to BWRs.

3.2.2.2.6 Loss of Material Due to Erosion 

LRA Section 3.2.2.2.6 is associated with LRA Table 3.2.1, item 3.2.1-12, and addresses the 

stainless steel high pressure pump minimum flow orifices in the CVCS exposed to treated 

borated water, which the applicant proposed to manage for loss of material due to erosion with 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. 

The criterion in SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion could occur 

in high-pressure safety injection (HPSI) pump minimum flow orifices exposed to treated borated 

water. The SRP-LR also states that a plant-specific AMP should be evaluated for erosion of the 

orifice due to extended use of the centrifugal HPSI pump for normal charging. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is adequate to manage the 

aging effect in these components.

In its review of components associated with LRA Table 3.2.1, item 3.2.1-12, the staff noted that 

the only components associated with this item are the minimum flow orifices downstream of the 

two centrifugal charging and high-head injection pumps in the CVCS. The staff also noted that 

the applicant proposed to manage the aging effect for these components through the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff 

further noted that this program consists of inspections of opportunity, performed during 

pre-planned periodic system and component surveillances or during maintenance activities, 

when the systems are opened and the surfaces are made accessible for visual inspection. 

Based on the CVCS piping configuration and the limited number of charging pump minimum 
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flow orifices, it was not clear to the staff if opportunities for inspection of these components 

occur routinely, in accordance with scheduled preventive maintenance or periodic surveillance, 

or if opportunities for inspection are normally available only during corrective maintenance after 

degradation or failure of the component may have occurred.

By letter dated January 5, 2011, the staff issued RAI 3.2.2.2.6-01 requesting the applicant to 

explain whether opportunities for inspection of the charging pump bypass orifices are routinely 

available. The staff also asked the applicant to justify how the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program will be capable of detecting 

degradation in these components before failure of their intended function if routine opportunities 

for inspection are not available.

In its response dated February 3, 2011, the applicant stated that the CVCS high-pressure pump 

minimum flow orifices are welded in place and are not routinely available for internal visual 

inspection. The applicant further stated that the minimum flow orifices have multiple internal 

plates with multiple orifice holes and that these design features of the minimum flow orifices 

make volumetric examination for dimensional comparison impractical. The applicant proposed 

to manage loss of material due to erosion in minimum flow orifices with the Water Chemistry 

Program. The applicant also stated that its TSs require quarterly inservice testing of the CVCS 

high-pressure pumps and that this testing can provide early indication of orifice degradation. 

The applicant revised LRA Table 3.3.2-3, LRA Section 3.2.2.2.6, and LRA Table 3.2.1, 

item 3.2.1-12, to state that the Water Chemistry Program, rather than the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program, will be used to manage 

loss of material due to erosion in CVCS stainless steel orifices exposed to treated borated 

water.

The staff’s evaluation of the applicant’s Water Chemistry Program is documented in SER 

Section 3.0.3.1.2. The staff noted that the applicant’s Water Chemistry Program is consistent 

with GALL Report AMP XI.M2, “Water Chemistry.” The staff also noted that the GALL Report 

credits the Water Chemistry Program with providing management for loss of material due to 

corrosion in stainless steel components exposed to a treated borated water environment; 

however, the GALL Report does not credit the Water Chemistry Program with managing loss of 

material due to erosion. The staff further noted that the applicant had neither proposed nor 

committed to any activity that would confirm effectiveness of the Water Chemistry Program to 

mitigate erosion in the stainless steel CVCS high-pressure pump minimum flow orifice.

By letter dated March 7, 2011, the staff issued RAI 3.2.2.2.6-02 asking the applicant to include 

in the AMP(s) for these components an inspection or testing activity to confirm effectiveness of 

the Water Chemistry Program to mitigate or prevent unacceptable loss of material due to 

erosion in the stainless steel CVCS high-pressure pump minimum flow orifices.

In its response dated April 5, 2011, the applicant stated that it will credit its high-pressure SI 

pump (CVCS charging pump) TS Performance Monitoring Program to detect loss of material 

due to erosion in the minimum flow orifices and to confirm effectiveness of the Water Chemistry 

Program for this component. The applicant stated the following:

• Its TSs require quarterly testing of the CVCS charging pump.

• The pump is always tested in the same lineup where the flow path is only through the 

minimum flow orifice.
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• Pump flow and differential pressure are measured, recorded, and compared with 

acceptance criteria.

• If the minimum flow orifice should experience erosion to the extent that the acceptance 

criteria are not met, then restoration of the pump to operable status requires appropriate 

corrective actions per the Corrective Action Program.

The applicant revised the LRA by adding a plant-specific note in LRA Table 3.3.2-3, revising 

LRA Section 3.2.2.2.6, and adding a new commitment (Commitment No. 63) to LRA 

Section A.3. These changes in the LRA state that the TS Performance Monitoring Program for 

the high-pressure safety injection pump (CVCS charging pump) is credited to detect loss of 

material due to erosion in the minimum flow orifices and provide a commitment to ensure that 

the quarterly CVCS charging pump testing is continued during the period of extended operation. 

Appropriate procedures are revised to add a caution stating that an increase in CVCS charging 

pump minimum flow may be indicative of erosion in the minimum flow orifice.

The staff noted that SRP-LR Appendix A, Section A.1.1, states that a Performance Monitoring 

Program, which tests the ability of a structure or component to perform its intended function, is 

an acceptable method for aging management. The staff also noted that the applicant will use its 

existing quarterly TS Performance Monitoring Program for the CVCS high-pressure SI pump 

(charging pump) to confirm effectiveness of the Water Chemistry Program in mitigating or 

preventing unacceptable loss of material due to erosion in the stainless steel minimum flow 

orifices exposed to treated borated water. The staff further noted that the applicant added a 

new commitment (Commitment No. 63) to ensure that quarterly CVCS charging pump testing is 

continued during the period of extended operation.

The staff finds that the applicant has met the further evaluation criteria and that the applicant’s 

proposal to manage aging using the Water Chemistry Program and performance monitoring of 

the CVCS charging pump is acceptable for the following reasons:

• Properly maintained water chemistry will mitigate erosion in the CVCS charging pump 

minimum flow orifice.

• Performance monitoring will be used to ensure effectiveness of the Water Chemistry 

Program for this component.

• Performance monitoring is one of the four general types of AMPs recommended in 

SRP-LR, Appendix A.

Based on its review above, the staff finds the applicant’s responses to RAIs 3.2.2.2.6-01 and 

3.2.2.2.6-02 acceptable, and the staff’s concerns described in these RAIs are resolved.

Based on the program identified, and the applicant’s commitment to monitor performance, the 

staff concludes that the applicant’s program meets SRP-LR Section 3.2.2.2.6 criteria. For those 

items that apply to LRA Section 3.2.2.2.6, the staff determined that the LRA is consistent with 

the GALL Report, and the applicant 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).

3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling

LRA Section 3.2.2.2.7, associated with LRA Table 3.2.1, item 3.2.1-13, addresses loss of 

material due to general corrosion and fouling in steel drywell and suppression chamber spray 
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system nozzle and flow orifice exposed to air-indoor uncontrolled (internal). The applicant 

stated that this item is not applicable because it is only applicable to BWRs. The staff reviewed 

SRP and LRA Section 3.2 and noted that this item is associated only with BWRs; therefore, it 

finds the applicant’s claim acceptable.

3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.2.2.2.8 against the following criteria in SRP-LR 

Section 3.2.2.2.8:

(1) LRA Section 3.2.2.2.8.1, associated with LRA Table 3.2.1, item 3.2.1-14, addresses loss 

of material due to general, pitting, and crevice corrosion in BWR steel piping, piping 

components, and piping elements exposed to treated water. The applicant stated that 

this item is not applicable because it is only applicable to BWRs. The staff reviewed the 

SRP-LR and LRA Section 3.2 and noted that this item is associated only with BWRs; 

therefore, it finds the applicant’s claim acceptable.

(2) LRA Section 3.2.2.2.8.2, associated with LRA Table 3.2.1, item 3.2.1-15, addresses loss 

of material due to general, pitting, and crevice corrosion in internal surfaces of steel 

containment isolation piping, piping components, and piping elements exposed to 

treated water. The applicant stated that this item is not applicable because its ESF

systems do not contain steel containment isolation piping, piping components, and 

piping elements exposed to treated water. The staff reviewed LRA Sections 2.3.2 and 

3.2 and the UFSAR and confirmed that no in-scope steel containment isolation piping, 

piping components, and piping elements exposed to treated water are present in the 

ESF systems; therefore, it finds the applicant’s claim acceptable.

(3) LRA Section 3.2.2.2.8.3, referenced by LRA Table 3.2.1, item 3.2.1-16, addresses steel 

piping, piping components, and piping elements exposed to lubricating oil, which are 

being managed for loss of material due to general, pitting, and crevice corrosion by the 

Lubricating Oil Analysis and One-Time Inspection Programs. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that the One-Time Inspection 

Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program 

to manage loss of material due to general, pitting, and crevice corrosion through 

examination of susceptible locations in steel piping components in the RHR and SI

systems. In addition, the applicant stated that the One-Time Inspection Program will 

also be used to verify the effectiveness of the Lubricating Oil Analysis Program to 

manage loss of material due to general, pitting, and crevice corrosion through 

examination of susceptible locations in steel tanks in the SI system.

The staff reviewed LRA Section 3.2.2.2.8.3 against the criteria in SRP-LR 

Section 3.2.2.2.8, item 3, which states that loss of material due to general, pitting, and 

crevice corrosion could occur for steel piping, piping components, and piping elements 

exposed to lubricating oil. The SRP-LR also states that the existing AMP relies on 

periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

The SRP-LR further states that control of lube oil contaminants may not always have 

been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil 

control should be confirmed to ensure that corrosion does not occur. The SRP-LR also 

states that the GALL Report recommends further evaluation of programs to verify the 

effectiveness of the Lubricating Oil Program for which a one-time inspection of select 

components at susceptible locations is an acceptable method to ensure that corrosion 
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does not occur and that the component’s intended function will be maintained during the 

period of extended operation.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.2.1-16, the staff finds 

the applicant’s proposal to manage aging using the One-Time Inspection Program to 

verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the 

Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Time Inspection Program will be used to 

examine steel piping, piping components, and piping elements to verify the effectiveness 

of the Lubricating Oil Analysis Program. This satisfies the acceptance criteria in SRP-LR 

Section 3.2.2.2.8, item 3; therefore, the applicant’s AMR is consistent with the GALL 

Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.8, item 3, criteria. For the line items that apply to LRA 

Section 3.2.2.2.8.3, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant demonstrated that the effect 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).

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion

LRA Section 3.2.2.2.9 is associated with LRA Table 3.2.1, item 3.2.1-17, and addresses loss of 

material due to general, pitting, crevice and MIC in steel (with or without coating or wrapping) 

piping, piping components, and piping elements exposed to a soil environment. The applicant 

stated that this item is not applicable because there are no steel (with or without coating or 

wrapping) piping, piping components, and piping elements in the ESF systems exposed to soil. 

The staff reviewed LRA Sections 2.3 and 3.2 and the applicant’s UFSAR and confirmed that no 

in-scope steel piping, piping components, and piping elements exposed to a soil environment 

are present in the ESF systems; therefore, it finds the applicant’s determination acceptable.

3.2.2.2.10 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 Aging Management Review Results Not Consistent with or Not Addressed in 

the GALL Report

In LRA Tables 3.2.2-1 through 3.2.2-4, 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 3.2.2-4, via Notes F–J, the applicant indicated which 

combinations of component type, material, environment, and AERM do 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 if the applicant 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 Combustible Gas Control System—Summary of Aging Management Review—LRA 

Table 3.2.2-1

In LRA Tables 3.2.2-1, 3.2.2-2, 3.2.2-3, and 3.3.2-4, the applicant stated that the stainless steel 

bolting exposed to air-indoor is being managed for loss of preload by the Bolting Integrity 

Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel bolting exposed to air-indoor is not specifically addressed in the GALL 

Report, Table IX.E, the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to 

a variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion and cracking due to SCC. The staff noted that the environment of interest, air-indoor, 

would not induce SCC or loss of material in stainless steel material because stainless steel is 

inherently resistant to corrosion in the air-indoor environment. Therefore, the aging effect of 

concern is loss of preload, which is addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of material of stainless steel bolting exposed 

to air-indoor in the ESF system exposed to indoor air, the GALL Report has items for other 

material bolting exposed to air-indoor managed by the Bolting Integrity Program. The staff finds 

the applicant’s proposal to manage aging using the Bolting Integrity Program acceptable 

because the Bolting Integrity Program conducts bolting assembly and maintenance control such 

as application of appropriate gasket alignment, torque, lubricants, and preload. It also inspects 

for leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be 

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

for the period of extended operation.

In LRA Tables 3.2.2-1, 3.2.2-3, and 3.2.2-4, the applicant stated that for glass piping elements 

exposed to air-with borated water leakage (external), there is no aging effect, and no AMP is 

proposed. The AMR item cites generic note G. The staff reviewed the associated items in the 

LRA and confirmed that no aging effect is applicable for this component, material, and 

environment combination because the GALL Report, item V.F-9 states that for an environment 

of treated borated water, there is no AERM and no recommended AMP, and the air with borated 

water leakage environment is no more severe than the treated borated water environment.
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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 addressed in the GALL 

Report. The staff finds 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).

3.2.2.3.2 Containment Building Spray System—Summary of Aging Management Review—

LRA Table 3.2.2-2 

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.2.2.3.1.

In LRA Table 3.2.2-2, the applicant stated that elastomer flexible hoses exposed to air with 

borated water leakage (external) are being managed for hardening and loss of strength by the 

External Surfaces Monitoring Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report, Table IX.C, indicates that elastomers are susceptible to hardening and loss of 

strength at temperatures over 95 °F (35 °C), which is addressed in the AMR item. The GALL 

Report, item VII.A3-1, also indicates that elastomers are susceptible to hardening when 

exposed to treated borated water.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff noted that the program includes non-visual tactile 

examinations, such as scratching, which will determine if scale or residues are present or 

determine if there is a breakdown of material. The staff also noted that the program includes 

bending and folding of the elastomer to detect cracking that initiates at the surface. The staff 

further noted that the program includes stretching and pressing to determine the resistance of 

the material to hardening effects and pressing to gauge the materials resiliency to maintain its 

strength. The staff finds the applicant’s proposal to manage aging using the External Surfaces 

Monitoring Program acceptable because the program includes periodic visual inspections as 

well as non-visual tactile examinations, which are capable of detecting hardening and loss of 

strength by detecting discontinuities and imperfections on the surface of the component.

In LRA Table 3.2.2-2, the applicant stated that the stainless steel piping and fittings exposed to 

air-outdoor (external) are being managed for loss of material by the External Surfaces 

Monitoring Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report, Table IX.C, states that stainless steels are susceptible to loss of material due 

to pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment 

of interest, air-outdoor (external), would be expected to contain higher levels of chlorides due to 

the site’s relative proximity to the ocean, which is known to induce SCC. By letter dated 

February 24, 2011, the staff issued RAI 3.3-1 requesting that the applicant explain why 

atmospheric chloride-induced SCC is not considered to be an applicable aging effect for 

stainless steel components exposed to outdoor-air and explain how SCC will be managed if it is 

determined to be an applicable aging affect.
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In its response dated March 22, 2011, the applicant stated that SCC has been added as an 

aging mechanism for stainless steel components exposed to air-outdoor environment. The 

applicant added a new item to manage cracking by the External Surfaces Monitoring Program. 

The staff finds the applicant’s response acceptable because the applicant has modified the LRA 

to include SCC as an applicable aging effect for stainless steel components exposed to 

outdoor-air and include SCC as an aging effect to be managed by the External Surfaces 

Monitoring Program, which includes visual inspection that is a capable technique to detect SCC. 

The staff’s concern described in RAI 3.3-1 is resolved.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff finds the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable because the program uses periodic visual 

inspections that would detect loss of material and detect SCC prior to loss of 

component-intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.2.2.3.3 Residual Heat Removal System—Summary of Aging Management Review—LRA 

Table 3.2.2-3

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.2.2.3.1.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external) with no AERM and no recommended AMP, citing generic note G, is documented in 

Section 3.2.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.2.2.3.4 Safety Injection System—Summary of Aging Management Review—LRA 

Table 3.2.2-4

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.2.2.3.1.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external) with no AERM and no recommended AMP, citing generic note G, is documented in 

Section 3.2.2.3.1.
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On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.2.3 Conclusion

The staff concludes that 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).

3.3

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

auxiliary system components and component groups of the following systems:

Aging Management of Auxiliary Systems 

• auxiliary boiler

• boron recovery system

• chemical and volume control system

• chlorination system

• containment air handling system

• containment air purge system

• containment enclosure air handling system

• containment online purge system 

• control building air handling system

• demineralized water system

• dewatering system

• diesel generator

• diesel generator air handling system

• emergency feed water pump house air handling system

• fire protection system

• fuel handling system

• fuel oil system

• fuel storage building air handling system 

• hot water heating system 

• instrument air system

• leak detection system

• mechanical seal supply system

• miscellaneous equipment system

• nitrogen gas system 

• oil collection for reactor coolant pumps system

• plant floor drain system

• potable water system

• primary auxiliary building air handling system

• primary component cooling water system
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• radiation monitoring system

• reactor makeup water system

• release recovery system

• resin sluicing system

• roof drains system

• sample system

• screen wash system

• service water system

• service water pump house air handling system

• spent fuel pool cooling system

• switchyard

• valve stem leak-off system

• vent gas system

• waste gas system

• waste processing liquid system

• waste processing liquid drains system

3.3.1 Summary of Technical Information in the Application

LRA Section 3.3 provides AMR results for the auxiliary system 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 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.

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine if the applicant provided sufficient information 

to demonstrate that it will adequately manage the effects of aging for the auxiliary systems 

components within the scope of license renewal and subject to an AMR 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 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. SER Section 3.3.2.1 

documents the staff’s evaluations, and SER Section 3.0.3 documents the staff’s evaluations of 

the AMPs.

The staff also reviewed AMRs consistent with the GALL Report for which further evaluation is 

recommended. The staff confirmed that the applicant’s further evaluations were consistent with 

the SRP-LR Section 3.3.2.2 acceptance criteria. SER Section 3.3.2.2 documents the staff’s 

evaluations.
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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 if the applicant identified all 

plausible aging effects and if the aging effects listed were appropriate for the material and 

environment combinations specified. SER Section 3.3.2.3 documents the staff’s evaluations.

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 3.1-1 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 system components in the GALL Report 

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel cranes—

structural girders 

exposed to airindoor uncontrolled 

(external) 

(3.3.1-1)

Cumulative 

fatigue damage

TLAA to be 

evaluated for 

structural girders of 

cranes. See the 

SRP-LR, 

Section 4.7 for 

generic guidance 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes TLAA Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.1)

Steel and stainless 

steel piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to airindoor uncontrolled, 

treated borated 

water or treated 

water

(3.3.1-2)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes TLAA Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water

(3.3.1-3)

Reduction of 

heat transfer 

due to fouling

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry

Consistent with 

GALL Report (see 

SER Sections

3.3.2.2.2 and 

3.3.2.3.3)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to sodium 

pentaborate solution 

> 140 °F (> 60 °C )

(3.3.1-4)

Cracking due to 

SCC

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.2.3)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel and 

stainless clad steel 

heat exchanger 

components 

exposed to treated 

water > 140 °F 

(> 60 °C)

(3.3.1-5)

Cracking due to 

SCC

A plant-specific

AMP is to be 

evaluated.

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.3.2.2.3)

Stainless steel 

diesel engine 

exhaust piping, 

piping components, 

and piping elements 

exposed to diesel 

exhaust

(3.3.1-6)

Cracking due to 

SCC

A plant-specific

AMP is to be 

evaluated.

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.3)

Stainless steel nonregenerative heat 

exchanger 

components 

exposed to treated 

borated water 

> 140 °F (> 60 °C)

(3.3.1-7)

Cracking due to 

SCC and cyclic 

loading

Water Chemistry 

and a plant-specific 

verification 

program—An 

acceptable 

verification program 

is to include 

temperature and 

radioactivity 

monitoring of the 

shell side water and 

eddy current testing 

of tubes.

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.4)

Stainless steel 

regenerative heat 

exchanger 

components 

exposed to treated 

borated water 

> 140 °F (> 60 °C)

(3.3.1-8)

Cracking due to 

SCC and cyclic 

loading

Water Chemistry 

and a plant-specific 

verification 

program—The AMP 

is to be augmented 

by verifying the 

absence of cracking 

due to stress 

corrosion cracking 

and cyclic loading.

A plant-specific

AMP is to be 

evaluated.

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.4)

Stainless steel highpressure pump 

casing in PWR 

CVCS(3.3.1-9)

Cracking due to 

SCC and cyclic 

loading

Water Chemistry 

and a plant-specific 

verification 

program—The AMP 

is to be augmented 

by verifying the 

absence of cracking 

due to SCC and 

cyclic loading. A 

plant-specific AMP

is to be evaluated.

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.4)
Aging Management Review Results

3-278

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.3.1-10)

Cracking due to 

SCC and cyclic 

loading

Bolting Integrity—

The AMP is to be 

augmented by 

appropriate 

inspection to detect 

cracking if the bolts 

are not otherwise 

replaced during 

maintenance.

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.3.2.2.4)

Elastomer seals and 

components 

exposed to airindoor uncontrolled 

(internal/external)

(3.3.1-11)

Hardening and 

loss of strength 

due to elastomer 

degradation

A plant-specific

AMP is to be 

evaluated.

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

and External 

Surfaces 

Monitoring

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.5)

Elastomer lining 

exposed to treated 

water or treated 

borated water

(3.3.1-12)

Hardening and 

loss of strength 

due to elastomer 

degradation

A plant-specific 

AMP is to be 

evaluated.

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.5)

Boral, boron steel 

spent fuel storage 

racks neutronabsorbing sheets 

exposed to treated 

water or treated 

borated water

(3.3.1-13)

Reduction of 

neutronabsorbing 

capacity and 

loss of material 

due to general 

corrosion

A plant-specific

AMP is to be 

evaluated.

Yes Boral 

Monitoring

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.6)

Steel piping, piping 

component, and 

piping elements 

exposed to 

lubricating oil

(3.3.1-14)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.7)

Steel reactor coolant 

pump oil collection 

system piping, 

tubing, and valve 

bodies exposed to 

lubricating oil

(3.3.1-15)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Not applicable to 

Seabrook (see 

SER Section 

3.3.2.2.7)
Aging Management Review Results

3-279

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel reactor coolant 

pump oil collection 

system tank 

exposed to 

lubricating oil

(3.3.1-16)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Lubricating Oil 

Analysis and OneTime Inspection to 

evaluate the 

thickness of the 

lower portion of the 

tank

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.7)

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water

(3.3.1-17)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.2.7)

Stainless steel and 

steel diesel engine 

exhaust piping, 

piping components,

and piping elements 

exposed to diesel 

exhaust

(3.3.1-18)

Loss of 

material/general 

(steel only) and 

pitting and 

crevice 

corrosion

A plant-specific

AMP is to be 

evaluated.

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.7)

Steel (with or 

without coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil

(3.3.1-19)

Loss of material 

due to general, 

pitting, crevice, 

and MIC

Buried Piping and 

Tanks Surveillance

or

Buried Piping and 

Tanks Inspection

No

Yes

Buried Piping 

and Tanks 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.8) 

Steel piping, piping 

components, piping 

elements, and tanks 

exposed to fuel oil

(3.3.1-20)

Loss of material 

due to general, 

pitting, crevice, 

and MIC, and 

fouling

Fuel Oil Chemistry 

and One-Time 

Inspection

Yes Fuel Oil 

Chemistry and 

One-Time 

Inspection

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with

GALL Report (see 

SER Section 

3.3.2.2.9)

Steel heat 

exchanger 

components 

exposed to 

lubricating oil

(3.3.1-21)

Loss of material 

due to general, 

pitting, crevice, 

and MIC, and 

fouling

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.9)
Aging Management Review Results

3-280

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel with elastomer 

lining or stainless 

steel cladding 

piping, piping 

components, and 

piping elements 

exposed to treated 

water and treated 

borated water

(3.3.1-22)

Loss of material 

due to pitting 

and crevice 

corrosion (only 

for steel after 

lining/cladding 

degradation)

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.3.2.2.10)

Stainless steel and 

steel with stainless 

steel cladding heat 

exchanger 

components 

exposed to treated 

water

(3.3.1-23)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.2.10)

Stainless steel and 

aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.3.1-24)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.3.2.2.10)

Copper-alloy

heating, ventilation, 

and air conditioning

(HVAC) piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(external)

(3.3.1-25)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Bolting Integrity, 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components, or

External 

Surfaces 

Monitoring

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.10)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil

(3.3.1-26)

Loss of material 

due to pitting 

and crevice 

corrosion

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.10)
Aging Management Review Results

3-281

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel 

HVAC ducting and 

aluminum HVAC 

piping, piping 

components, and 

piping elements 

exposed to 

condensation

(3.3.1-27)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be

evaluated.

Yes Bolting Integrity, 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components,

External 

Surfaces 

Monitoring, and 

Compressed Air 

Monitoring

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.10)

Copper-alloy fire 

protection piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(internal)

(3.3.1-28)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

and 

Compressed Air 

Monitoring

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.10)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil

(3.3.1-29)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Buried Piping 

and Tanks 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.10)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to sodium 

pentaborate solution

(3.3.1-30)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.2.10)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.3.1-31)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.2.11)

Stainless steel, 

aluminum and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to fuel oil

(3.3.1-32)

Loss of material 

due to pitting, 

crevice, and 

MIC

Fuel Oil Chemistry 

and One-Time 

Inspection

Yes Fuel Oil 

Chemistry,

One-Time 

Inspection, and 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.12)
Aging Management Review Results

3-282

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil

(3.3.1-33)

Loss of material 

due to pitting, 

crevice, and 

MIC

Lubricating Oil 

Analysis and OneTime Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.12)

Elastomer seals and 

components 

exposed to airindoor uncontrolled 

(internal or external)

(3.3.1-34)

Loss of material 

due to wear

A plant-specific

AMP is to be 

evaluated.

Yes External 

Surfaces 

Monitoring and 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.2.13)

Steel with stainless 

steel cladding pump 

casing exposed to 

treated borated 

water

(3.3.1-35)

Loss of material 

due to cladding 

breach

A plant-specific 

AMP is to be 

evaluated.

Reference NRC 

IN 94-63, “Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.”

Yes Water 

Chemistry and 

One-Time 

Inspection

Not applicable to 

Seabrook (see 

SER Section 

3.3.2.2.14)

Boraflex spent fuel 

storage racks 

neutron-absorbing 

sheets exposed to 

treated water

(3.3.1-36)

Reduction of 

neutronabsorbing 

capacity due to 

boraflex 

degradation

Boraflex Monitoring No Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 140 °F

(> 60 °C)

(3.3.1-37)

Cracking due to 

SCC and 

IGSCC

BWR Reactor 

Water Cleanup 

System

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 140 °F 

(> 60 °C)

(3.3.1-38)

Cracking due to 

SCC

BWR SCC and 

Water Chemistry

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.1.1)
Aging Management Review Results

3-283

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel BWR 

spent fuel storage 

racks exposed to 

treated water 

> 140 °F (> 60 °C)

(3.3.1-39)

Cracking due to 

SCC

Water Chemistry No Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.1.1)

Steel tanks in diesel 

fuel oil system 

exposed to airoutdoor (external)

(3.3.1-40)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Aboveground Steel 

Tanks

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.3.1-41)

Cracking due to 

cyclic loading

and SCC

Bolting Integrity No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Steel closure bolting 

exposed to air with 

steam or water 

leakage

(3.3.1-42)

Loss of material 

due to general 

corrosion

Bolting Integrity No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Steel bolting and 

closure bolting 

exposed to airindoor uncontrolled 

(external) or airoutdoor (external)

(3.3.1-43)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Bolting Integrity No Bolting Integrity Consistent with 

GALL Report

Steel compressed 

air system closure 

bolting exposed to 

condensation

(3.3.1-44)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Bolting Integrity No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Steel closure bolting 

exposed to airindoor uncontrolled 

(external)

(3.3.1-45)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Bolting Integrity No Bolting Integrity Consistent with 

GALL Report

Stainless steel and 

stainless clad steel 

piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water > 140 °F 

(> 60 °C)

(3.3.1-46)

Cracking due to 

SCC

Closed-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)
Aging Management Review Results

3-284

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel piping, piping 

components, piping 

elements, tanks, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-47)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Steel piping, piping 

components, piping 

elements, tanks, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-48)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report (see 

SER section 

3.3.2.1)

Stainless steel and

steel with stainless 

steel cladding heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-49)

Loss of material 

due to MIC

Closed-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water

(3.3.1-50)

Loss of material 

due to pitting 

and crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Copper-alloy piping, 

piping components, 

piping elements, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-51)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Steel, stainless 

steel, and 

copper-alloy heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water

(3.3.1-52)

Reduction of 

heat transfer 

due to fouling

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report
Aging Management Review Results

3-285

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel compressed 

air system piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(internal)

(3.3.1-53)

Loss of material 

due to general 

and pitting 

corrosion

Compressed Air 

Monitoring

No Compressed Air 

Monitoring

Consistent with 

GALL Report

Stainless steel 

compressed air 

system piping, 

piping components, 

and piping elements 

exposed to internal 

condensation

(3.3.1-54)

Loss of material 

due to pitting 

and crevice 

corrosion

Compressed Air 

Monitoring

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

and External 

Surfaces 

Monitoring

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.2)

Steel ducting 

closure bolting 

exposed to airindoor uncontrolled 

(external)

(3.3.1-55)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring

Consistent with 

GALL Report

Steel HVAC ducting 

and components 

external surfaces 

exposed to airindoor uncontrolled 

(external)

(3.3.1-56)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.3)

Steel piping and 

components 

external surfaces 

exposed to airindoor uncontrolled 

(External)

(3.3.1-57)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring

Consistent with 

GALL Report

Steel external 

surfaces exposed to 

air-indoor

uncontrolled 

(external), airoutdoor (external), 

and condensation 

(external)

(3.3.1-58)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring and 

Inspection of 

Overhead 

Heavy Load 

and Light Load 

(Related to 

Refueling) 

Handling 

Systems

Consistent with 

GALL Report
Aging Management Review Results

3-286

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel heat 

exchanger 

components 

exposed to airindoor uncontrolled 

(external) or airoutdoor (external)

(3.3.1-59)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring

Consistent with 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to airoutdoor (external)

(3.3.1-60)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring

Consistent with 

GALL Report

Elastomer fire 

barrier penetration 

seals exposed to 

air-outdoor or airindoor uncontrolled

(3.3.1-61)

Increased 

hardness, 

shrinkage, and 

loss of strength 

due to 

weathering

Fire Protection No Fire Protection 

and Structural

Monitoring

Consistent with 

GALL Report (see 

SER section 

3.3.2.1.4)

Aluminum piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-62)

Loss of material 

due to pitting 

and crevice 

corrosion

Fire Protection No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Steel fire rated 

doors exposed to 

air-outdoor or airindoor uncontrolled

(3.3.1-63)

Loss of material 

due to wear

Fire Protection No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to fuel oil

(3.3.1-64)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Fire Protection and 

Fuel Oil Chemistry

No Fire Protection 

and Fuel Oil 

Chemistry

Consistent with 

GALL Report

Reinforced concrete 

structural fire 

barriers—walls, 

ceilings, and floors 

exposed to airindoor uncontrolled

(3.3.1-65)

Concrete 

cracking and 

spalling due to 

aggressive 

chemical attack, 

and reaction 

with aggregates

Fire Protection and 

Structures 

Monitoring Program

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Reinforced concrete 

structural fire 

barriers—walls, 

ceilings, and floors 

exposed to airoutdoor

(3.3.1-66)

Concrete 

cracking and 

spalling due to 

freeze thaw, 

aggressive 

chemical attack, 

and reaction 

with aggregates

Fire Protection and 

Structures 

Monitoring Program

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)
Aging Management Review Results

3-287

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Reinforced concrete 

structural fire 

barriers—walls, 

ceilings, and floors 

exposed to airoutdoor or air-indoor

uncontrolled

(3.3.1-67)

Loss of material 

due to corrosion 

of embedded 

steel

Fire Protection and 

Structures 

Monitoring Program

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.3.1-68)

Loss of material 

due to general, 

pitting, crevice, 

and MIC, and 

fouling

Fire Water System No Fire Water 

System and 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.5)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.3.1-69)

Loss of material 

due to pitting 

and crevice 

corrosion and 

fouling

Fire Water System No Fire Water 

System

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.6)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-70)

Loss of material 

due to pitting, 

crevice, and 

MIC, and fouling

Fire Water System No Fire Water 

System and 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.7)

Steel piping, piping 

components, and 

piping elements 

exposed to moist air 

or condensation 

(internal)

(3.3.1-71)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No Compressed Air 

Monitoring 

Program

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.8)

Steel HVAC ducting 

and components 

internal surfaces 

exposed to 

condensation 

(internal)

(3.3.1-72)

Loss of material 

due to general, 

pitting, crevice, 

and (for drip 

pans and drain 

lines) MIC

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report
Aging Management Review Results

3-288

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel crane 

structural girders in 

load handling 

system exposed to 

air-indoor

uncontrolled 

(external)

(3.3.1-73)

Loss of material 

due to general 

corrosion

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 and 

Structural 

Monitoring 

Program

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.9)

Steel cranes—rails 

exposed to airindoor uncontrolled 

(external)

(3.3.1-74)

Loss of material 

due to wear

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

GALL Report

Elastomer seals and 

components 

exposed to raw 

water

(3.3.1-75)

Hardening and 

loss of strength 

due to elastomer 

degradation and

loss of material 

due to erosion

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous

Piping and 

Ducting 

Components 

Program

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.10)

Steel piping, piping 

components, and 

piping elements 

(without lining/ 

coating or with 

degraded 

lining/coating) 

exposed to raw 

water

(3.3.1-76)

Loss of material 

due to general, 

pitting, crevice, 

and MIC, 

fouling, and 

lining/coating 

degradation

Open-Cycle 

Cooling Water 

System

No Buried Piping 

and Tanks 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.11)

Steel heat 

exchanger 

components 

exposed to raw 

water

(3.3.1-77)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

MIC, and fouling

Open-Cycle 

Cooling Water 

System

No Fire Water 

System

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.12)

Stainless steel, 

nickel alloy, and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-78)

Loss of material 

due to pitting 

and crevice 

corrosion

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.13)
Aging Management Review Results

3-289

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.3.1-79)

Loss of material 

due to pitting 

and crevice 

corrosion, and 

fouling

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components or 

Bolting Integrity

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.14)

Stainless steel and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-80)

Loss of material 

due to pitting, 

crevice, and 

MIC

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components or

Structural 

Monitoring

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.15)

Copper-alloy piping, 

piping components, 

and piping 

elements, exposed 

to raw water

(3.3.1-81)

Loss of material 

due to pitting, 

crevice, and 

MIC, and fouling

Open-Cycle 

Cooling Water 

System

No Buried Piping 

and Tanks 

Inspection and 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.16)

Copper-alloy heat 

exchanger 

components 

exposed to raw 

water

(3.3.1-82)

Loss of material 

due to pitting, 

crevice, 

galvanic, and 

MIC, and fouling

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Stainless steel and 

copper-alloy heat 

exchanger tubes 

exposed to raw 

water

(3.3.1-83)

Reduction of 

heat transfer 

due to fouling

Open-Cycle 

Cooling Water 

System

No Fire Water 

System

Consistent with 

GALL Report (see 

SER Section 

3.3.2.1.17)

Copper-alloy

> 15% Zn piping, 

piping components, 

piping elements, 

and heat exchanger 

components 

exposed to raw 

water, treated water, 

or closed-cycle

cooling water

(3.3.1-84)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Selective 

Leaching of 

Materials

Consistent with 

GALL Report
Aging Management Review Results

3-290

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil, raw 

water, treated water, 

or closed-cycle 

cooling water

(3.3.1-85)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Selective 

Leaching of 

Materials

Consistent with 

GALL Report

Structural steel (new 

fuel storage rack 

assembly) exposed 

to air-indoor

uncontrolled 

(external)

(3.3.1-86)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Structures 

Monitoring Program

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Boraflex spent fuel 

storage racks 

neutron-absorbing 

sheets exposed to 

treated borated 

water

(3.3.1-87)

Reduction of 

neutronabsorbing 

capacity due to 

boraflex 

degradation

Boraflex Monitoring No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Aluminum and 

copper-alloy

> 15% Zn piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage

(3.3.1-88)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Not applicable Not applicable to 

Seabrook (see 

SER section 

3.3.2.1.1)

Steel bolting and 

external surfaces 

exposed to air with 

borated water 

leakage

(3.3.1-89)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion

Consistent with 

GALL Report

Stainless steel and 

steel with stainless 

steel cladding 

piping, piping 

components, piping 

elements, tanks, 

and fuel storage 

racks exposed to 

treated borated 

water > 140 °F 

(> 60 °C)

(3.3.1-90)

Cracking due to 

SCC

Water Chemistry No Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report
Aging Management Review Results

3-291

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel and 

steel with stainless 

steel cladding 

piping, piping 

components, and 

piping elements 

exposed to treated 

borated water

(3.3.1-91)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry No Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report

Galvanized steel 

piping, piping 

components, and 

piping elements 

exposed to airindoor uncontrolled

(3.3.1-92)

None None No None Consistent with 

GALL Report

Glass piping 

elements exposed 

to air, air-indoor

uncontrolled 

(external), fuel oil, 

lubricating oil, raw 

water, treated water, 

and treated borated 

water

(3.3.1-93)

None None No None Consistent with 

GALL Report

Stainless steel and 

nickel-alloy piping, 

piping components, 

and piping elements 

exposed to airindoor uncontrolled 

(external)

(3.3.1-94)

None None No None Consistent with 

GALL Report

Steel and aluminum 

piping, piping 

components, and 

piping elements 

exposed to airindoor controlled 

(external)

(3.3.1-95)

None None No None Consistent with 

GALL Report 

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.3.1-96)

None None No None Consistent with 

GALL Report 
Aging Management Review Results

3-292

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel, stainless 

steel, aluminum, 

and copper-alloy

piping, piping 

components, and 

piping elements 

exposed to gas

(3.3.1-97)

None None No None Consistent with 

GALL Report 

Steel, stainless 

steel, and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to dried air

(3.3.1-98)

None None No None Consistent with 

GALL Report 

Stainless steel and 

copper-alloy

< 15% Zn piping, 

piping components, 

and piping elements

exposed to air with 

borated water 

leakage

(3.3.1-99)

None None No None Consistent with 

GALL Report 

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 Aging Management Review 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 Steel Tanks Program

• Bolting Integrity Program 

• Boric Acid Corrosion Program 

• Buried Piping and Tanks Inspection Program 

• Closed-Cycle Cooling Water System Program 

• Compressed Air Monitoring Program
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• External Surfaces Monitoring Program 

• Fuel Oil Chemistry Program 

• Fire Protection Program 

• Fire Water System Program 

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program

• Lubricating Oil Analysis Program

• One-Time Inspection Program 

• Open-Cycle Cooling Water System Program

• Selective Leaching of Materials Program

• ASME Code Section XI ISI, Subsections IWB, IWC, and IWD Program

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping

• Water Chemistry Program 

LRA Tables 3.3.2-1 through 3.3.2-45 summarize AMRs for the auxiliary system components 

and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine if the plant-specific components in these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR item describing how the information in the tables 

aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A–E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these items to verify consistency with the GALL Report and the validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff reviewed these items to verify consistency with the 

GALL Report and to ensure that it had reviewed and accepted the identified exceptions to the 

GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the 

site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

items to verify consistency with the GALL Report. The staff also determined whether the AMR 
Aging Management Review Results

3-294

item of the different component applied to the component under review and whether the AMR 

was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the AMP identified in the GALL Report. The staff reviewed 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 exceptions 

to the GALL Report AMPs was reviewed and accepted by the staff. The staff also determined 

whether the AMP identified by the applicant was consistent with the AMP identified in the GALL 

Report and whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff reviewed these items 

to verify consistency with the GALL Report and determined whether the identified AMP would 

manage the aging effect consistent with the AMP identified in the GALL Report and whether the 

AMR was valid for the site-specific conditions.

The staff 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 3.2.1-48, addresses stainless steel or stainless steel clad piping, piping 

components, piping elements, and tanks exposed to treated borated water greater than 140 °F 

(60 °C), which are being managed for cracking due to SCC. The LRA credits the Water 

Chemistry Program to manage the aging effect. The GALL Report recommends GALL Report 

AMP XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately managed. 

The associated AMR items cite generic Notes A and C.

In its review of components associated with item 3.2.1-48 for which the applicant cited generic 

note C, the staff noted that LRA Table 3.2.2-3 indicates that stainless steel heat exchanger 

components (1-RH-E-188A and 188B tubes, 1-RH-E-9A and 9B channel head, 1-RH-E-9A and 

9B tube sheet, and 1-RH-E-9A and 9B tubes) are subject to cracking due to SCC. The staff 

also noted that the applicant stated that the aging effect is managed by the Water Chemistry 

Program. The staff further noted that the GALL Report does not contain a specific AMR item for 

cracking due to SCC of stainless steel heat exchangers exposed to treated borated water 

greater than 140 °F (60 °C) in the ESFs. However, the staff noted that GALL Report 

item VII.E1-5 addresses cracking due to SCC of stainless steel heat exchangers exposed to 

treated borated water greater than 140 °F (60 °C) in the auxiliary systems. Additionally, the 

GALL AMR item recommends to use the Water Chemistry Program and a plant-specific 

program that verifies the absence of cracking due to SCC. By letter dated January 5, 2011, the 

staff issued RAI 3.2.2.3-01 requesting that the applicant justify how the Water Chemistry 

Program alone is adequate to manage the aging effect for the heat exchanger components 

exposed to treated borated water greater than 140 °F (60 °C). As part of the justification, the 

staff asked the applicant to evaluate the operating experience to clarify whether it supports the 

AMR results. The staff also requested that, in lieu of a justification, the applicant provide a 

plant-specific program that will confirm the absence of cracking due to SCC in the components 

and verify the effectiveness of the Water Chemistry Program.

In its response dated February 3, 2011, the applicant stated that the One-Time Inspection 

Program will be implemented to verify the effectiveness of the Water Chemistry Program for the 
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3-295

heat exchanger components exposed to the treated borated water greater than 140 °F (60 °C). 

In its response, the applicant also indicated that LRA Tables 3.2.1, 3.3.1 and 3.2.2-3 and LRA 

Section 3.3.2.2.4.2 were revised accordingly.

Based on its review, the staff finds the applicant’s response to RAI 3.2.2.3-01 acceptable 

because the applicant revised the LRA so that the One-Time Inspection Program will be used to 

verify the effectiveness of the Water Chemistry Program for managing cracking due to SCC of 

the heat exchanger components in a manner that is consistent with the recommendations in the 

GALL Report. The staff’s concern described in RAI 3.2.2.3-01 is resolved.

The staff reviewed the Water Chemistry Program and One-Time Inspection Program and the 

staff’s evaluations are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its 

review, the staff finds the applicant’s use of the Water Chemistry Program and One-Time 

Inspection Program acceptable to manage the aging effect for the following reasons:

• The Water Chemistry Program establishes the plant water chemistry control parameters 

and their limits to mitigate the environmental effect on the aging.

• The Water Chemistry Program also takes corrective actions if the parameters exceed 

the limits so that the environmental effect on the aging is minimized.

• The One-Time Inspection Program will be implemented to confirm the effectiveness of 

the Water Chemistry Program, consistent with the recommendations in the GALL 

Report.

LRA Table 3.3.1, item 3.3.1-90 addresses stainless steel piping, piping components, piping 

elements, tanks, and spent fuel rack supports exposed to treated borated water greater than 

140 °F (60 °C) which are being managed for cracking due to SCC. The LRA credits the Water 

Chemistry Program to manage the aging effect. The GALL Report recommends GALL AMP 

XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately managed. The 

associated AMR items cite generic note A. 

In its review of components associated with item number 3.3.1-90 for which the applicant cited 

generic note A, the staff noted that the guidance in the SRP-LR and GALL Report was revised 

in LR-ISG-2011-01, “Aging Management of Stainless Steel Structures and Components in 

Treated Borated Water,” to add the One-Time Inspection Program to verify the effectiveness of 

the Water Chemistry Program to manage stainless steel components for loss of material, 

cracking, and reduction of heat transfer in treated borated water environments that are not 

controlled to low oxygen levels. The staff noted that, prior to the issuance of LR-ISG-2011-01, 

the SRP-LR and GALL Report guidance inappropriately credited the boron in borated water as a 

corrosion inhibitor in place of other aging management activities.

By letter dated May 29, 2012, the staff issued RAI 3.2.1.48-1 requesting that the applicant 

describe how the effectiveness of the Water Chemistry Program to manage cracking will be 

verified for stainless steel components exposed to treated borated water with greater than 5 ppb 

oxygen. Pending the staff’s review of the applicant’s response, this issue is identified as Open 

Item OI 3.2.2.1-1.

LRA Table 3.3.1, item 3.3.1-91 addresses stainless steel piping, piping components, piping 

elements, tanks, and heat exchanger components exposed to treated borated water which are 

being managed for loss of material due to pitting and crevice corrosion. The LRA credits the 

Water Chemistry Program to manage the aging effect. The GALL Report recommends GALL 

AMP XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately managed. 
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The associated AMR items cite generic notes A or C. The staff noted that the LRA originally 

included a bolting item that referenced item 3.3.1-91 in the spent fuel pool cooling system, citing 

generic note E; however, in its response to RAI B.2.1.9-1 in a letter dated December 17, 2010, 

the applicant stated that the subject bolting was not in scope for license renewal and removed 

the item from the LRA. 

In its review of components associated with item number 3.3.1-91 for which the applicant cited 

generic note A or C, the staff noted that the guidance in the SRP-LR and GALL Report was 

revised in LR-ISG-2011-01, “Aging Management of Stainless Steel Structures and Components 

in Treated Borated Water,” to add the One-Time Inspection Program to verify the effectiveness 

of the Water Chemistry Program to manage stainless steel components for loss of material, 

cracking, and reduction of heat transfer in treated borated water environments that are not 

controlled to low oxygen levels. The staff noted that, prior to the issuance of LR-ISG-2011-01, 

the SRP-LR and GALL Report guidance inappropriately credited the boron in borated water as a 

corrosion inhibitor in place of other aging management activities.

By letter dated May 29, 2012, the staff issued RAI 3.2.1.48-1 requesting that the applicant 

describe how the effectiveness of the Water Chemistry Program to manage loss of material will 

be verified for stainless steel components exposed to treated borated water with greater than 

5 ppb oxygen. Pending the staff’s review of the applicant’s response, this issue is identified as 

Open Item OI 3.2.2.1-1.

The staff concludes that, pending resolution of Open Item OI 3.2.2.1-1, the applicant 

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).

3.3.2.1.1 Aging Management Review Results Identified as Not Applicable

LRA Table 3.3.1, items 3.3.1-36, 3.3.1-37, 3.3.1-38, and 3.3.1-39 state that these items are 

applicable only to BWRs. The staff confirmed that these items do not apply because the unit is

a PWR design. Based on this determination, the staff finds that the applicant provided an 

acceptable basis for concluding AMR items 3.3.1-36, 3.3.1-37, 3.3.1-38, 3.3.1-39, and 3.3.1-49

are not applicable.

LRA Table 3.3.1, items 3.3.1-40, 3.3.1-41, 3.3.1-42, 3.3.1-44 3.3.1-62, 3.3.1-66, 3.3.1-67, 

3.3.1-86, 3.3.1-87, 3.3.1-88 state that these items are not applicable to Seabrook. 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.

LRA Table 3.3.1, item 3.3.1-46, addresses stainless steel and stainless steel clad steel piping 

components and heat exchangers exposed to closed-cycle cooling water at temperatures 

greater than 140 °F (60 °C). The GALL Report recommends the Closed-Cycle Cooling Water 

System Program to manage cracking due to SCC for this component group. The applicant 

stated that this item is not applicable because this item was not used. The staff evaluated the 

applicant’s claim and found that the primary component cooling water system contains stainless 

steel components exposed to closed-cycle cooling water. In addition, the staff noted that 

portions of the primary component cooling water system may reach temperatures greater than 

140 °F (60 °C), based on information in the applicant’s UFSAR. By letter dated 

January 21, 2011, the staff issued RAI 3.3.1.46-1, asking the applicant to clarify whether any 
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stainless steel components in the primary cooling water system are exposed to closed-cycle 

cooling water with temperatures greater than 140 °F (60 °C).

In its response dated February 18, 2011, the applicant stated that the temperatures provided for 

the primary component cooling water system in UFSAR Table 9.2-7, for the thermal barrier loop 

heat exchangers, are design temperatures associated with an abnormal event. The applicant 

also stated that, during normal power operation, the heat exchanger inlet temperature is 

approximately 86 °F and since the thermal barrier cooling water does not exceed 140 °F, SCC 

does not need to be addressed in this system. The staff finds the applicant’s response and its 

claim, that this item is not applicable, acceptable because abnormal events need not be 

postulated for license renewal, as stated in SRP-LR Section A.1.2.1, “Applicable Aging Effects.” 

Therefore, the components will not reach temperatures requiring consideration of SCC. The 

staff’s concern described in RAI 3.3.1.46-1 is resolved.

LRA Table 3.3.1, item 3.3.1-49, addresses stainless steel and stainless steel clad heat 

exchanger components exposed to closed-cycle cooling water. The GALL Report recommends 

the Closed-Cycle Cooling Water Program to manage loss of material due to MIC for this 

component group. The applicant stated that this item is not applicable because the GALL 

Report only includes items associated with BWR systems, and Seabrook is a PWR. The staff 

evaluated the applicant’s claim and found it acceptable because the applicant manages the 

relevant components for loss of material for other aging mechanisms with the Closed-Cycle 

Cooling Water Program, consistent with the guidance in the GALL Report, which will identify 

loss of material due to MIC. This issue is also addressed in RAI B.2.1.12-7, which is discussed 

in SER Section 3.0.3.2.4.

The staff evaluated the applicant’s claim of consistency with the GALL Report. 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 indeed 

consistent with its AMRs. Therefore, the staff concludes that the applicant 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).

LRA Table 3.3.1, item 3.3.1-63, addresses steel fire rated doors exposed to air-outdoor or airindoor uncontrolled. The GALL Report recommends the Fire Protection Program to manage 

loss of material due to wear for this component group. The applicant stated that this item is not 

applicable in the auxiliary system; however, loss of material due to wear of steel fire doors 

exposed to air-outdoor or air-indoor uncontrolled is managed by the Fire Protection Program, as 

described in LRA Section 3.5. The staff evaluated the applicant’s claim and found it acceptable 

because steel fire doors were not found in the auxiliary system, and for these components in the 

containment, structures, and component system described in LRA Section 3.5, the applicant will 

manage aging with the Fire Protection Program, which is consistent with the guidance in the 

GALL Report.

LRA Table 3.3.1, item 3.3.1-65, addresses reinforced concrete structural fire barriers, walls, 

ceilings, and floors exposed to air-indoor uncontrolled, which are being managed for concrete 

cracking and spalling due to aggressive chemical attack and reaction with aggregates. LRA 

Table 3.3.1, item 3.3.1-67, addresses reinforced concrete structural fire barriers, walls, ceilings, 

and floors exposed to air-indoor uncontrolled, which are being managed for loss of material due 

to corrosion of embedded steel. The GALL Report recommends the Fire Protection and 
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Structures Monitoring Programs to manage concrete cracking and spalling due to aggressive 

chemical attack and reaction with aggregates and loss of material due to corrosion of embedded 

steel for this component group. The applicant stated that these items are not applicable to the 

auxiliary system but are applicable to the containment, structures, and component supports 

described in LRA Section 3.5. The staff evaluated the applicant’s claim and noted that, in LRA

Tables 3.5.2-4, 3.5.2-5, and 3.5.2-8, the applicant cited LRA Table 3.3.1, item 3.3.1-65 or 

3.3.1-67 when the Fire Protection Program is proposed to manage aging for reinforced concrete 

structural fire barriers, and LRA Table 3.3.1, item 3.5.1-23, when the Structures Monitoring 

Program is proposed to manage aging. The staff also noted that, in Table 3.5.2-2, the applicant 

uses the ASME Code Section XI, Subsection IWL Program to manage concrete cracking and 

spalling using LRA Table 3.5.1, item 3.5.1-1, instead of the Structures Monitoring Program. The 

staff reviewed the applicant’s ASME Code Section XI, Subsection IWL Program, and its 

evaluation is documented in SER Section 3.0.3.2.17. The staff further noted that the applicant’s 

ASME Code Section XI, Subsection IWL Program includes the same or more conservative 

inspection method and frequency as the Structures Monitoring Program. The staff finds the 

applicant’s claim acceptable because there are no reinforced structural fire barriers, walls, 

ceilings, and floors in the auxiliary systems, and these components in the containment, 

structures, and component supports portion of the LRA are either being managed by the Fire 

Protection and Structures Monitoring Programs or by acceptable alternative items.

3.3.2.1.2 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-54, addresses stainless steel compressed air system piping, piping 

components, and piping elements exposed to internal condensation, which are being managed 

for loss of material due to pitting and crevice corrosion. Stainless steel piping components 

exposed to external condensation are being managed for loss of material due to pitting and 

crevice corrosion. The LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program to manage the aging effect for internal condensation and the 

External Surfaces Monitoring Program to manage the aging effect for external condensation. 

The GALL Report recommends GALL Report AMP XI.M24, “Compressed Air Monitoring” to 

ensure that these aging effects are adequately managed. The associated AMR items cite 

generic note E.

GALL Report AMP XI.M24 recommends using visual inspections of stainless and carbon steels 

to detect the effects of corrosion or presence of contaminants. In its review of components 

associated with LRA Table 3.3.1, item 3.3.1-54, for which the applicant cited generic note E, the 

staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program or the External Surfaces Monitoring Program proposes to manage the 

aging of piping and fittings, valve bodies, tanks, traps, flexible hoses, and orifices through the 

use of visual surface inspections (during periodic maintenance and via work order for 

components identified as requiring aging management) for evidence of hardening and loss of 

strength, loss of material, and reduction of heat transfer due to fouling.

The staff’s evaluations of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program and the External Surfaces Monitoring Program are 

documented in SER Sections 3.0.3.2.15 and 3.0.3.2.14, respectively. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-54, the staff finds the applicant’s

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program for stainless steel compressed air system piping, piping 

components, and piping elements exposed to internal condensation, and the External Surfaces 

Monitoring Program for stainless steel piping components exposed to external condensation 
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acceptable. These programs will manage loss of material for the relevant in-scope stainless 

steel components through visual inspections which will be performed by qualified personnel 

during the performance of periodic, predictive, and corrective maintenance and surveillance 

testing.

The staff concludes that the applicant 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 Due to General Corrosion

LRA Table 3.3.1, item 3.3.1-56, addresses steel HVAC ducting and components external 

surfaces exposed to air-indoor uncontrolled (external), which are being managed for loss of 

material due to general corrosion. The applicant credits the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to manage the aging effect for steel 

fan housings exposed to air-indoor uncontrolled (internal). The GALL Report recommends 

GALL Report AMP XI.M36, “External Surfaces Monitoring,” to ensure that these aging effects 

are adequately managed. The associated AMR items cite generic note E. The applicant stated 

that components that have the same internal and external environments have the same aging 

effects on both the internal and external surfaces.

GALL Report AMP XI.M36 recommends using visual inspections of the external surfaces of 

components for general corrosion to manage the aging effect for the item. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-56, for which the applicant cited 

generic note E, the staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program proposes to manage the aging of structures and structural 

components through the use of opportunistic inspections of the internal surfaces of components. 

The staff also noted that, since the components have the same internal and external 

environments, the loss of material aging effect is the same on both the internal and external 

surfaces; therefore, GALL Report, item VII.F4-1, which refers to air-indoor uncontrolled 

(external) environment and the loss of material aging mechanism, would also apply to an 

air-indoor uncontrolled (internal) environment.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Program is documented in SER Section 3.0.3.2.15. In its review of components 

associated with LRA Table 3.3.1, item 3.3.1-56, the staff finds the applicant’s proposal to 

manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Program acceptable because it includes visual inspections that can detect loss of material on 

the internal surfaces of components.

The staff concludes that the applicant 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).

3.3.2.1.4 Increased Hardness, Shrinkage, and Loss of Strength Due To Weathering

LRA Table 3.3.1, item 3.3.1-61, addresses elastomer fire barrier penetration seals exposed to 

air-outdoor or air-indoor uncontrolled, which are being managed for increased hardness, 

shrinkage, and loss of strength due to weathering. The applicant credits the Fire Protection or 
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Structures Monitoring Program to manage the aging effect. The GALL Report recommends 

GALL Report AMP XI.M26, “Fire Protection,” to ensure that these aging effects are adequately 

managed. The associated AMR items cite generic note A when they are managed by the Fire 

Protection Program and generic note E when they are managed by the Structures Monitoring 

Program.

GALL Report AMP XI.M26 recommends using visual inspections for 10 percent of each type of 

seal at least once every RFO to manage the aging of these items. In its review of components 

associated with LRA Table 3.3.1, item 3.3.1-61, for which the applicant cited generic note E, the 

staff noted that the Structures Monitoring Program will be used to manage the aging of 

elastomer seals through the use of visual inspections performed on a 5-year basis.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with LRA Table 3.3.1, item 3.3.1-61, 

the staff noted that the components which cite generic note E and do not have a corresponding 

item that credits the Fire Protection Program are not fire barriers but other types of elastomer 

seals, such as pressure or flood barriers. The staff also noted that LRA Table 3.3.1, 

item 3.3.1-61, is specifically for fire barrier elastomer seals, and the Fire Protection Program is 

not applicable for non-fire barrier elastomer seals. The staff further noted that non-fire barrier 

elastomer seals may be constructed of materials that are sensitive to ultraviolet light, radiation, 

or ozone; therefore, tactile examination techniques—such as scratching, bending, folding, 

stretching or pressing—are recommended in conjunction with visual examinations to manage

the effects of aging. The applicant’s Structures Monitoring Program does not include tactile 

examination techniques. By letter dated January 21, 2011, the staff issued RAI 3.3.1.61-1 

requesting that the applicant clarify whether the non-fire barrier elastomer seals being managed 

for aging by the Structures Monitoring Program are subject to hardening and loss of strength 

due to exposure to ultraviolet light, radiation, or ozone. If the materials are subject to hardening 

and loss of strength and exposed to these aging effects, the staff asked the applicant to explain 

how the Structures Monitoring Program is adequate to manage aging for these components.

In its response dated February 18, 2011, the applicant stated that the Structures Monitoring 

Program manages non-fire barrier elastomer seals that are subject to aging effects of increased 

hardness, shrinkage, and loss of strength for all environments including ultraviolet light, 

radiation, and ozone. The applicant also stated that it will perform both visual and tactile 

examinations, when required, for non-fire barrier elastomer seals to ensure the seal’s integrity. 

The applicant further stated that the Structures Monitoring Program will be updated to provide 

tactile examination techniques for the non-fire barrier elastomer seals. The staff finds the 

applicant’s response acceptable because the applicant will enhance its Structures Monitoring 

Program to include tactile examination techniques for the non-fire barrier elastomer seals, which 

is an appropriate technique for managing the hardening and loss of strength and is consistent 

with the GALL Report recommendations. The staff’s concern described in RAI 3.3.1.61-1 is 

resolved.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with item 3.3.1-61, the staff noted 

that the components that cite generic note E and do not have a corresponding item being 

managed by the Fire Protection Program, are not fire barriers but are other types of elastomer 

seals, such as pressure or flood barriers. The staff also noted that item 3.3.1-61 is specifically 

for fire barrier elastomer seals, and the Fire Protection Program is not applicable for non-fire 

barrier elastomer seals. The staff finds the applicant’s proposal to manage non-fire barrier 

elastomer seals using the Structures Monitoring Program acceptable because the program 
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includes visual inspections and tactile examinations, which are capable of detecting increased 

hardness, shrinkage, and loss of strength for elastomer seals.

The staff concludes that the applicant 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).

3.3.2.1.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion and Fouling

LRA Table 3.3.1, item 3.3.1-68, addresses steel piping, piping components, and piping 

elements exposed to raw water, which are being managed for loss of material due to general, 

pitting, crevice, and MIC and fouling. The staff noted that the LRA states that galvanic corrosion 

is an additional aging effect that will be managed for several systems. The LRA credits the Fire 

Water System to manage the aging effects for components in the fire protection system and the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage the aging effects for components in the chlorination, dewatering, plant floor drain, 

potable water, roof drains, screen wash, waste processing liquid, and waste processing liquid 

drains systems. The GALL Report recommends GALL Report AMP XI.M27, “Fire Water 

System,” to ensure that these aging effects are adequately managed. The associated AMR 

items that credit the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program cite generic note E and plant-specific notes that state the components 

are not associated with the fire water system.

GALL Report AMP XI.M27 recommends using non-intrusive examination techniques (e.g., 

volumetric testing) to detect changes in the wall thickness. GALL Report AMP XI.M27 also 

recommends visual inspections of the interior pipe surfaces as an alternative to non-intrusive 

examinations, as long as inspections are performed on a representative number of locations on 

a reasonable basis and can evaluate wall thickness and the inner diameter of the piping to 

manage the aging of these items. In its review of components associated with LRA Table 3.3.1, 

item 3.3.1-68, for which the applicant cited generic note E, the staff noted that the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to 

manage the aging of steel piping, piping components, and piping elements through the use of 

visual inspections performed on an opportunistic basis.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted 

that LRA Table 3.3.1, item 3.3.1-68, states that loss of material due to fouling is not an 

applicable aging effect for components in the potable water system. However, the staff also 

noted that GALL Report Table 3, item 68, states that steel components exposed to raw water 

have an aging effect of loss of material due to fouling. While the applicant has stated that the 

environment is potable water, given that there are no chemistry controls for its potable water, its 

effect on items would be similar to raw water. Nevertheless, the staff also noted that the 

inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program for loss of material due to corrosion are the same as those to 

identify loss of material due to fouling. In its review of components associated with LRA 

Table 3.3.1, item 3.3.1-68, the staff finds the applicant’s proposal to manage aging using the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable. This program will conduct visual inspections of the internal surfaces of the 
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components, which is equivalent to the recommendations in GALL Report AMP XI.M27 for 

managing aging of these types of components.

The staff concludes that the applicant 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 Due to Pitting and Crevice Corrosion and Fouling

LRA Table 3.3.1, item 3.3.1-69, addresses stainless steel piping, piping components, and piping 

elements exposed to raw water, which are being managed for loss of material due to pitting and 

crevice corrosion and fouling. The staff noted that the LRA states that MIC is an additional 

aging effect that will be managed for a few systems. The LRA credits the Fire Water System 

Program to manage the aging effects for components in the fire protection system and the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage the aging effects for components in the plant floor drain, potable water, and waste 

processing liquid drains systems. The GALL Report recommends GALL Report AMP XI.M27, 

“Fire Water System,” to ensure that these aging effects are adequately managed. The 

associated AMR items that credit the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program cite generic note E indicating that the AMR item is consistent 

with the GALL Report for material, environment, and aging effect, but a different AMP is 

credited.

GALL Report AMP XI.M27 recommends using non-intrusive examination techniques (e.g., 

volumetric testing) to detect changes in the wall thickness. GALL Report AMP XI.M27 also 

recommends visual inspections of the interior pipe surfaces as an alternative to non-intrusive 

examinations, as long as inspections are performed on a representative number of locations on 

a reasonable basis and can evaluate wall thickness and the inner diameter of the piping to 

manage the aging of these items. In its review of components associated with LRA Table 3.3.1, 

item 3.3.1-69, for which the applicant cited generic note E, the staff noted that the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to 

manage the aging of stainless steel piping, piping components, and piping elements through the 

use of visual inspections performed on an opportunistic basis.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted 

that LRA Table 3.3.1, item 3.3.1-69, states that loss of material due to fouling is not an 

applicable aging effect for components in the potable water system. However, the staff also 

noted that GALL Report Table 3, item 69, states that steel components exposed to raw water 

have an aging effect of loss of material due to fouling. While the applicant has stated that the 

environment is potable water, given that there are no chemistry controls for its potable water, its 

effect on items would be similar to raw water. Nevertheless, the staff also noted that the 

inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program for loss of material due to corrosion are the same as those to 

identify loss of material due to fouling. In its review of components associated with LRA 

Table 3.3.1, item 3.3.1-69, the staff finds the applicant’s proposal to manage aging using the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable. This program will conduct visual inspections of the internal surfaces of 

components, which is equivalent to the recommendations in GALL Report AMP XI.M27 for 

managing aging of these types of components.
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The staff concludes that the applicant 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 Loss of Material Due To Pitting, Crevice, and Microbiologically-Influenced Corrosion 

and Fouling

LRA Table 3.3.1, item 3.3.1-70, addresses copper piping, piping components, and piping 

elements exposed to raw water, which are being managed for loss of material due to pitting, 

crevice, and MIC and fouling. The staff noted that the LRA states that this item will manage the 

additional aging effect of galvanic corrosion for components in the potable water system. The 

LRA credits the Fire Water System Program to manage the aging effects for components in the 

fire protection system and the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program to manage the aging effects for components in the potable water 

system. The GALL Report recommends GALL Report AMP XI.M27, “Fire Water System,” to 

ensure that these aging effects are adequately managed. The associated AMR items, which 

credit the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program, cite generic note E indicating that the AMR item is consistent with the GALL Report for 

material, environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M27 recommends using non-intrusive examination techniques (e.g.,

volumetric testing) to detect changes in the wall thickness. GALL Report AMP XI.M27 also 

recommends visual inspections of the interior pipe surfaces as an alternative to non-intrusive 

examinations, as long as inspections are performed on a representative number of locations on 

a reasonable basis and can evaluate wall thickness and the inner diameter of the piping to 

manage the aging of these items. In its review of components associated with LRA Table 3.3.1, 

item 3.3.1-70, for which the applicant cited generic note E, the staff noted that the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program also proposes to 

manage the aging of copper piping, piping components, and piping elements through the use of 

visual inspections performed on an opportunistic basis.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted 

that LRA Table 3.3.1, item 3.3.1-70, states that loss of material due to fouling is not an 

applicable aging effect for components in the potable water system. However, the staff also 

noted that GALL Report Table 3, item 70, states that steel components exposed to raw water 

have an aging effect of loss of material due to fouling. While the applicant has stated that the 

environment is potable water, given that there are no chemistry controls for its potable water, its 

effect on items would be similar to raw water. Nevertheless, the staff also noted that the 

inspections performed by the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program for loss of material due to corrosion are the same as those to 

identify loss of material due to fouling. In its review of components associated with LRA 

Table 3.3.1, item 3.3.1-70, the staff finds the applicant’s proposal to manage aging using the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable. This program will conduct visual inspections of the internal surfaces of 

components, which is equivalent to the recommendations in GALL Report AMP XI.M27 for 

managing aging of these types of components.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 
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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 Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-71, addresses piping components, and piping elements exposed to 

moist air or condensation (internal), which are being managed for loss of material due to 

general, pitting, and crevice corrosion. The applicant credits the Compressed Air Monitoring 

Program to manage aging for steel and gray cast iron dryer housing, piping and fittings, trap, 

filter housing, and valve body components. The GALL Report recommends the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Program to ensure that the aging effect is 

adequately managed. The associated AMR items cite generic note E indicating that the AMR 

item is consistent with the GALL Report for material, environment, and aging effect, but a 

different AMP is credited. The associated AMR items also cite a plant-specific note, which 

states that the Compressed Air Monitoring Program is substituted to manage the aging effect 

applicable to this component type, material, and environment combination because the diesel 

generator starting air is part of the Compressed Air Monitoring Program at the station. 

Therefore, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program is 

not applicable.

GALL Report AMP XI.M38 recommends using periodic visual inspections of internal surfaces. 

In its review of components associated with LRA Table 3.3.1, item 3.3.1-71, for which the 

applicant cited generic note E, the staff noted that the Compressed Air Monitoring Program also 

proposes to manage the aging of steel piping, piping components, and piping elements exposed 

to moist air or condensation (internal) through the use of air quality monitoring and visual 

inspections.

The staff’s evaluation of the applicant’s Compressed Air Monitoring Program is documented in 

SER Section 3.0.3.2.6. The Compressed Air Monitoring Program proposes to manage the 

aging of steel components by monitoring air quality and dew point and performing visual 

inspections. The Compressed Air Monitoring Program includes in-line dew point monitors,

which verify the dew point of instrument air to be sure it is within the calculated limit and in-line 

filters which limit air particle size. The Compressed Air Monitoring Program also includes air 

sampling to ensure compliance with air quality standards. In addition, the applicant stated that 

the system is subject to a New Hampshire State inspection, which is a visual inspection of the 

system. In its review of components associated with LRA Table 3.3.1, item 3.3.1-71, the staff 

finds the applicant's proposal to manage aging using the Compressed Air Monitoring Program 

acceptable because, like the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program, it will perform visual inspections that can detect loss of material 

prior to the loss of component function.

The staff concludes that the applicant 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).

3.3.2.1.9 Loss of Material Due to General Corrosion

LRA Table 3.3.1, item 3.3.1-73, addresses steel crane structural girders in load handling system 

exposed to air-indoor uncontrolled (external), which are being managed for loss of material due 

to general corrosion. The LRA credits the Inspection of Overhead Heavy Load and Light Load 
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(Related to Refueling) Handling Systems and Structural Monitoring Programs to manage the 

aging effect. The GALL Report recommends GALL Report AMP XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems,” to ensure that 

this aging effect is adequately managed. The associated AMR items cite generic note E and 

plant-specific note 514, which states that the applicant will use the Structural Monitoring 

Program in addition to the recommended GALL Report AMP.

For those items associated with generic note E, GALL Report AMP XI.M23 recommends using 

visual inspections on a routine basis to manage the aging of these items. In its review of 

components associated with item 3.3.1-73, for which the applicant cited generic note E, the staff 

noted that the Structural Monitoring Program also includes the use of visual inspections to 

manage the aging of steel crane structural girders in the load handling system.

The staff’s evaluation of the applicant’s Structural Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff noted that the applicant is using the Inspection of Overhead Heavy 

Load and Light Load (Related to Refueling) Handling Systems Program, documented in SER 

Section 3.0.3.2.5, as well as the Structural Monitoring Program, and visual inspections are 

included in both programs. The staff also noted the Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems Program performs visual inspections of structural 

supports of overhead cranes yearly, while the Structures Monitoring Program determines the 

frequency of the inspections in accordance with the characteristics of the environment in which 

the structures are located. For structures in harsh environments, the inspections are conducted 

on a 5-year basis and those in mild environments are done on a 10-year basis.

In its review of components associated with item 3.3.1-73, the staff finds the applicant’s 

proposal to manage aging using dual programs, the Structural Monitoring Program and the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program, acceptable. Visual inspections of cranes structural components’ will be performed at 

least annually to manage their aging effects so they can continue to fulfill their function(s) for the 

period of extended operation.

The staff concludes that the applicant 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 Hardening and Loss of Strength Due To Elastomer Degradation; Loss of Material 

Due To Erosion

LRA Table 3.3.1, item 3.3.1-75, addresses elastomer seals and components exposed to raw 

water, which are being managed for hardening and loss of strength due to elastomer 

degradation and loss of material due to erosion. The applicant credits the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging 

effect. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water 

System,” to ensure that these aging effects are adequately managed. The associated AMR 

items cite generic note E indicating that the AMR item is consistent with the GALL Report for 

material, environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 
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recommends the use of periodic flushing. In its review of components associated with LRA 

Table 3.3.1, item 3.3.1-75, for which the applicant cited generic note E, the staff noted that the 

applicant also proposed to use the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program to manage the aging of elastomer seals and components 

through the use of periodic inspection on the internal surfaces of components. It was not clear 

to the staff how the opportunistic visual inspections will be able to manage aging of components 

in a raw water system that does not include chemical treatments or surveillances. By letter 

dated January 5, 2011, the staff issued RAI 3.3.2.2-1 asking the applicant to justify using the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, 

which is only a visual inspection program, to manage aging in the raw water environment.

In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows components exposed to raw water, that are not part of the open-cycle cooling 

water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Component Program; therefore, the applicant’s proposal complies with the current 

staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-75, the staff finds the applicant’s 

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program, and the response to RAI 3.3.2.2-1, acceptable for the following 

reasons:

• The program conducts inspections during periodic system surveillances or maintenance 

activities when internal surfaces are accessible.

• The inspections consist of visual examinations and non-visual examinations, such as 

tactile techniques that are capable of detecting hardening and loss of strength in 

elastomers.

• The raw water environment is associated with groundwater that is not capable of being 

chemical treated or for which there are no applicable performance tests associated with 

groundwater dewatering systems, as related to managing the aging of elastomers.

In addition, the staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is acceptable to manage the elastomers exposed to raw 

water because the raw water is associated with the dewatering system and not the open-cycle

cooling system, so the use of this program is consistent with the current staff position. The 

staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 
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consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.11 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, Fouling, and Lining/Coating Degradation

LRA Table 3.3.1, item 3.3.1-76, addresses steel piping, piping components, and piping 

elements (without lining or coating or with degraded lining or coating) exposed to raw water,

which are being managed for loss of material due to general, pitting, and crevice corrosion, MIC, 

fouling, and lining or coating degradation. The applicant credits the Buried Piping and Tanks 

Inspection Program to manage the aging effect. The GALL Report recommends GALL Report 

AMP XI.M.20, “Open-Cycle Cooling Water System,” to ensure that these aging effects are 

adequately managed. The associated AMR item cites generic note E indicating that the AMR 

item is consistent with the GALL Report for material, environment, and aging effect, but a 

different AMP is credited.

GALL Report AMP XI.M.20 recommends using coatings to protect the metal surfaces from 

being exposed to aggressive environments and visual inspections to manage the aging of these 

items. In its review of components associated with LRA Table 3.3.1, item 3.3.1-76, for which 

the applicant cited generic note E, the staff noted that the Buried Piping and Tanks Inspection 

Program proposes to manage the aging of steel piping, piping components, and piping elements 

through the use of coatings to protect the metal surfaces from being exposed to aggressive 

environments and visual inspections.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. The staff noted that the raw water that this item is 

exposed to is groundwater seepage into a vault in which the piping is routed. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-76, the staff finds the applicant’s 

proposal to manage aging using the Buried Piping and Tanks Inspection Program acceptable 

for the following reasons:

• The program includes preventive actions, such as external coatings and wrappings,

installed to industry standard practices.

• Periodic visual inspections will be performed starting 10 years prior to the period of 

extended operation and extend into both 10-year periods during the period of extended 

operation to ensure that coatings remain intact.

• Plant-specific operating experience will be used to inform inspection locations.

The staff concludes that the applicant 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).

3.3.2.1.12 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, and Fouling

LRA Table 3.3.1, item 3.3.1-77, addresses steel heat exchanger components exposed to raw 

water, which are being managed for loss of material due to general, pitting, and crevice

corrosion, MIC, and fouling. The applicant credits the Fire Water System Program to manage 

the aging effect. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle 
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Cooling Water System,” to ensure that these aging effects are adequately managed. The 

associated AMR items cite generic note E indicating that the AMR item is consistent with the 

GALL Report for material, environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. In its review of components associated with LRA

Table 3.3.1, item 3.3.1-77, for which the applicant cited generic note E, the staff noted that the 

Fire Water System Program proposes to manage the aging of steel heat exchanger 

components through the use of inspections, periodic flushing, system performance testing, and 

chemical additions to prevent microbiological growth.

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.2.8. In its review of components associated with LRA Table 3.3.1, item 3.3.1-77, 

the staff finds the applicant’s proposal to manage aging using the Fire Water System Program 

acceptable because the program conducts inspections roughly every outage and uses 

preventive actions, including chemical additions and performance verification.

The staff concludes that the applicant 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 Due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-78, addresses stainless steel, nickel alloy, and copper-alloy piping, 

piping components, and piping elements exposed to raw water, which are being managed for 

loss of material due to pitting and crevice corrosion. The applicant credits the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the 

aging effect. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling 

Water System,” to ensure that these aging effects are adequately managed. The associated 

AMR items cite generic note E indicating that the AMR item is consistent with the GALL Report 

for material, environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. In its review of components associated with LRA

Table 3.3.1, item 3.3.1-78, for which the applicant cited generic note E, the staff noted that the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

proposes to manage the aging of stainless steel, nickel alloy, and copper-alloy piping, piping 

components, and piping elements through the use of periodic inspection on the internal surfaces 

of components. It was not clear to the staff how the opportunistic visual inspections will be able 

to manage aging of components in a raw water system that does not include chemical 

treatments or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2-1 

requesting that the applicant justify the use of the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program, which is only a visual inspection 

program, to manage aging in the raw water environment.
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In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows components exposed to raw water, that are not part of the open-cycle cooling 

water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Component Program; therefore, the applicant’s proposal complies with the current 

staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-78, the staff finds the applicant’s 

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program acceptable. The program conducts visual inspections during 

periodic system surveillances or maintenance activities when internal surfaces are accessible 

and monitors parameters such as corrosion, corrosion byproducts, coating degradation, 

scale/deposits, pits, and surface discoloration and discontinuities. In addition, the staff finds that 

the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program is acceptable to manage these components exposed to raw water because the raw 

water is associated with the chlorination and screen wash system and not the open-cycle

cooling system. Therefore, the use of this program is consistent with the current staff position.

The staff concludes that the applicant 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 Due to Pitting and Crevice Corrosion, and Fouling

LRA Table 3.3.1, item 3.3.1-79, addresses stainless steel piping, piping components, and piping 

elements exposed to raw water, which are being managed for loss of material due to pitting and 

crevice corrosion, and fouling. The applicant credits either the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program or Bolting Integrity Program to manage 

the aging effect. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle 

Cooling Water System,” to ensure that these aging effects are adequately managed. The 

associated AMR items cite generic note E indicating that the AMR item is consistent with the 

GALL Report for material, environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. In its review of components associated with LRA

Table 3.3.1, item 3.3.1-79, for which the applicant cited generic note E, the staff noted that the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

proposes to manage the aging of stainless steel piping, piping components, and piping 

elements through the use of periodic inspection on the internal surfaces of components. The 
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staff also noted that the Bolting Integrity Program proposes to manage the aging of stainless 

steel bolts through the use of periodic inspection.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. The staff notes that the GALL Report mainly recommends managing aging of 

bolts with the Bolting Integrity Program. In its review of components associated with LRA

Table 3.3.1, item 3.3.1-79, the staff finds the applicant’s proposal to manage aging using the 

Bolting Integrity Program acceptable because it follows the ASME Code guidelines for 

managing aging of bolts, which incorporates operating experience specifically for this 

component type.

For the components other than bolting, it was not clear to the staff how the opportunistic visual 

inspections will be able to manage aging of components in a raw water system that does not 

include chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued 

RAI 3.3.2.2-1 requesting that the applicant justify the use of the Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components Program, which is only a visual inspection 

program to manage aging in the raw water environment.

In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows for components exposed to raw water, that are not part of the open-cycle

cooling water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Component Program. therefore, the applicant’s proposal complies with the 

current staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-79, the staff finds the applicant’s 

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program acceptable. This program conducts visual inspections during 

periodic system surveillances or maintenance activities when internal surfaces are accessible 

and monitors parameters such as corrosion, corrosion byproducts, coating degradation, 

scale/deposits, pits, and surface discoloration and discontinuities. In addition, the staff finds that 

the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program is acceptable to manage the component exposed to raw water because the raw water 

is associated with the dewatering, service water, and screen wash systems and not the 

open-cycle cooling system. Therefore, the use of this program is consistent with the current 

staff position.

The staff concludes that the applicant 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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3.3.2.1.15 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

LRA Table 3.3.1, item 3.3.1-80, addresses stainless steel and copper piping, piping 

components, and piping elements exposed to raw water, which are being managed for loss of 

material due to pitting and crevice corrosion and MIC. The applicant credits either the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program or 

Structures Monitoring Program to manage the aging effect. The GALL Report recommends 

GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these aging 

effects are adequately managed. The associated AMR items cite generic note E indicating that 

the AMR item is consistent with the GALL Report for material, environment, and aging effect, 

but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 

chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. 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 noted that the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

proposes to manage the aging of stainless steel and copper piping, piping components, and 

piping elements through the use of periodic inspection on the internal surfaces of components. 

The staff also noted that the Structures Monitoring Program proposes to manage the aging of 

stainless steel sumps through the use of periodic inspections conducted on a 5-year basis. It 

was not clear to the staff how the opportunistic visual inspections will be able to manage aging 

of components in a raw water system that does not include chemical treatments or 

surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2-1 requesting that the 

applicant justify the use of the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program, which is only a visual inspection program to manage aging in 

the raw water environment. In addition, by letter dated January 5, 2011, the staff issued 

RAI 3.5.2.5-2 requesting that the applicant justify the use of the Structures Monitoring Program, 

which is only a visual inspection program, to manage aging in the raw water environment.

In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows components exposed to raw water, that are not part of the open-cycle cooling 

water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Component Program; therefore, the applicant’s proposal complies with the current 

staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-80, the staff finds the applicant’s 

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program acceptable. This program conducts inspections during periodic 

system surveillances or maintenance activities when internal surfaces accessible and monitors 
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parameters such as corrosion, corrosion byproducts, coating degradation, scale/deposits, pits,

and surface discoloration and discontinuities. In addition, the staff finds that the use of 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is 

acceptable to manage these components exposed to raw water because the raw water is 

associated with the boron recovery and waste processing liquid and waste processing liquid 

systems and not the open-cycle cooling system. Therefore, the use of this program is 

consistent with the current staff position

In its response dated February 3, 2011, with regard to RAI 3.5.2.5-2, the applicant stated that 

the raw water in the sumps is not part of the open-cycle cooling water system and receives no 

chemical addition. The applicant also stated that the sumps are normally dry or slightly wetted 

and, if water enters the lined or unlined sumps, the sump pump removes the water. The 

applicant further stated that because the sumps can be wetted, it was assumed that they are in 

a raw water environment, that the Structures Monitoring Program will perform an inspection for 

degradation, and that any degradation identified will be appropriately dispositioned. The staff 

finds the applicant’s response acceptable because the sumps are typically not wet, and the 

applicant conservatively assigned a raw water environment. In addition, the staff finds the 

response acceptable because the GALL Report, Revision 2, allows components exposed to raw 

water, that are not part of the open-cycle cooling water system, to be managed with programs 

that periodically inspect the components. The staff notes that the Structures Monitoring 

Program will conduct periodic visual inspections that are consistent with the current staff 

position in GALL Report, Revision 2. The staff’s concern described in RAI 3.5.2.5-2 is resolved.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with LRA Table 3.3.1, item 3.3.1-80, 

the staff finds the applicant’s proposal to manage aging using the Structures Monitoring 

Program acceptable because the program conducts periodic visual inspections for aging effects 

specific to each structure by qualified individuals. In addition, the staff finds that the use of 

Structures Monitoring Program is acceptable to manage these components exposed to raw 

water because the raw water is not the open-cycle system; therefore, the use of this program is 

consistent with the current staff position.

The staff concludes that the applicant 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 Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion, 

and Fouling

LRA Table 3.3.1, item 3.3.1-81, addresses copper piping, piping components, and piping 

elements exposed to raw water, which are being managed for loss of material due to pitting and 

crevice corrosion, MIC, and fouling. The applicant credits the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to manage the aging effect. The 

GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to 

ensure that these aging effects are adequately managed. The associated AMR items cite 

generic note E indicating that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, GALL Report AMP XI.M20 recommends using 
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chemical treatments whenever the potential for biological fouling species exists and also 

recommends the use of periodic flushing. In its review of components associated with LRA

Table 3.3.1, item 3.3.1-81, for which the applicant cited generic note E, the staff noted that the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

proposes to manage the aging of copper piping, piping components, and piping elements 

through the use of periodic inspection on the internal surfaces of components. It was not clear 

to the staff how the opportunistic visual inspections will be able to manage aging of components 

in a raw water system that does not include chemical treatments or surveillances. By letter 

dated January 5, 2011, the staff issued RAI 3.3.2.2-1 requesting that the applicant justify the 

use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program, which is only a visual inspection program, to manage aging in the raw water 

environment.

In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows components exposed to raw water, that are not part of the open-cycle cooling 

water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Component Program; therefore, the applicant’s proposal complies with the current 

staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-81, the staff finds the applicant’s 

proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program acceptable. This program conducts visual inspections during 

periodic system surveillances or maintenance activities when internal surfaces are accessible 

and monitors parameters such as corrosion, corrosion byproducts, coating degradation, 

scale/deposits, pits, and surface discoloration and discontinuities. In addition, the staff finds that 

the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program is acceptable to manage these components exposed to raw water because the raw 

water is associated with the chlorination, dewatering, plant floor drain, and screen wash 

systems and not the open-cycle cooling system. Therefore, the use of this program is 

consistent with the current staff position.

The staff noted that, in a letter dated November 15, 2010, the applicant submitted Supplement 2

to the LRA. In this supplement, LRA Table 3.3.1, item 3.3.1-81, was modified to include the 

Buried Piping and Tanks Inspection Program for copper-alloy components. The staff also noted 

that LRA Table 3.3.2-37 identifies the specific components as copper alloy greater than 

15 percent zinc valve bodies that are inside a vault and exposed to raw water due to 

groundwater inleakage as stated in plant-specific note 9. The staff further noted that, given that 

the valves are constructed of copper alloy greater than 15 percent zinc, they would also be 

susceptible to selective leaching. The staff noted that, in Table 3.3.2-37, the applicant 

established an item for these components that identifies selective leaching as an AERM and 

uses the Selective Leaching Program to manage this aging effect. The staff finds that the 
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applicant is appropriately managing the added components because they are managing aging 

due loss of material and selective leaching.

For the copper alloy greater than 15 percent zinc valve body items associated with generic 

note E, GALL Report AMP XI.M.20 recommends using coatings to protect the metal surfaces 

from being exposed to aggressive environments and visual inspections to manage the aging of 

these items. In its review of components associated with LRA Table 3.3.1, item 3.3.1-81 for 

which the applicant cited generic note E, the staff noted that the Buried Piping and Tanks 

Inspection Program proposes to manage the aging of piping, piping components, and piping 

elements through the use of coatings to protect the metal surfaces from being exposed to 

aggressive environments and visual inspections.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. In its review of components associated with LRA

Table 3.3.1, item 3.3.1-81, the staff finds the applicant’s proposal to manage aging using the 

Buried Piping and Tanks Inspection Program acceptable for the following reasons:

• The program includes preventive actions such as external coatings and wrappings 

installed to industry standard practices.

• Periodic visual inspections will be performed starting 10 years prior to the period of 

extended operation and extend into both 10-year periods during the period of extended 

operation to ensure that coatings remain intact.

• Plant-specific operating experience will be used to inform inspection locations.

The staff concludes that the applicant 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 Reduction of Heat Transfer Due to Fouling

LRA Table 3.3.1, item 3.3.1-83, addresses stainless steel and copper-alloy heat exchanger 

tubes exposed to raw water, which are being managed for reduction of heat transfer due to 

fouling. The applicant credits the Fire Water System Program to manage the aging effect. The 

GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to 

ensure that these aging effects are adequately managed. The associated AMR items cite 

generic note E indicating that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, the GALL Report AMP XI.M20 program 

recommends using chemical treatments whenever the potential for biological fouling species 

exists and also recommends the use of periodic flushing. In its review of components 

associated with LRA Table 3.3.1, item 3.3.1-83, for which the applicant cited generic note E, the 

staff noted that the Fire Water System Program proposes to manage the aging of stainless steel 

and copper-alloy heat exchanger tubes through the use of inspections, periodic flushing, system

performance testing, and chemical additions to prevent microbiological growth.

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.2.8. In its review of components associated with LRA Table 3.3.1, item 3.3.1-83, 
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the staff finds the applicant’s proposal to manage aging using the Fire Water System Program 

acceptable because the program conducts inspections roughly every outage and uses 

preventive actions including chemical additions and performance verification.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.2 Aging Management Review 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

• reduction of heat transfer due to fouling

• cracking due to SCC

• cracking due to SCC and cyclic loading

• hardening and loss of strength due to elastomer degradation

• reduction of neutron-absorbing capacity and loss of material due to general corrosion

• loss of material due to general, pitting, and crevice corrosion

• loss of material due to general, pitting, crevice, and MIC 

• loss of material due to general, pitting, crevice, MIC, and fouling

• loss of material due to pitting and crevice corrosion

• loss of material due to pitting, crevice, and galvanic corrosion

• loss of material due to pitting, crevice, and MIC

• loss of material due to wear

• loss of material due to cladding breach

• 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 if 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.

3.3.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.3.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants 

must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the 

staff’s review of the applicant’s evaluation of this TLAA.

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 air-indoor uncontrolled (external), and 

steel and stainless steel piping, piping components, piping elements, and heat exchanger 

components exposed to air-indoor uncontrolled, 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 is 
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required to be evaluated in accordance with 10 CFR 54.21(c). The applicant stated that TLAAs

identified for fatigue in the chemical and volume control system (CVCS) are discussed in LRA 

Section 4.3, and the evaluation of crane load cycles as a TLAA for cranes is discussed in LRA 

Section 4.7.6.

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. 

These TLAAs are to be evaluated in accordance with the TLAA acceptance criteria 

requirements in 10 CFR 54.21(c)(1) and in accordance with SRP-LR Section 4.3, “Metal Fatigue 

Analysis,” or SRP-LR Section 4.7, “Other Plant-Specific Time-Limited Aging Analyses.” The 

staff reviewed the applicant’s AMR items and finds that the AMR results are consistent with the 

recommendations of the GALL Report and SRP-LR for managing cumulative fatigue damage in 

steel cranes, structural girders exposed to air-indoor uncontrolled (external), and steel and 

stainless steel piping, piping components, piping elements, and heat exchanger components 

exposed to air-indoor uncontrolled, treated borated water or treated water, except as identified 

below.

In its review of LRA Table 3.3.2-3, the staff noted that, in addition to the AMR items associated 

with item 3.3.1-2, the applicant also included two AMR items associated with item 3.1.1-8 

regarding TLAAs of valve body (Class 1) and piping and fittings (Class 1 less than 4 in.). LRA 

Section 4.3.7 states that the CVCS components were designed in accordance with ASME Code

Section III Class 2 and Class 3 requirements. It is not clear to the staff which piping and fittings 

are represented in LRA Table 3.3.2-3 and whether the two AMR items (3.1.1-8) represent the 

portion of the CVCS that is located inside the reactor containment. By letter dated 

January 21, 2010, the staff issued RAI 3.3.2.2.1-2 asking the applicant to clarify which portions 

of the CVCS system are represented by AMR items 3.1.1-8 in LRA Table 3.3.2-3 for the CVCS. 

The staff also asked the applicant to clarify the inconsistency between LRA Section 4.3.7, which 

stated that the CVCS components were designed to ASME Code Section III Class 2 and 

Class 3 requirements, and LRA Table 3.1.1, item 3.1.1-8, which represents Class 1 

components. Furthermore, the staff requested that the applicant identify the TLAA in LRA 

Section 4 that represents the fatigue analysis for these Class 1 components.

In its response dated February 18, 2011, the applicant clarified that item 3.1.1-8 represents the 

Class 1 RCPB components in the CVCS (LRA Table 3.3.2-3) system. The applicant also stated 

that item 3.3.1-2, which represents the Class 2 and Class 3 components in the CVCS, were 

already included in LRA Table 3.3.2-3, and no changes were necessary. The applicant stated 

that the Class 1 RCPB components in the CVCS are part of the NSSS and are evaluated in 

LRA Sections 4.3.1 and 4.3.2. The applicant also stated that the TLAAs for Class 2 and Class 3 

components are evaluated in LRA Section 4.3.7.

Based on its review, the staff finds the applicant’s response to RAI 3.3.2.2.1-2 acceptable 

because the applicant clarified the AMR items and associated TLAAs for Class 1 RCPB

components and Class 2 and Class 3 components in the CVCS, and the applicant’s AMR 

results are consistent with the recommendations of the GALL Report. The staff’s review of the 

applicant’s TLAAs associated with the Class 1 components and Class 2 and Class 3 

components are documented in SER Section 4.3. The staff’s concern described in 

RAI 3.3.2.2.1-2 is resolved.

The staff noted that LRA Table 3.5.2-3 does not include any applicable items for management 

of cumulative fatigue damage in the steel cranes structural girders even though LRA 

Section 4.7.6 discusses the TLAA associated with crane load cycle limits. By letter dated 
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January 21, 2010, the staff issued RAI 3.3.2.2.1-1, Request 2, asking the applicant to include in 

LRA Table 3.5.2-3 the applicable items for management of cumulative fatigue damage in the 

steel cranes structural girders or provide the basis for excluding these items from the LRA.

In its response dated February 18, 2011, the applicant amended LRA Table 3.5.2-3 to include 

the associated AMR items for the steel crane structural girders for fuel handling and overhead 

cranes, consistent with GALL Report AMR item VII.B-2. The applicant stated that two rows 

representing TLAAs of steel structural support for 1-FH-RE-1 spent fuel cask handling crane 

and 1-MM-CR-3 polar gantry crane exposed to air-indoor uncontrolled have been added to LRA

Table 3.5.2-3.

Based on its review of the amended LRA Table 3.5.2-3, the staff finds the applicant’s response 

to RAI 3.3.2.2.1-1, Request 2, and the additions of the AMR items acceptable because they are 

consistent with GALL AMR item VII.B-2 for the steel cranes structural girders. The staff’s 

concern described in RAI 3.3.2.2.1-1, Request 2, is resolved.

Based on the staff’s review, it concludes that the applicant 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 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 4.7 document the staff’s review of the applicant’s evaluation of the TLAAs for 

these components.

3.3.2.2.2 Reduction of Heat Transfer due to Fouling

LRA Section 3.3.2.2.2 is associated with LRA Table 3.3.1, item 3.3.1-3, and addresses stainless 

steel heat exchanger tubes exposed to treated water. The applicant stated that this item is not 

applicable because this item is associated with the GALL item VII.E3-6, which applies to BWR 

reactor water cleanup system heat exchangers. The staff noted that the related item, AP-62, 

from SRP-LR Table 3.3.1, was derived from a previous SER for heat exchanger tubes exposed 

to treated borated water in a spent fuel pool system. Based on this, the applicant’s 

determination that this item was not applicable did not appear appropriate. By letter dated 

February 24, 2011, the staff issued RAI 3.3.2.2.2-1 requesting that the applicant provide 

additional bases regarding the non-applicability of this item and the bases for not managing 

reduction of heat transfer for heat exchanger tubes identified as having a heat transfer function.

In its response dated March 22, 2011, the applicant stated that the “treated borated water” 

environment is different from the “treated water” environment. The applicant provided the 

definitions of treated water and treated boated water from the GALL Report Section IX.D, which 

states that, unlike the PWR reactor coolant environment (treated borated water), the BWR 

reactor coolant environment (treated water) does not contain boron, a recognized corrosion 

inhibitor. The applicant also referred to GALL Report Section IX.F, which describes fouling as 

an accumulation of deposits that may be due to particulate fouling, such as sediment, silt or 

corrosion products. The applicant further stated that none of the heat exchanger tubes in LRA 

Section 3.3 are exposed to treated water; however, there are stainless steel heat exchanger 

tubes exposed to treated borated water in the auxiliary systems. The applicant provided the 

following basis for its determination that these components are not susceptible to reduction of 

heat transfer:
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Seabrook’s determination that reduction of heat transfer is not an aging effect in treated borated 

water environment is based on plant and industry operating experience. Seabrook is not aware 

of any fouling in treated borated water environment leading to reduction of heat transfer in 

stainless steel heat exchanger tubes. This conclusion is consistent with NUREG-1801,

Revision 1. NUREG-1801, Revision 1, does not identify reduction of heat transfer as an aging 

effect for stainless steel heat exchanger tubes in treated borated water environment.

Fouling of the stainless steel heat exchanger tubes on the treated borated water side would only 

occur through the buildup of corrosion products. Since Seabrook’s treated borated water 

contains boron, a corrosion inhibitor, corrosion product buildup resulting in reduction of heat 

transfer in treated borated water environment is not a credible aging effect/mechanism. This is 

further validated by NUREG-1801, Revision 1, items V.A-27 and V.D1-30 (NUREG-1800,

Table 3.2-1, items 48 and 49), which state that Water Chemistry Program alone (for PWR 

primary water) is adequate for managing loss of material in stainless steel components exposed 

to treated borated water, indicating that corrosion is not expected to occur in stainless steel 

components exposed to treated borated water. In the absence of corrosion, corrosion product 

buildup will not occur.

The applicant also stated that since reduction of heat transfer in treated borated water is not 

identified as a potential aging effect, no items for reduction of heat transfer in treated borated 

water appear in the LRA. The applicant further stated that its conclusion is consistent with 

NUREG-1810, Revision 1 and Revision 2, as well as the staff conclusions, as stated in the 

Beaver Valley (Section 3.2.2.3.2) and Prairie Island (Section 3.2.2.2.4) final SERs.

The staff reviewed the applicant response and the cited portions of the GALL Report. The staff 

noted that, although the GALL Report, Revision 1, states that boron is a recognized corrosion 

inhibitor, the GALL Report, Revision 2, deleted that discussion from the definition of treated 

water. The staff also reviewed the AMR items V.A-27 and V.D1-30 (SRP-LR, Table 3.2,

item 49) and noted that the GALL Report credits water chemistry to manage loss of material due 

to pitting and crevice corrosion in stainless components exposed to treated borated water. The 

staff noted that, although the basis for adding these items in the GALL Report, Revision 1, 

stated that a significant loss of material was not expected, the potential for corrosion and 

consequently corrosion product buildup still exists. The staff also reviewed the Beaver Valley 

and Prairie Island SERs, and the associated LRAs cited by the applicant, and noted that both 

LRAs identified reduction of heat transfer for stainless steel heat exchanger tubes in a treated 

borated water environment as an aging effect requiring managing. Based on the above, by 

letter dated May 23, 2011, the staff issued RAI 3.2.2.2.4.2-1A, requesting that the applicant 

justify why heat exchanger tubes, which have a heat transfer intended function, do not need to 

include a reduction of heat transfer aging effect requiring management. In addition, the RAI 

asked the applicant to provide the plant-specific and industry operating experience cited in its 

response demonstrating that reduction in heat transfer was not a credible aging effect for the 

components in question.

In its response dated June 2, 2011, the applicant revised LRA Tables 3.3.2-3 and 3.3.2-39 to 

include AMR items for stainless steel heat exchanger components in treated borated water 

environment that are being managed for reduction of heat transfer by the Water Chemistry 

Program. The AMR items cite generic note H and plant-specific notes, which state that 

reduction of heat transfer due to fouling is not in the GALL Report for this component, material,

and environment combination. 
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The staff finds the applicant’s response unacceptable because the guidance in the SRP-LR and 

GALL Report was revised in LR-ISG-2011-01, “Aging Management of Stainless Steel Structures 

and Components in Treated Borated Water,” to add the One-Time Inspection Program to verify 

the effectiveness of the Water Chemistry Program to manage stainless steel components for 

loss of material, cracking, and reduction of heat transfer in treated borated water environments 

that are not controlled to low oxygen levels. The staff noted that, prior to the issuance of 

LR-ISG-2011-01, the SRP-LR and GALL Report guidance inappropriately credited the boron in 

borated water as a corrosion inhibitor in place of other aging management activities.

By letter dated May 29, 2012, the staff issued RAI 3.2.1.48-1 requesting that the applicant 

describe how the effectiveness of the Water Chemistry Program to manage reduction of heat 

transfer will be verified for stainless steel components exposed to treated borated water with 

greater than 5 ppb oxygen. Pending the staff’s review of the applicant’s response, this issue is 

identified as Open Item OI 3.2.2.1-1.

3.3.2.2.3 Cracking due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.3.2.2.3 against the following criteria in SRP-LR

Section 3.3.2.2.3:

(1) SRP-LR Section 3.3.2.2.3 states that cracking due to SCC could occur in the stainless 

steel piping, piping components, and piping elements of the BWR standby liquid control 

system that are exposed to sodium pentaborate solution greater than 140 °F (60 °C).

LRA Section 3.3.2.2.3.1, associated with LRA Table 3.3.1, item 3.3.1-4, addresses 

cracking due to SCC in stainless steel piping, piping components, and piping elements 

exposed to sodium pentaborate at greater than 140 °F (60 °C). The applicant stated that 

this item is not applicable because this aging issue is only applicable to BWRs. The staff 

reviewed SRP-LR and confirmed that this aging effect is only applicable to the standby 

liquid control system, which is only associated with BWRs; therefore, it finds the 

applicant’s determination acceptable.

(2) LRA Section 3.3.2.2.3.2, is associated with LRA Table 3.3.1, item 3.3.1-5, and 

addresses stainless steel and stainless clad steel heat exchanger components exposed 

to treated water greater than 140 °F (60 °C). The applicant stated that this item is not 

applicable because this item is associated with GALL items VII.E3-3 and VII.E3-19, 

which apply to BWR reactor water cleanup system heat exchangers. The staff reviewed 

LRA Section 3.3 and noted that, although there were no in-scope stainless steel heat 

exchanger tubes exposed to treated water greater than 140 °F (60 °C) present in the 

auxiliary systems, there were several systems with heat exchanger tubes exposed to 

treated borated water greater than 140 °F (60 °C). As a result, the staff considered this 

aging effect to be applicable to these components. However, the staff also noted that 

the applicant aligned these components with item 3.3.1-7, which is associated with 

non-regenerative heat exchanger tubes and cited generic note E indicating that a 

different AMP or plant-specific AMP was credited to manage this aging effect. The staff 

further noted that the applicant also cited plant-specific note 7 for these components, 

which stated that the Water Chemistry and One-Time Inspection Programs were used to 

manage this aging effect. The staff finds the applicant’s determination, that item 3.3.1-5 

is not applicable, acceptable because the applicant aligned the applicable components 

with item 3.3.1-7, which has comparable acceptance criteria as item 3.3.1-5; 

consequently, it will adequately manage this aging effect.
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(3) LRA Section 3.3.2.2.3.3 is associated with LRA Table 3.3.1, item 3.3.1-6, and addresses 

stainless steel diesel engine exhaust piping, piping components, and piping elements 

exposed to diesel exhaust, which are being managed for cracking due to SCC by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program. The criteria in SRP-LR Section 3.3.2.2.3, item 3, state that cracking due to 

SCC could occur for stainless steel diesel engine exhaust piping, piping components, 

and piping elements exposed to diesel exhaust. The SRP-LR states that a plant-specific 

AMP should be used. The SRP-LR also states that acceptance criteria for the 

plant-specific AMP will include a description of its basis and analysis methodology, 

ensure continued functional operation of structure and components, contain quantified 

criteria or a illustrate method of quantification, and discuss qualitative inspections via 

ASME or site-specific criteria. The applicant addressed the further evaluation criteria of 

the SRP-LR by stating that it will implement the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to manage cracking due to 

SCC for the stainless steel diesel exhaust piping components exposed to diesel exhaust 

in the diesel generator system and fire protection system.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. 

The staff noted that the AMP includes visual surface, magnification, and ultrasonic 

inspection methods. The staff also noted that the reports will be evaluated by a system 

engineer who will help ensure the extent and schedule of inspections to detect 

degradation prior to loss of function, and these reviews will include trending to determine 

whether the number of locations and intervals are providing aging management 

consistent with the CLB. Acceptance criteria for various corrosion mechanisms will be 

identified in appropriate inspection procedures. The staff further noted that GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” states that inspections are performed when the internal surfaces are 

accessible during the performance of periodic surveillances and during maintenance 

activities or during scheduled outages. It also states that inspection intervals are 

established such that they provide timely detection of degradation. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-6, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is acceptable for the following reasons:

• The applicant will perform sufficient inspections for each material-environment 

combination to provide an overall assessment of any aging degradation that may be 

occurring.

• The selection of inspections will consider materials, operating environments, industry 

and plant-specific operating experience, engineering evaluations of equipment 

performance, and susceptibility to aging due to time in service, severity of operating 

conditions, and lowest design margins.

• Recurring surveillance and maintenance activities provides the ability to detect aging of 

the material-environment combination prior to loss of function.

• Inspection results will be trended.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.3, item 3, criteria. For those items that apply to LRA 
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Section 3.3.2.2.3.3, the staff determined 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 be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.4 Cracking due to Stress Corrosion Cracking and Cyclic Loading

The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP-LR 

Section 3.3.2.2.4:

(1) LRA Section 3.3.2.2.4.1, is associated with LRA Table 3.3.1, item 3.3.1-7, and 

addresses cracking due to SCC and cyclic loading in stainless steel non-regenerative 

heat exchanger components exposed to treated borated water greater than 140 °F 

(60 °C), which are being managed by the Water Chemistry and the One-Time Inspection 

Programs. The criteria in SRP-LR Section 3.3.2.2.4, item 1, states that the existing AMP 

monitors and controls primary water chemistry to manage cracking due to SCC; 

however, control of water chemistry does not preclude cracking due to SCC and cyclic 

loading. The SRP-LR also states that the effectiveness of Water Chemistry Control 

Programs should be confirmed using a plant-specific AMP, and an acceptable 

verification program includes temperature and radioactivity monitoring of the shell side 

water and eddy current testing of the tubes. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the Water Chemistry Program will 

manage this aging effect, and the effectiveness of the program will be confirmed by the 

One-Time Inspection Program.

The staff’s evaluations of the applicant’s Water Chemistry and the One-Time Inspection 

Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The 

staff reviewed the applicant's Water Chemistry Program and noted that it controls 

detrimental contaminants below the levels known to cause cracking. The staff also 

noted that the applicant credited its One-Time Inspection Program to verify the 

effectiveness of the Water Chemistry Program to manage this aging effect. However, it 

is not clear whether the non-regenerative heat exchangers will be included in the sample 

of components to be inspected and what inspection techniques will be used. In addition, 

it is also not clear if temperature and radioactivity monitoring of the shell side water is 

performed to verify the integrity of the heat exchangers. By letter dated January 5, 2011, 

the staff issued RAI 3.3.2.2.4-1 requesting that the applicant clarify if the 

non-regenerative heat exchangers will be included in sample of components to be 

inspected, to provide the inspection method that will be used to detect cracking in the 

heat exchanger tubes, and to confirm if temperature and radioactivity monitoring of the 

shell side water is performed.

In its response dated February 3, 2011, the applicant stated that the non-regenerative 

heat exchangers will be included in the sample of components to be inspected in the 

One-Time Inspection Program and that eddy current testing will be used to detect 

cracking in the stainless steel tubes. The applicant also revised LRA 

Section 3.3.2.2.4.1, item 1, and stated that temperature and radioactivity monitoring of 

the shell side water is performed to verify the integrity of the heat exchangers.

The staff finds the applicant response acceptable because the applicant is consistent 

with the GALL Report recommendation of verification program of eddy current testing of 

tubes to detect cracking and temperature and radioactivity monitoring of the shell side 
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water to verify heat exchanger integrity. The staff’s concern described in RAI 3.3.2.2.4-1 

is resolved.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.4, item 1, criteria. For those items that apply to LRA 

Section 3.2.2.2.4.1, the staff determined that the LRA is consistent with the GALL 

Report. The staff also determined that the applicant 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 3.3.2.2.4.2, is associated with LRA Table 3.3.1, item 3.3.1-8, and 

addresses cracking due to SCC and cyclic loading in stainless steel regenerative heat 

exchanger components exposed to treated borated water greater than 140 °F (60 °C). 

The criteria in SRP-LR Section 3.3.2.2.4, item 2, states that cracking due to SCC and 

cyclic loading may occur in stainless steel regenerative heat exchanger components 

exposed to treated borated water greater than 140 °F (60 °C). The SRP-LR also states 

that the existing AMP monitors and controls primary water chemistry to manage cracking 

due to SCC; however, these controls do not preclude cracking and recommend that the 

effectiveness of Water Chemistry Control Program be confirmed using a plant-specific 

AMP. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that this aging effect will be managed by the Water Chemistry Program. The applicant 

also stated that, since the regenerative heat exchanger is welded and cannot be 

disassembled for internal inspection, the effectiveness of the water chemistry controls 

will be confirmed by a one-time inspection of a non-regenerative heat exchanger with the 

same material and environment combination in the chemical and volume control system. 

The applicant further stated that the integrity of the regenerative heat exchanger is 

confirmed by continuous temperature monitoring.

SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur 

in stainless steel PWR regenerative heat exchanger components exposed to treated 

borated water greater than 140 °F (60 °C). The existing AMP monitors and controls 

primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. 

However, control of water chemistry does not preclude cracking due to SCC and cyclic 

loading; therefore, the effectiveness of Water Chemistry Control Programs should be 

confirmed to ensure that cracking does not occur. The GALL Report recommends that a 

plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic 

loading to ensure that these aging effects are adequately managed.

The staff’s evaluations of the applicant’s Water Chemistry and the One-Time Inspection 

Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its 

review of components associated with item 3.3.1-8, the staff finds that the applicant met 

the further evaluation criteria. The staff also found that the applicant’s proposal to 

manage aging using the specified programs is acceptable because the Water Chemistry 

Program includes control of detrimental contaminants below the levels known to cause 

cracking. Additionally, the one-time inspection of the non-regenerative heat exchanger 

will verify the effectiveness of the Water Chemistry Program and confirm that cracking in 

not occurring in comparable components in the same environment.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.4, item 2, criteria. For those items that apply to LRA 
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Section 3.2.2.2.4.2, the staff determined that the LRA is consistent with the GALL 

Report. The staff also determined that the applicant 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) LRA Section 3.3.2.2.4.3, associated with LRA Table 3.3.1, item 3.3.1-9, addresses 

stainless steel high-pressure pump casings, exposed to treated borated water in the 

chemical and volume control system, which are being managed for cracking due to SCC

and cyclic loading by the Water Chemistry Program and the One-Time Inspection 

Program. The criteria in SRP-LR Section 3.3.2.2.4, item 3, states that cracking due to 

SCC and cyclic loading could occur for stainless steel pump casings for the PWR 

high-pressure pumps in the chemical and volume control system. The SRP-LR also 

states that the GALL Report recommends the existing AMP, including monitoring and 

control of primary water chemistry. The SRP-LR further recommends that this aging 

issue be managed by a plant-specific program to verify the effectiveness of the Water 

Chemistry Control Program. The applicant addressed the further evaluation criteria of 

the SRP-LR by stating that the Water Chemistry Program effectiveness will be confirmed 

by the One-Time Inspection Program.

The staff’s evaluations of the applicant’s Water Chemistry Program and the One-Time 

Inspection Program are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.3.1-9, the staff finds 

that the applicant met the further evaluation criteria, and the applicant’s proposal to 

manage aging using the Water Chemistry Program and the One-Time Inspection 

Program is acceptable because the Water Chemistry Program establishes the plant 

water chemistry control parameters and their limits to mitigate the environmental effect 

that can cause cracking and takes actions if the parameters exceed the limits. 

Additionally, the One-Time Inspection Program is adequate to confirm the effectiveness 

of the Water Chemistry Program.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.4, item 3, criteria. For those items that apply to LRA 

Section 3.3.2.2.4.3, the staff determined 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 be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(4) LRA Section 3.3.2.2.4.4, associated with LRA Table 3.3.1, item 3.3.1-10, addresses 

cracking due to SCC and cyclic loading in high-strength steel closure bolting exposed to 

air with steam or water leakage. The applicant stated that this item is not applicable 

because there is no high-strength steel closure bolting exposed to air with steam or 

water leakage in the auxiliary system. The staff reviewed LRA Sections 2.3.3 and 3.3 

and the UFSAR and confirmed that no in-scope high-strength steel closure bolting 

exposed to air with steam or water leakage are present in the auxiliary system; 

therefore, it finds the applicant’s claim acceptable.

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

The staff reviewed LRA Section 3.3.2.2.5 against the following criteria in SRP-LR 

Section 3.3.2.2.5:
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(1) LRA Section 3.3.2.2.5.1, is associated with LRA Table 3.3.1, item 3.3.1-11, and 

addresses elastomer seals and components exposed to air-indoor uncontrolled, internal

or external environments, which are being managed for hardening and loss of strength 

due to elastomer degradation by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program for internal surfaces and the External 

Surfaces Monitoring Program for external surfaces. The criteria in SRP-LR 

Section 3.3.2.2.5, item 1, state that hardening and loss of strength due to elastomer 

degradation may occur in elastomeric seals and components associated with auxiliary 

heating and ventilation systems that are exposed either internally or externally to 

uncontrolled indoor air. The SRP-LR recommends further evaluation of a plant-specific 

AMP to ensure that these aging effects are adequately managed. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program is 

adequate to manage the aging effects on the internal surfaces of these components, and 

the External Surfaces Monitoring Program is adequate to manage the aging effects on 

the external surfaces of these components.

SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer 

degradation may occur in elastomer seals and components of heating and ventilation 

systems exposed to air-indoor uncontrolled (internal or external). The GALL Report 

recommends further evaluation of a plant-specific AMP to ensure that these aging 

effects are adequately managed.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. 

The staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program provides for inspections of opportunity, performed during 

pre-planned, periodic system and component surveillances, or during maintenance 

activities when the systems are opened and the surfaces are made accessible for visual 

inspection. The staff also noted that for elastomeric materials, the program uses tactile 

techniques, which include scratching, bending, folding, stretching, and pressing in 

conjunction with the visual examinations.

The staff’s evaluation of the applicant’s Inspection of External Surfaces Monitoring 

Program is documented in SER Section 3.0.3.2.14. The staff noted that the External 

Surfaces Monitoring Program uses periodic system inspections and walkdowns to 

monitor for materials degradation and leakage. The staff also noted that for elastomeric 

materials, the program uses tactile techniques, which include scratching, bending, 

folding, stretching, and pressing in conjunction with the visual examinations.

In its review of components associated with LRA Table 3.3.1, item 3.3.1-11, the staff 

finds that the applicant met the further evaluation criteria. The staff also finds that the 

applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program and the External Surfaces 

Monitoring Program is acceptable because the programs use a methodology that is 

capable of detecting hardening and loss of strength caused by elastomer degradation 

before loss of intended function occurs.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.5, item 1, criteria. For those items that apply to LRA 

Section 3.2.2.2.5.1, the staff determined that the LRA is consistent with the GALL 
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Report. The staff also determined that the applicant 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 3.3.2.2.5.2, is associated with LRA Table 3.3.1, item 3.3.1-12, and 

addresses elastomer lined components exposed to treated borated water in the 

chemical and volume control system, which are being managed for hardening and loss 

of strength due to elastomer degradation by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program.

The criteria in SRP-LR Section 3.3.2.2.5, item 2, state that hardening and loss of 

strength due to elastomer degradation may occur in elastomer linings of the filters, 

valves, and ion exchangers in spent fuel pool cooling and cleanup systems (BWR and 

PWR) exposed to treated water or to treated borated water. The SRP-LR also states 

that the GALL Report recommends that a plant-specific AMP be evaluated that

determines and assesses the qualified life of the elastomeric liners in the environment to 

ensure that these aging effects are adequately managed. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is adequate to 

manage the aging effects of these components.

The applicant is using LRA Table 3.3.1, item 3.3.1-12, to address elastomer flex hoses 

exposed to treated borated water. The staff noted that elastomer flex hoses, when 

exposed to treated borated water, will have the same aging effect of hardening and loss 

of strength as elastomer-lined components in the same environment. The applicant 

stated that for item 3.3.1-12, the applicability is limited to the chemical and volume 

control system. The staff also noted that a search of the applicant’s UFSAR for the 

spent fuel pool cooling and cleanup and chemical volume control systems confirmed that 

no in-scope elastomer-lined components exposed to treated borated water are present 

in the spent fuel pool cooling and cleanup system.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. 

The staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program provides for inspections of opportunity, performed during 

pre-planned, periodic system and component surveillances, or during maintenance 

activities when the systems are opened and the surfaces are made accessible for visual 

inspection. The staff also noted that for elastomeric materials, the program uses tactile 

techniques, which include scratching, bending, folding, stretching, and pressing in 

conjunction with the visual examinations.

In its review of components associated with LRA Table 3.3.1, item 3.3.1-12, the staff 

finds that the applicant met the further evaluation criteria. Additionally, the staff finds 

that the applicant’s proposal to manage aging using the Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components Program is acceptable because the 

program uses a methodology that is capable of detecting hardening and loss of strength 

caused by elastomer degradation before loss of intended function occurs.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.5, item 2, criteria. For those items that apply to LRA 

Section 3.2.2.2.5.2, the staff determined that the LRA is consistent with the GALL 
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Report. The staff also determined that the applicant demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion 

LRA Section 3.3.2.2.6, referenced by LRA Table 3.3.1, item 3.3.1-13, addresses Boral, boron 

steel spent fuel storage racks neutron-absorbing sheets exposed to treated water or treated 

borated water, which are being managed for reduction of neutron–absorbing capacity and loss 

of material due to general corrosion. The applicant addressed the further evaluation criteria by 

stating that the Boral Monitoring Program, B.2.2.2, will be used to manage reduction of the 

neutron-absorbing capacity and loss of material due to general corrosion of the Boral poison 

sheet in the spent fuel pool, in treated water exposed to treated borated water.

The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6, which 

states that reduction of neutron-absorbing capacity and loss of material due to general corrosion 

could occur in the neutron-absorbing sheets of BWR and PWR spent fuel storage racks 

exposed to treated water or to treated borated water. The SRP-LR also states that the GALL 

Report recommends further evaluation of a plant-specific AMP to ensure that these aging 

effects are adequately managed and that acceptance criteria are described in BTP RLSB-1.

The staff evaluated the applicant’s Boral Monitoring Program, as documented in SER 

Section 3.0.3.3.3. In its review of components associated with item 3.3.1-13, the staff finds the 

applicant’s proposal to manage aging using the Boral Monitoring Program acceptable because 

the Boral Monitoring Program satisfies the acceptance criteria of the SRP-LR and uses 

inspection techniques (e.g., boron areal density measurement, and visual inspections) that will 

detect aging effects related to the neutron absorption and dimensional integrity.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.6 criteria. For those items that apply to LRA Section 3.3.2.2.6, the staff 

determined that the LRA is consistent with the GALL Report, and the applicant demonstrated 

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

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.3.2.2.7 against the following criteria in SRP-LR 

Section 3.3.2.2.7:

(1) LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1-14, addresses steel 

piping, piping components, and piping elements exposed to lubricating oil, which are 

being managed by the Lubricating Oil Analysis and One-Time Inspection Programs. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that the 
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One-Time Inspection Program will be used to verify the effectiveness of the Lubricating 

Oil Analysis Program to manage loss of material due to general, pitting, and crevice 

corrosion through examination of susceptible locations in steel tanks in the chemical and 

volume control, diesel generator, instrument air, and miscellaneous equipment systems. 

The applicant further stated that the Lubricating Oil Analysis Program and the One-Time 

Inspection Program will also be used to manage loss of material due to general, pitting, 

and crevice corrosion through examination of susceptible locations in steel piping 

components in the chemical and volume control system, diesel generator, fire protection, 

instrument air, miscellaneous equipment, and service water systems. Finally, the 

applicant stated that the Lubricating Oil Analysis Program and the One-Time Inspection 

Program will be used to manage loss of material due to general, pitting, and crevice 

corrosion through examination of susceptible locations in galvanized steel piping 

components in the service water system.

LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1-15, addresses steel 

reactor coolant pump oil collection system tank exposed to lubricating oil, which are 

being managed for loss of material due to general, pitting, and crevice corrosion by the 

Lubricating Oil Analysis and One-Time Inspection Programs. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that this item was not applicable 

because Seabrook does not have steel containment isolation piping, piping components, 

crevice corrosion evaluated components, and piping elements internal surfaces exposed 

to lubricating oil in the oil collection for reactor coolant pumps system.

LRA Section 3.3.2.2.7.1, referenced by LRA Table 3.3.1, item 3.3.1-16, addresses steel 

reactor coolant pump oil collection system and chemical and volume control system 

tanks exposed to lubricating oil, which are being managed for loss of material due to 

general, pitting, and crevice corrosion by the Lubricating Oil Analysis and One-Time 

Inspection Programs. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that the One-Time Inspection Program will be used to verify the 

effectiveness of the Lubricating Oil Analysis Program to manage for loss of material due 

to general, pitting, and crevice corrosion by the Lubricating Oil Analysis and One-Time 

Inspection Programs. Additionally, the applicant stated that the Lubricating Oil Analysis 

and One-Time Inspection Programs will manage loss of material due to general, pitting, 

and crevice corrosion by including a one-time thickness measurement on the bottom 

portion of the steel tanks exposed to lubricating oil in the oil collection for the reactor 

coolant pumps system.

The staff reviewed LRA Section 3.3.2.2.7.1 against the criteria in SRP-LR 

Section 3.3.2.2.7, item 1, which states that loss of material due to general, pitting, and 

crevice corrosion could occur in steel piping, piping components, and piping elements, 

including the tubing, valves, and tanks in the reactor coolant pump oil collection system, 

exposed to lubricating oil (as part of the fire protection system). The SRP-LR also stated 

that the existing AMP relies on the periodic sampling and analysis of lubricating oil to 

maintain contaminants within acceptable limits, thereby preserving an environment that 

is not conducive to corrosion. The SRP-LR further states that control of lube oil 

contaminants may not always have been adequate to preclude corrosion; therefore, the 

effectiveness of lubricating oil control should be confirmed to ensure that corrosion does 

not occur. The SRP-LR also states that the GALL Report recommends further 

evaluation of programs to manage corrosion to verify the effectiveness of the Lubricating 

Oil Analysis Program for which a one-time inspection of selected components at 

susceptible locations is an acceptable method to ensure that corrosion does not occur
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and that the component’s intended function will be maintained during the period of 

extended operation.

In addition, the SRP-LR states that corrosion may occur at locations in the reactor 

coolant pump oil collection tank where water from wash downs may accumulate; 

therefore, the effectiveness of the program should be confirmed to ensure that corrosion 

does not occur. The SRP-LR also states that the GALL Report recommends further 

evaluation of programs to manage loss of material due to general, pitting, and crevice 

corrosion. This includes determining the thickness of the lower portion of the tank for 

which a one-time inspection is an acceptable method to ensure that corrosion does not 

occur and that the component’s intended function will be maintained during the period of 

extended operation.

The staff reviewed Table 3.3.2-25, “Oil Collection for Reactor Coolant Pump System, 

Summary of Aging Management Evaluation,” of the applicants LRA and the UFSAR to 

verify that there is no steel reactor coolant pump oil collection system piping components 

exposed to lubricating oil in the oil collection for reactor coolant pumps system. Based 

on the information provided in Table 3.3.2-25, the staff confirmed that the oil collection 

for reactor coolant pumps system only has stainless steel piping components exposed to 

lubricating oil. Therefore, the staff finds that item 3.3.1-15 is not applicable.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8,

respectively. In its review of components associated with items 3.3.1-14 and 3.3.1-16, 

the staff finds the applicant’s proposal to manage the applicable aging using the 

One-Time Inspection Program to verify the effectiveness of the Lubricating Oil Analysis 

Program acceptable. The Lubricating Oil Analysis Program was determined to be 

consistent with the GALL Report, and the applicant stated that the One-Time Inspection 

Program will be used to examine steel piping and piping components to verify the 

effectiveness of the Lubricating Oil Analysis Program. 

Based on the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.3.2.2.7, item 1 criteria. For those items that apply to 

LRA Section 3.3.2.2.7.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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 3.3.2.2.7.2, associated with LRA Table 3.3.1, item 3.3.1-17, addresses loss 

of material due to general, pitting, and crevice corrosion in BWR steel piping, piping 

components, and piping elements exposed to treated water. The applicant stated that 

this item is not applicable because it is only applicable to BWRs. The staff reviewed the 

SRP-LR and LRA Section 3.3 and noted that this item is associated only with BWRs; 

therefore, if finds the applicant’s claim acceptable.

(3) LRA Section 3.3.2.2.7.3 is associated with LRA Table 3.3.1, item 3.3.1-18, and 

addresses stainless steel and steel diesel engine exhaust piping, piping components, 

and piping elements exposed to diesel exhaust, which are being managed for loss of 

material due to general (steel only), pitting, and crevice corrosion by the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components. The criteria in 

SRP-LR Section 3.3.2.2.7, item 3, state that loss of material due to general (steel only),

pitting, and crevice corrosion could occur for steel and stainless steel diesel exhaust 
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piping, piping components, and piping elements exposed to diesel exhaust. The 

SRP-LR states that a plant-specific AMP should be used. The SRP-LR also states that 

acceptance criteria for a plant-specific AMP will include a description of its basis and 

analysis methodology, ensure continued functional operation of structure and 

components, contain quantified criteria or a illustrate method of quantification, and 

discuss qualitative inspections via ASME or site-specific criteria. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that it will implement 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program to manage loss of material due to general (steel only), pitting, and crevice 

corrosion of the steel piping components, steel silencer (diesel generator system), and 

stainless steel piping components exposed to diesel exhaust in the diesel generator 

system and fire protection system.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program is documented in SER Section 3.0.3.2.15. 

The staff noted that the AMP includes visual surface, magnification, and ultrasonic 

inspection methods. The staff also noted that reports will be evaluated by a system 

engineer who will help ensure the extent and schedule of inspections to detect 

degradation prior to loss of function, and these reviews will include trending to determine 

whether the number of locations and intervals are providing aging management 

consistent with the CLB. Acceptance criteria for various corrosion mechanisms will be 

identified in appropriate inspection procedures. In its review of components associated 

with LRA Table 3.3.1, item 3.3.1-18, the staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program is 

acceptable for the following reasons:

• The applicant will perform sufficient inspections for each 

material-environment combination to provide an overall assessment of 

any aging degradation that may be occurring.

• The selection of inspections will consider materials, operating 

environments, industry and plant-specific operating experience, 

engineering evaluations of equipment performance, and susceptibility to 

aging due to time in service, severity of operating conditions, and lowest 

design margins.

• Recurring surveillance and maintenance activities provides the ability to 

detect aging of the material prior to loss of function.

• Inspection results will be trended.

Based on the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.3.2.2.7, item 3 criteria. For those items that apply to 

LRA Section 3.3.2.2.7.3, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice and Microbiologically-Influenced 

Corrosion

The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8.
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LRA Section 3.3.2.2.8 is associated with LRA Table 3.3.1, item 3.3.1-19, and addresses steel 

piping, piping components and piping elements exposed to soil, which are being managed for 

loss of material due to general, pitting, crevice, and MIC by the Buried Piping and Tanks 

Inspection Program. The criteria in SRP-LR Section 3.3.2.2.8, state that the loss of material 

due to general, pitting, crevice, and MIC could occur for steel (with or without coating or 

wrapping) piping, piping components, and piping elements exposed to soil environment. The 

SRP-LR also states that the Buried Piping and Tanks Inspection Program relies on industry 

practice, frequency of pipe excavation, and operating experience to manage the effects of loss 

of material aging effect. The applicant addressed the further evaluation criteria of the SRP-LR 

by stating that the Buried Piping and Tanks Inspection Program will use external coatings and 

wrappings installed to industry standards on buried piping as well as periodic inspections to 

determine loss of material. The staff noted that the applicant stated, in LRA Section B.2.1-22,

under the “detection of aging effects” program element that inspections locations would be, in 

part, based on areas with a history of corrosion problems.

SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice 

corrosion and MIC may occur in steel (with or without coating or wrapping) piping, piping 

components, and piping elements buried in soil. Buried Piping and Tanks Inspection Programs 

rely on industry practice, frequency of pipe excavation, and operating experience to manage the 

effects of loss of material from general, pitting, and crevice corrosion and MIC. The 

effectiveness of the Buried Piping and Tanks Inspection Program should be confirmed to 

evaluate an applicant’s inspection frequency and operating experience with buried components, 

ensuring that loss of material does not occur.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. The applicant stated that the Buried Piping and Tanks 

Inspection Program will manage loss of material due to general, pitting, crevice, and MIC by 

employing preventive measures such as external coatings and wrappings and performing 

periodic inspections to detect aging effects. The applicant further stated that, during installation, 

steel and stainless steel buried piping contained either external coatings or wrappings to 

mitigate corrosion. The applicant stated that visual inspections will be performed on the 

protective wraps and coatings to look for evidence of damaged wrapping or coating defects. 

The applicant stated that if defects are found then the external surface of the pipe will be further 

inspected for loss of material. The applicant also stated that ultrasonic inspections or other 

advanced inspection methods may be used to detect for loss of material. Additionally, visual 

inspections will be performed at least once during the 10-year period of extended operation or 

when pipes are excavated for maintenance or other activities. In its review of components 

associated with item 3.3.1-19, the staff finds that the applicant has met the further evaluation 

criteria, and the applicant’s proposal to manage aging using the Buried Piping and Tanks 

Inspection Program is acceptable for the following reasons:

• The program includes preventive actions, such as external coatings and wrappings 

installed to industry standard practices and backfill that will not damage the piping or 

coatings, and some systems are protected by a cathodic protection system.

• Periodic visual inspections will be performed starting 10 years prior to the period of 

extended operation and extend into both 10-year periods during the period of extended 

operation to ensure that coatings remain intact or uncoated piping has not degraded.

• Plant-specific operating experience will be used to inform inspection locations.
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• Alternatives to direct visual inspection, such as pressure tests or ultrasonic inspections,

are capable of detecting piping degradation.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.8 criteria. For those items that apply to LRA Section 3.3.2.2.8, the staff 

determined that the LRA is consistent with the GALL Report, and the applicant demonstrated 

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

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced 

Corrosion, and Fouling 

The staff reviewed LRA Section 3.3.2.2.9 against the following criteria in SRP-LR 

Section 3.3.2.2.9:

(1) LRA Section 3.3.2.2.9.1, referenced by LRA Table 3.3.1, item 3.3.1-20, addresses steel 

piping, piping components, piping elements, and tanks exposed to fuel oil, which are 

being managed for loss of material due to general, pitting, crevice, MIC, and fouling by 

the Fuel Oil Chemistry Program and One-Time Inspection Program. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the One-Time 

Inspection Program will be used to verify the effectiveness of the Fuel Oil Chemistry 

Program to manage the loss of material through examination of susceptible locations in 

steel piping, piping components, piping elements, and tanks exposed to fuel oil in the 

fuel oil system.

The staff reviewed LRA Section 3.3.2.2.9.1 against the criteria in SRP-LR 

Section 3.3.2.2.9, item 1, which states loss of material due to general, pitting, crevice, 

MIC, and fouling could occur for steel piping, piping components, piping elements, and 

tanks exposed to fuel oil. The SRP-LR also stated that the existing AMP relies on the 

Fuel Oil Chemistry Program for monitoring and control of fuel oil contamination to 

manage loss of material due to corrosion or fouling. Corrosion or fouling may occur at 

locations where contaminants accumulate. The effectiveness of the fuel oil chemistry 

control should be confirmed to ensure that corrosion does not occur. The SRP-LR also 

states that the GALL Report recommends further evaluation of programs to manage loss 

of material due to general, pitting, crevice, MIC, and fouling to verify the effectiveness of 

the Fuel Oil Chemistry Program. It also states that a one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion 

does not occur and that the component's intended function will be maintained during the 

period of extended operation.

The staff’s evaluations of the applicant’s Fuel Oil Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.2.10 and 3.0.3.1.8, respectively. In its 

review of components associated with item 3.3.1-20, the staff finds the applicant’s 

proposal to manage aging using the One-Time Inspection Program to verify the 

effectiveness of the Fuel Oil Chemistry Program acceptable because the Fuel Oil 

Chemistry Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Time Inspection Program will be used to 

examine steel piping, piping components, piping elements to verify the effectiveness of 

the Fuel Oil Chemistry Program. This satisfies the acceptance criteria in SRP-LR 

Section 3.3.2.2.9, item 1; therefore, the applicant’s AMR is consistent with GALL Report.
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Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.9, item 1, criteria. For the items that apply to LRA 

Section 3.3.2.2.9.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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 3.3.2.2.9.2, referenced by LRA Table 3.3.1, item 3.3.1-21, addresses steel 

heat exchanger components exposed to lubricating oil, which are being managed for 

loss of material due to general, pitting, crevice, MIC, and fouling by the Lubricating Oil 

Analysis and One-Time Inspection Programs. SRP-LR Section 3.3.2.2.9, item 2, states 

that loss of material due to general, pitting, and crevice corrosion, MIC, and fouling may 

occur in steel heat exchanger components exposed to lubricating oil. The existing AMP 

periodically samples and analyzes lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment not conducive to corrosion.

However, control of lube oil contaminants may not always be fully effective in precluding 

corrosion; therefore, the effectiveness of lubricating oil control should be confirmed to 

ensure that corrosion does not occur. The GALL Report recommends further evaluation 

of programs to manage corrosion to verify the effectiveness of lubricating oil programs.

A one-time inspection of selected components at susceptible locations is an acceptable 

method to ensure that corrosion does not occur and that component-intended functions 

will be maintained during the period of extended operation.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.3.1-21, the staff finds 

the applicant’s proposal to manage aging using the One-Time Inspection Program to 

verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the 

Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Time Inspection Program will be used to 

examine steel heat exchanger components to verify the effectiveness of the Lubricating 

Oil Analysis Program. This satisfies the acceptance criteria in SRP-LR 

Section 3.3.2.2.9, item 2; therefore, the applicant’s AMR is consistent with the GALL 

Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.9, item 2, criteria. For the items that apply to LRA 

Section 3.3.2.2.9.2, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.10 Loss of Material due to Pitting and Crevice Corrosion

(1) LRA Section 3.3.2.2.10.1, associated with LRA Table 3.3.1, item 3.3.1-22, addresses 

loss of material due to pitting and crevice corrosion in steel piping with elastomer lining 

or stainless steel cladding exposed to treated water or treated borated water if the 

cladding or lining is degraded. The applicant stated that this item is not applicable 

because there are no steel with elastomer lining components exposed to treated borated 

water in the spent fuel pool cooing system, and GALL Report item VII.A4-12 is only 

applicable to BWR plants.
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The staff reviewed LRA Sections 2.3.3 and 3.3 and the UFSAR and confirmed that no 

in-scope steel piping with elastomer lining exposed to treated borated water is present in 

the spent fuel pool cooing system. The staff confirmed that GALL Report item VII.A4-12, 

steel with elastomer lining or stainless steel cladding, is only applicable to BWR plants; 

therefore, it finds the applicant’s claim acceptable.

(2) LRA Section 3.3.2.2.10.2, associated with LRA Table 3.3.1, items 3.3.1-23 and 3.3.1-24, 

addresses loss of material due to pitting and crevice corrosion in stainless steel and 

steel with stainless steel cladding heat exchanger components, and stainless steel and 

aluminum piping, piping components, and piping elements exposed to treated water. 

The applicant stated that these items are not applicable because they are only 

applicable to BWRs.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice 

corrosion may occur in stainless steel and aluminum piping, piping components, piping 

elements, and for stainless steel and steel with stainless steel cladding heat exchanger 

components exposed to treated water. The existing AMP monitors and controls reactor 

water chemistry to manage the aging effects of loss of material from pitting and crevice 

corrosion. However, high concentrations of impurities in crevices and with stagnant flow 

conditions may cause pitting or crevice corrosion; therefore, the effectiveness of Water 

Chemistry Control Programs should be confirmed to ensure that corrosion does not 

occur. The GALL Report recommends further evaluation of programs to manage loss of 

material from pitting and crevice corrosion to verify the effectiveness of Water Chemistry 

Control Programs. A one-time inspection of selected components at susceptible 

locations is an acceptable method to ensure that corrosion does not occur and that 

component-intended functions will be maintained during the period of extended 

operation.

The staff noted that SRP-LR items 3.3.1-23 and 3.3.1-24 are associated with GALL 

items VII.A4-2, VII.A4-5, VII.A4-11, VII.E3-7, VII.E3-15, VII.E4-4, and VII.E4-14, all of 

which are associated with BWR spent fuel pool cooling and cleanup, reactor water 

cleanup, and shutdown cooling systems; therefore, it finds the applicant’s claim 

acceptable. The staff also noted that LRA items with the same component, material, 

environment, and aging effect combination are managed for aging by items 3.4.1-15 and 

3.4.1-16 instead of items 3.3.1-23 and 3.3.1-24, and these alternative items are 

consistent with the GALL Report’s recommended programs.

(3) LRA Section 3.3.2.2.10.3, is associated with LRA Table 3.3.1, item 3.3.1-25, and 

addresses the copper-alloy HVAC piping, piping components, and piping elements in the 

chlorination, screen wash, service water, and waste processing liquid systems, and 

copper-alloy heat exchanger components in the containment air handling, containment 

enclosure air handling, and control building air handling systems exposed to 

condensation (external), which are being managed for loss of material due to pitting, 

galvanic or crevice corrosion by the External Surfaces Monitoring, Bolting Integrity 

Program, or Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Programs.

The criteria in SRP-LR Section 3.3.2.2.10, item 3, states that loss of material due to 

pitting and crevice corrosion could occur for copper-alloy HVAC piping, piping 

components, and piping elements exposed to condensation (external). The SRP-LR 

also states that the GALL Report recommends further evaluation of a plant-specific AMP
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to ensure that these aging effects are adequately managed in accordance with the 

acceptance criteria described in BTP RLSB-1. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that copper-alloy piping, copper-alloy heat 

exchanger components, and bolting exposed to condensation (external) will be managed 

for loss of material due to pitting, galvanic, and crevice corrosion by the External 

Surfaces Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components, and Bolting Integrity Programs.

The staff’s evaluations of the applicant’s External Surfaces Monitoring, Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components, and Bolting Integrity 

Programs are documented in SER Sections 3.0.3.2.14, 3.0.3.2.15, and 3.0.3.1.7, 

respectively. The staff noted that the applicant’s External Surfaces Monitoring Program 

provides for visual inspection of component surfaces for pitting, crevice, and galvanic 

corrosion at least once per refueling cycle. The staff also noted that the applicant’s 

Bolting Integrity Program provides for visual inspection of bolting for corrosion. In 

addition, the staff noted that the applicant’s Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program affords opportunistic visual 

inspections by qualified personnel in accordance with station-controlled procedures and 

processes during the pre-planned, periodic system, and component surveillance and 

maintenance activities. In its review of components associated with LRA Table 3.3.1, 

item 3.3.1-25, the staff finds that the applicant met the further evaluation criteria. 

Additionally, the applicant’s proposal to manage aging using the External Surfaces 

Monitoring, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components, and Bolting Integrity Programs is acceptable because these programs 

include periodic visual inspections capable of detecting loss of material due to pitting, 

crevice, or galvanic corrosion.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 3, criteria. For those items that apply to LRA 

Section 3.3.2.2.10.3, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

(4) LRA Section 3.3.2.2.10.4, referenced in Table 3.3.1, item 3.3.1-26, addresses 

copper-alloy piping, piping components, and piping elements exposed to lubricating oil, 

which are being managed for loss of material due to pitting and crevice corrosion by the 

Lubricating Oil Analysis and One-Time Inspection Programs. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that the One-Time Inspection 

Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program 

to manage loss of material due to pitting and crevice corrosion through examination of 

susceptible locations in copper-alloy piping, piping components, and copper-alloy heat 

exchanger components exposed to lubricating oil in the chemical and volume control, 

diesel generator, miscellaneous equipment, instrument air, service water, switchyard 

systems.

The staff reviewed LRA Section 3.3.2.2.10.4 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 4, which states that loss of material due to pitting and crevice 

corrosion could occur for copper-alloy piping, piping components, and piping elements 

exposed to lubricating oil. The SRP-LR also states that the existing AMP relies on the 

periodic sampling and analysis of lubricating oil to maintain contaminants within 
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acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

The SRP-LR further states that control of lube oil contaminants may not always have 

been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil 

control should be confirmed to ensure that corrosion does not occur. The SRP-LR also 

states that the GALL Report recommends further evaluation of programs to manage 

corrosion to verify the effectiveness of the Lubricating Oil Analysis Program for which a 

one-time inspection of selected components at susceptible locations is an acceptable 

method to ensure that corrosion does not occur and that the component’s intended 

function will be maintained during the period of extended operation.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.3.1-26, the staff finds 

the applicant’s proposal to manage aging using the One-Time Inspection Program to 

verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the 

Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Time Inspection Program will be used to 

examine copper-alloy piping, piping components, and piping elements to verify the 

effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance 

criteria in SRP-LR Section 3.3.2.2.10, item 4; therefore, the applicant’s AMR is 

consistent with the GALL Report.

(5) LRA Section 3.3.2.2.10.5 is associated with LRA Table 3.3.1, item 3.3.1-27, and 

addresses stainless steel and aluminum components in auxiliary systems exposed to 

condensation (internal) or condensation (external), which are being managed for loss of 

material due to pitting or crevice corrosion. The criteria in SRP-LR Section 3.3.2.2.10, 

item 5, states that loss of material due to pitting and crevice corrosion could occur for 

HVAC aluminum piping, piping components, and piping elements and stainless steel 

ducting and components exposed to condensation. The SRP-LR also states that a 

plant-specific AMP should be evaluated to ensure that these aging effects are 

adequately managed. The applicant addressed the further evaluation criteria of the 

SRP-LR by identifying several AMPs to manage the aging effect, as described below.

The applicant stated the following: 

• The Bolting Integrity Program will be used to manage loss of material due 

to pitting and crevice corrosion of stainless steel bolting exposed to 

condensation (external) in the primary component cooling water, screen 

wash, and service water systems.

• The Compressed Air Monitoring Program will be used to manage loss of 

material due to pitting, crevice, and galvanic corrosion for aluminum 

piping and heat exchanger components (after cooler tubes, filter housing, 

traps) exposed to condensation (internal) in the diesel generator and 

instrument air systems.

• The External Surfaces Monitoring Program will be used to manage loss of 

material due to pitting and crevice corrosion of aluminum heat exchanger 

fins exposed to condensation (external) in the control building air handling 

system.

• The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program will be used to manage loss of material due to 
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pitting, crevice, and galvanic corrosion of aluminum piping components 

exposed to condensation in the fire protection system. It will be used to 

manage loss of material due to pitting and crevice corrosion of stainless 

steel HVAC drip pans and piping exposed to condensation (internal) in 

the containment air handling, containment enclosure air handling, and 

fuel storage building air handling systems.

The staff’s evaluations of the applicant’s Bolting Integrity Program, Compressed Air 

Monitoring Program, External Surfaces Monitoring Program, and Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program are documented in 

SER Sections 3.0.3.1.7, 3.0.3.2.6, 3.0.3.2.14, and 3.0.3.2.15, respectively. The staff 

noted that the Bolting Integrity, Compressed Air Monitoring, External Surfaces 

Monitoring, and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Programs all include visual inspection activities that are capable of 

detecting loss of material due to pitting, crevice, and galvanic corrosion in aluminum and 

stainless steel components. These programs implement corrective action if 

unacceptable indications of loss of material due to pitting, crevice, or galvanic corrosion 

are found. The staff also noted that the Compressed Air Monitoring Program also 

includes monitoring of air system quality and preventive activities to reduce the potential 

for presence of moisture and occurrence of corrosion. The staff further noted that 

components associated with LRA Table 3.3.1, item 3.3.1-27, addressed by the Bolting 

Integrity Program, the External Surfaces Monitoring Program, and the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program are 

typically accessible for visual examination during normal operation or routine plant 

outages. In its review of components associated with LRA Table 3.3.1, item 3.3.1-27, 

the staff finds that the applicant has met the further evaluation criteria, and the 

applicant’s proposal to manage aging using the Bolting Integrity Program, Compressed 

Air Monitoring Program, External Surfaces Monitoring Program, and Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program is 

acceptable for the following reasons:

• The components associated with LRA Table 3.3.1, item 3.3.1-27, are 

typically accessible for inspection either during normal operation or 

routine plant outages.

• Each of the credited programs includes visual inspections that are 

capable of detecting loss of material due to pitting, crevice, and galvanic 

corrosion in aluminum and stainless steel components.

• Each credited program includes requirements for implementing corrective 

actions if unacceptable indications of loss of material due to pitting, 

crevice, or galvanic corrosion are found.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 5, criteria. For those items that apply to LRA 

Section 3.3.2.2.10.5, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

(6) LRA Section 3.3.2.2.10.6, is associated with LRA Table 3.3.1, item 3.3.1-28, and 

addresses copper-alloy fire protection piping and piping components and tanks in the 
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diesel generator, instrument air, and fire protection systems exposed to condensation 

(internal), which are being managed for loss of material due to pitting and crevice 

corrosion by the Compressed Air Monitoring and the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Programs. The criteria in SRP-LR 

Section 3.3.2.2.10, item 6, states that loss of material due to pitting and crevice 

corrosion could occur for copper-alloy piping, piping components, and piping elements 

exposed to internal condensation. The SRP-LR also states that the GALL Report 

recommends further evaluation of a plant-specific AMP to ensure that these aging 

effects are adequately managed in accordance with the acceptance criteria described in 

BTP RLSB-1. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that copper-alloy piping components exposed to condensation will be managed 

for loss of material due to pitting and crevice corrosion by the Compressed Air 

Monitoring and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Programs.

The staff’s evaluations of the applicant’s Compressed Air Monitoring and Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Programs are 

documented in SER Sections 3.0.3.2.6 and 3.0.3.2.15, respectively. In its review of 

components associated with LRA Table 3.3.1, item 3.3.1-28, the staff finds that the 

applicant met the further evaluation criteria. Additionally, the staff finds that the 

applicant’s proposal to manage aging using the Compressed Air Monitoring and 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Programs is acceptable because these programs provide for preventive actions, 

inspections, and detection of aging effects of copper alloys.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 6, criteria. For those items that apply to LRA 

Section 3.3.2.2.10.6, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

(7) LRA Section 3.3.2.2.10.7 addresses loss of material due to pitting and crevice corrosion 

in stainless steel piping, piping components, and piping elements exposed to soil. LRA 

Section 3.3.2.2.10.7 is associated with LRA Table 3.3.1, item 3.3.1-29, and addresses 

stainless steel piping, piping components and piping elements exposed to soil, which are 

being managed for loss of material due to pitting and crevice corrosion by the Buried 

Piping and Tanks Inspection Program. The criteria in SRP-LR Section 3.3.2.2.10, 

item 7, states that the loss of material due to pitting, crevice, and MIC could occur for 

stainless steel piping, piping components, and piping elements exposed to soil 

environment. The SRP-LR also states that a plant-specific AMP will be used to manage 

the loss of material aging effect. The applicant addressed the further evaluation criteria 

of the SRP-LR by stating that the Buried Piping and Tanks Inspection Program will use 

external coatings and wrappings on buried piping as well as periodic inspections to 

determine loss of material.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. In its review of components associated with LRA

Table 3.3.1, item 3.3.1-29, the staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the Buried Piping 

and Tanks Inspection Program is acceptable for the following reasons:
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• The program includes preventive actions such as external coatings and 

wrappings installed to industry standard practices and backfill that will not 

damage the piping or coatings, and some systems are protected by a 

cathodic protection system.

• Periodic visual inspections will be performed starting 10 years prior to the 

period of extended operation and extend into both 10-year periods during 

the period of extended operation to ensure that coatings remain intact or 

uncoated piping has not degraded.

• Plant-specific operating experience will be used to inform inspection 

locations.

• Alternatives to direct visual inspection, such as pressure tests or 

ultrasonic inspections, are capable of detecting piping degradation.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.10, item 7, criteria. For those items that apply to LRA 

Section 3.3.2.2.10.7, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

(8) LRA Section 3.3.2.2.10.8, associated with LRA Table 3.3.1, item 3.3.1-30, addresses 

loss of material due to pitting and crevice corrosion in stainless steel piping, piping 

components, and piping elements of the BWR standby liquid control system exposed to 

sodium pentaborate solution. The applicant stated that this item is not applicable 

because it is only applicable to BWRs. The staff reviewed the SRP-LR and LRA 

Section 3.3 and noted that this item is associated only with BWRs; therefore, it finds the 

applicant’s claim acceptable.

3.3.2.2.11 Loss of Material due to Pitting, Crevice, and Galvanic Corrosion

LRA Section 3.3.2.2.11, associated with LRA Table 3.3.1, item 3.3.1-31, addresses loss of 

material due to pitting, crevice, and galvanic corrosion of copper-alloy piping, piping 

components, and piping elements that are exposed to treated water. The applicant stated that 

this item is not applicable because LRA Table 3.3.1, item 3.3.1-31, is applicable to BWRs only. 

The staff reviewed LRA Sections 2.3.4 and 3.4 and found that there are in-scope copper-alloy

instrumentation elements, valve bodies, and heat exchanger components exposed to treated 

water in the auxiliary steam condensate and feedwater systems. The staff noted that although 

loss of material due to selective leaching for these components is managed with Selective 

Leaching of Materials Program, there are no actions identified to manage loss of material due to 

pitting, crevice, and galvanic corrosion for these components.

By letter dated January 5, 2011, the staff issued RAI 3.3.2.2-1 requesting that the applicant 

justify why the copper-alloy piping, piping components, and piping elements exposed to treated 

water would not be vulnerable to pitting, crevice, and galvanic corrosion.

In its response dated February 3, 2011, the applicant stated that auxiliary steam condensate, 

condensate, and feedwater systems were evaluated under Section 3.4 of the LRA, “Aging 

Management of Steam and Power Conversion Systems,” and, therefore, aligned with 

Section 3.4.2.2.7.1 and item 3.4.1-15. The staff noted that components under item LRA

Table 3.4.1, item 3.4.1-15, are managed for loss of material due to pitting and crevice corrosion 
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in aluminum and copper-alloy piping, piping components, and piping elements exposed to 

treated water by the One-Time Inspection and Water Chemistry Programs. The staff’s 

evaluations of the applicant’s One-Time Inspection and Water Chemistry Programs are 

documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The staff finds the 

applicant’s response acceptable because adherence to the water chemistry guidelines through 

the implementation of the Water Chemistry Program minimizes the presence of contaminants 

that may lead to pitting and crevice corrosion in those components. The One-Time Inspection 

Program provides an inspection opportunity to verify the effectiveness of the Water Chemistry 

Program. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

(1) LRA Section 3.3.2.2.12.1 is associated with LRA Table 3.3.1, item 3.3.1-32, and 

addresses stainless steel, aluminum and copper-alloy piping, piping components, and 

piping elements exposed to fuel oil, which are being managed for loss of material due to 

pitting, crevice, and MIC by the Fuel Oil Chemistry and One-Time Inspection Programs. 

The staff noted that the LRA states that galvanic corrosion is an additional aging effect 

that will be managed for the aluminum components in the diesel generator system. The 

criteria in SRP-LR Section 3.3.2.2.12, item 1, state that loss of material due to pitting, 

crevice, and MIC could occur for stainless steel, aluminum, and copper-alloy

components exposed to fuel oil. The SRP-LR also states that corrosion may occur at 

locations where contaminants accumulate, and the effectiveness of fuel oil chemistry 

control should be confirmed to ensure that corrosion does not occur. The SRP-LR 

further states that a one-time inspection of selected components at susceptible locations 

is an acceptable method to ensure that corrosion does not occur and that the 

component’s intended function will be maintained during the period of extended 

operation. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating it will implement the One-Time Inspection Program to verify the effectiveness of 

the Fuel Oil Chemistry Program to ensure that these aging effects are adequately 

managed.

The staff’s evaluations of the applicant’s Fuel Oil Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.2.10 and 3.0.3.1.8, respectively. The 

staff noted that the Fuel Oil Chemistry Program includes activities to monitor fuel oil 

chemistry quality, remove water, and clean and inspect the tanks. The staff also noted 

that the One-Time Inspection Program will inspect a sample of components in systems 

that contain fuel oil for evidence of effective management of loss of material. In its 

review of components associated with LRA Table 3.3.1, item 3.3.1-32, the staff finds the 

applicant’s proposal to manage aging using the Fuel Oil Chemistry and One-Time 

Inspection Programs acceptable because the Fuel Oil Chemistry Program includes 

activities to ensure contaminants that could cause corrosion do not accumulate. 

Additionally, the One-Time Inspection Program provides for visual inspections to confirm 

the effectiveness of the Fuel Oil Chemistry Program, which is consistent with the 

guidance in the SRP-LR.
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Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.12, item 1, criteria. For those items that apply to LRA 

Section 3.3.2.2.12.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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 3.3.2.2.12.2, referenced in Table 3.3.1, item 3.3.1-33, addresses stainless 

steel piping, piping components, and piping elements exposed to lubricating oil, which 

are being manage for loss of material due to pitting, crevice, and MIC by the Lubricating 

Oil Analysis and One-Time Inspection Programs. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the One-Time Inspection Program will 

be used to verify the effectiveness of the Lubricating Oil Analysis Program to manage 

loss of material due to pitting, crevice, and MIC through examination of susceptible 

locations in stainless steel piping, stainless steel drip pan components, stainless steel 

flame arrestor, stainless steel tank, and stainless steel heat exchanger components 

exposed to lubricating oil in the chemical and volume control, diesel generator, fire 

protection, instrument air, miscellaneous equipment, oil collection for reactor coolant 

pumps, and switchyard systems.

The staff reviewed LRA Section 3.3.2.2.12.2 against the criteria in SRP-LR 

Section 3.3.2.2.12, item 2, which states that loss of material due to pitting, crevice, and 

MIC could occur in stainless steel piping, piping components, and piping elements 

exposed to lubricating oil. The SRP-LR also states that the existing AMP relies on the 

periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby an environment that is not conducive to corrosion. The 

SRP-LR further states that control of lube oil contaminants may not always have been 

adequate to preclude corrosion; therefore, the effectiveness of lubricating oil control 

should be confirmed to ensure that corrosion does not occur. The SRP-LR also states 

that the GALL Report recommends further evaluation of programs to manage corrosion 

to verify the effectiveness of the Lubricating Oil Analysis Program for which a one-time 

inspection of selected components at susceptible locations is an acceptable method to 

ensure that corrosion does not occur and that the component’s intended function will be 

maintained during the period of extended operation.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.3.1-33, the staff finds 

the applicant’s proposal to manage aging using the One-Time Inspection Program to 

verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the 

Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Inspection Program will be used to 

examine stainless steel piping, piping components, piping elements, and heat exchanger 

components to verify the effectiveness of the Lubricating Oil Analysis Program. This 

satisfies the acceptance criteria in SRP-LR Section 3.3.2.2.12, item 2; therefore, the 

applicant’s AMR is consistent with the GALL Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.12, item 2, criteria. For the items that apply to LRA 

Section 3.3.2.2.12.2, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant demonstrated that the effect of aging will be adequately 
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managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.13 Loss of Material Due to Wear 

LRA Section 3.3.2.2.13 is associated with LRA Table 3.3.1, item 3.3.1-34, and addresses 

elastomer seals and components exposed to air-indoor uncontrolled (internal or external) which 

are being managed for loss of material due to wear by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program for internal surfaces and the External 

Surfaces Monitoring Program for external surfaces. The criteria in SRP-LR Section 3.3.2.2.13 

state that loss of material due to wear could occur in the elastomer seals and components 

exposed to air-indoor uncontrolled (internal or external). The SRP-LR also states that the GALL 

Report recommends further evaluation of a program to ensure that the aging effects are 

adequately managed. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is adequate to manage the aging effects on the internal surfaces of these 

components, and the External Surfaces Monitoring Program is adequate to manage the aging 

effects on the external surfaces of these components.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff noted 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program provides for inspections of opportunity, performed during pre-planned, periodic system 

and component surveillances or during maintenance activities when the systems are opened 

and the surfaces are made accessible for visual inspection. The staff also noted that for 

elastomeric materials, the program uses tactile techniques, which include scratching, bending, 

folding, stretching, and pressing in conjunction with the visual examinations.

The staff’s evaluation of the applicant’s Inspection of External Surfaces Monitoring Program is 

documented in SER Section 3.0.3.2.14. The staff noted that the External Surfaces Monitoring 

Program uses periodic system inspections and walkdowns to monitor for materials degradation 

and leakage. The staff also noted that for elastomeric materials, the program uses tactile 

techniques, which include scratching, bending, folding, stretching, and pressing in conjunction 

with the visual examinations.

The staff finds that the applicant met the further evaluation criteria and the applicant’s proposal 

to manage aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program and the External Surfaces Monitoring Program is acceptable because the 

program uses visual inspections and tactile techniques that are capable of detecting loss of 

material due to wear before loss of intended function.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.13 criteria. For those items that apply to LRA Section 3.3.2.2.13, the 

staff determined that the LRA is consistent with the GALL Report, and the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.3.2.2.14 Loss of Material Due to Cladding Breach

The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP-LR Section 3.3.2.2.14.
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LRA Section 3.3.2.2.14, associated with LRA Table 3.3.1, item 3.3.1-35, addresses loss of 

material due to cladding breach in pump casings of steel with stainless steel cladding exposed 

to treated borated water. The applicant stated that this item is not applicable because the 

plant’s CVCS does not contain pump casings comprised of steel with stainless steel cladding. 

The staff reviewed LRA Sections 2.3.3 and 3.3 and the UFSAR and confirmed that no in-scope 

pump casings of steel with stainless steel cladding exposed to treated borated water are 

present in the auxiliary systems; therefore, it finds the applicant’s claim acceptable.

3.3.2.2.15 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.

3.3.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the GALL Report 

In LRA Tables 3.3.2-1 through 3.3.2-45, 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 3.3.2-1 through 3.3.2-45, via Notes F–J, the applicant indicated which 

combinations of component type, material, environment, and AERM do 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 if the applicant 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 Boiler—Aging Management Evaluation—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 boiler system component groups.

In LRA Tables 3.3.2-1, 3.3.2-17, and 3.3.2-40, the applicant stated that the steel bolting 

exposed to air-outdoor is being managed for loss of preload by the Bolting Integrity Program. 

The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

even though steel bolting exposed to air-outdoor is not specifically addressed in the GALL 

Report, Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that steel material is susceptible to a variety 
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of aging effects and mechanisms, including loss of material due to general, pitting, and crevice 

corrosion. The staff noted that the applicant addressed loss of material in additional items for 

each of these components; therefore, the aging effect of concern is loss of preload, which is 

addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of steel bolting exposed to 

air-outdoor in the auxiliary system, the GALL Report has items for other material bolting 

exposed to air-outdoor managed by the Bolting Integrity Program. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program conducts bolting assembly and maintenance control such as application of 

appropriate gasket alignment, torque, lubricants, and preload. Additionally, the program 

inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of 

preload, will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation.

In LRA Tables 3.3.2-1, 3.3.2-12, and 3.3.2-40, the applicant stated that aluminum valve body, 

flame arrestor, and piping and fittings exposed to air-outdoor (external) are being managed for 

loss of material by the External Surfaces Monitoring Program. The AMR item cites generic 

note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because, 

even though the GALL Report does not have an aging effect or AMP for aluminum exposed to 

air-outdoor (external), the GALL Report does state that aluminum materials exposed to 

condensation are subject to loss of material due to pitting and crevice corrosion. The GALL 

Report also states that exposure to outdoor weather conditions can be considered a 

condensation environment.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff finds that the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable because the program uses periodic visual 

inspections that would detect loss of material in aluminum components.

In LRA Tables 3.3.2-1 and 3.3.2-9, the applicant stated that aluminum valves and galvanized 

steel damper housings exposed to air-outdoor (internal) are being managed for loss of material 

due to general, pitting, and crevice corrosion with 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 confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Table IX.D 

of the GALL Report states that the outdoor air environment includes moist, possibly salt laden, 

air where the component is exposed to local weather conditions, including precipitation and 

wind. Section VII of the GALL Report states that aluminum and steel components exposed to 

condensation or raw water are susceptible to loss of material due to general, pitting, and crevice 

corrosion.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. 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 periodic visual inspections performed during maintenance and surveillance activities,
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which can identify localized discoloration and surface irregularities such as rust, scale, deposits, 

and surface pitting that could result in a loss of the component-intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.2 Boron Recovery System—Aging Management Evaluation—LRA Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the 

boron recovery system component groups.

In LRA Tables 3.3.2-2, 3.3.2-3, 3.3.2-4, 3.3.2-9, 3.3.2-10, 3.3.2-11, 3.3.2-12, 3.3.2-16, 3.3.2-19, 

3.3.2-20, 3.3.2-21, 3.3.2-22, 3.3.2-24, 3.3.2-25, 3.3.2-29, 3.3.2-30, 3.3.2-31, 3.3.2-32, 3.3.2-33, 

3.3.2-35, 3.3.2-37, 3.3.2-39, 3.3.2-42, 3.3.2-44, and 3.3.2-45, the applicant stated that the 

stainless steel bolting exposed to air-indoor is being managed for loss of preload by the Bolting 

Integrity Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel bolting exposed to air-indoor is not specifically addressed in the GALL 

Report, Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to 

a variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion and cracking due to SCC. The staff noted that the environment of interest, air-indoor,

would not induce SCC or loss of material in stainless steel material because stainless steel is 

inherently resistant to corrosion in the air-indoor environment. Therefore, the aging effect of 

concern is loss of preload, which is addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed 

to air-indoor in the auxiliary system, the GALL Report has items for other material bolting 

exposed to air-indoor managed by the Bolting Integrity Program. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program conducts bolting assembly and maintenance control such as application of 

appropriate gasket alignment, torque, lubricants, and preload. Additionally, the program 

inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of 

preload, will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).
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3.3.2.3.3 Chemical and Volume Control System—Aging Management Evaluation—LRA

Table 3.3.2-3

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the 

CVCS component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor, and managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

In LRA Table 3.3.2-3, the applicant stated that the nickel-alloy flexible hoses exposed to treated 

borated water are being managed for loss of material by the Water Chemistry Program. The 

AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

even though nickel alloys exposed to treated borated water are not specifically addressed in the 

GALL Report, Chapter VII of the GALL Report indicates that nickel alloys exposed to aqueous 

environments are susceptible to loss of material.

The staff’s evaluation of the applicant’s Water Chemistry Program is documented in SER 

Section 3.0.3.1.2. The staff noted that the Water Chemistry Program relies upon periodic 

monitoring and control of detrimental contaminants in the water to manage loss of material. The 

staff also notes that the GALL Report’s guidance for loss of material of stainless steel in treated 

borated water is part of the Water Chemistry Program, and this aging effect would be very 

similar to that of nickel alloys in treated borated water. The staff finds the applicant’s proposal 

to manage aging using the Water Chemistry Program acceptable because it employs the use of 

chemistry sampling to ensure that chemical impurities are minimized to reduce aging due to loss 

of material, which is similar to guidance observed in the GALL Report.

In LRA Tables 3.3.2-3, 3.3.2-12, 3.3.2-15, and 3.3.2-23, the applicant stated that elastomer 

flexible hose exposed to fuel oil or lubricating oil (internal) are being managed for hardening and 

loss of strength with 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 confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report, in Table IX.C, states that elastomers are susceptible to hardening and loss of 

strength at temperatures over about 95 °F (35 °C) or when exposed to additional aging factors 

such as ozone, oxidation, and radiation. The staff noted that the environment of interest, 

lubricating oil (internal), has the potential for being in the temperature range for elastomer 

susceptibility to aging; therefore, the aging effect of concern is hardening and loss of strength, 

which is addressed in the AMR.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:

• The program includes periodic visual inspections performed during maintenance and 

surveillance activities, which can identify localized discoloration and surface 

irregularities.
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• The program includes non-visual examinations, such as scratching, which will screen for 

residues and breakdown of the material, and stretching and pressing, which will evaluate 

the material resiliency to determine if hardening and loss of strength are occurring that 

could result in a loss of the component-intended function.

In LRA Tables 3.3.2-3, 3.3.2-5, 3.3.2-6, 3.3.2-7, 3.3.2-8, 3.3.2-11, 3.3.2-16, 3.3.2-18, 3.3.2-20, 

3.3.2-23, 3.3.2-28, 3.3.2-35 and 3.3.2-39, the applicant stated that the elastomer flexible hoses 

and flexible connectors exposed to air with borated water leakage (external) are being managed 

for hardening and loss of strength by the External Surfaces Monitoring Program. The AMR 

items cite generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report, item VII.A3-1, states that elastomers are susceptible to hardening and loss of 

strength, due to elastomer degradation when exposed to treated borated water. The 

environment of interest, air with borated water leakage, contains borated water that would make 

the material susceptible to hardening and loss of strength, which is addressed in the AMR.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff noted that the applicant’s program includes non-visual 

examinations such as scratching to determine if scale or residues are present or determine if 

there is a breakdown of material, bending, or folding of the elastomer to detect cracking that 

initiates at the surface, stretching, and pressing to determine the resistance of the material to 

hardening effects, and pressing to gauge the materials resiliency. The staff finds that the 

applicant’s proposal to manage aging using the External Surfaces Monitoring Program 

acceptable because the program includes periodic visual inspections as well as non-visual 

tactile examinations to detect hardening and loss of strength of the component.

In LRA Tables 3.3.2-3, 3.3.2-29, 3.3.2-37, and 3.3.2-40, the applicant stated that for nickel-alloy

components exposed to air with borated water leakage there is no aging effect and no AMP is 

proposed. The AMR items cite generic note G and plant-specific note 1. Plant-specific note 1 

states the following:

NUREG-1801 does not include air with borated water leakage for nickel-alloy

components. Similar to V.F-13 for stainless steel, there are no aging effects for 

nickel alloy in air with borated water leakage. Additionally, the American Welding 

Society (AWS) “Welding Handbook,” (Seventh Edition, Volume 4, 1982, Library 

of Congress) identifies that nickel chromium alloy materials that are alloyed with 

iron, molybdenum, tungsten, cobalt or copper in various combinations have 

improved corrosion resistance.

The staff reviewed the associated items in the LRA and confirmed that the applicant’s use of 

generic note G for these items is appropriate in that the GALL Report, Revision 1, does not 

include entries for nickel alloys exposed to air with borated water leakage. The staff notes that 

the GALL Report, Revision 2, dated December 31, 2010, does include entries for nickel alloys 

exposed to air with borated water leakage. These entries indicate that no AERM is present for 

this material environment combination. The staff also notes these items in Revision 2 of the 

GALL Report are based in part on EPRI Report 1000975, “Boric Acid Corrosion Guidebook, 

Revision 1.” This report contains data (p. 4–43) showing that “[t]here was no measurable 

corrosion of stainless steel piping surfaces or Inconel weld metal joining the stainless steel and 

carbon steel piping sections.” The staff, therefore, concurs with the applicant’s assessment that 
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aging management is not necessary for nickel-alloy components exposed to air with borated 

water leakage.

In LRA Table 3.3.2-3, 3.3.2-4, 3.3.2-5, 3.3.2-11, 3.3.2-16, 3.3.2-19, 3.3.2-29, 3.3.2-30, 3.3.2-31, 

3.3.2-35, 3.3.2-37, and 3.3.2-39, the applicant stated that, for glass piping elements exposed to 

air-with borated water leakage (external), there is no aging effect and no AMP is proposed. The 

AMR items cites generic note G. The staff reviewed the associated items in the LRA and 

confirmed that no aging effect is applicable for this component, material, and environment 

combination because the GALL Report, item V.F-9, states that, for an environment of treated 

borated water there is no AERM and no recommended AMP. Additionally, the air with borated 

water leakage environment is no more severe than the treated borated water environment.

In response to RAI 3.2.2.2.4.2-1A, by letter dated June 2, 2011, the applicant amended the LRA 

by revising LRA Table 3.3.2-3 to include stainless steel heat exchanger components exposed to 

treated borated water that are being managed for reduction of heat transfer due to fouling by the 

Water Chemistry Program. The AMR items cite generic note H.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report recommends managing reduction of heat transfer for heat exchanger 

components in treated water, and treated borated water is comparable to treated water with 

regard to the potential for reduction of heat transfer due to fouling.

However, the staff finds the applicant’s use of only the Water Chemistry Program to manage 

reduction of heat transfer unacceptable because the guidance in the SRP-LR and GALL Report 

was revised in LR-ISG-2011-01, “Aging Management of Stainless Steel Structures and 

Components in Treated Borated Water,” to add the One-Time Inspection Program to verify the 

effectiveness of the Water Chemistry Program to manage stainless steel components for loss of 

material, cracking, and reduction of heat transfer in treated borated water environments that are 

not controlled to low oxygen levels. The staff noted that, prior to the issuance of 

LR-ISG-2011-01, the SRP-LR and GALL Report guidance inappropriately credited the boron in 

borated water as a corrosion inhibitor in place of other aging management activities.

By letter dated May 29, 2012, the staff issued RAI 3.2.1.48-1 requesting that the applicant 

describe how the effectiveness of the Water Chemistry Program to manage reduction of heat 

transfer will be verified for stainless steel components exposed to treated borated water with 

greater than 5 ppb oxygen. Pending the staff’s review of the applicant’s response, this issue is 

identified as Open Item OI 3.2.2.1-1.

On the basis of its review, pending resolution of Open Item OI 3.2.2.1-1, the staff finds that the 

applicant appropriately evaluated the AMR results of material, environment, AERM, and AMP 

combinations not addressed in the GALL Report. The staff finds that the applicant 

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).

3.3.2.3.4 Chlorination System—Aging Management Evaluation—LRA Table 3.3.2-4

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the 

chlorination system component groups.
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The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

In LRA Table 3.3.2-4, the applicant stated that the stainless steel bolting exposed to 

condensation is being managed for loss of material by the Bolting Integrity Program. The AMR 

item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel bolting exposed to condensation is not specifically addressed in the GALL 

Report, Table IX.C of the GALL Report states that stainless steel material is susceptible to a 

variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion and cracking due to SCC. The staff noted that the environment of interest, 

condensation, would not induce SCC in stainless steel material because stainless steel is 

inherently resistant to SCC in the condensation environment and becomes susceptible to SCC 

only at temperatures above 140 °F (60 °C); therefore, the aging effect of concern is loss of 

material, which is addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of material of stainless steel bolting exposed 

to condensation in the auxiliary system, the GALL Report has items for loss of material of other 

material bolting managed by the Bolting Integrity Program. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program inspects the bolting through periodic visual inspections to verify that the aging 

effect, loss of material, will be adequately managed so that the intended functions will be 

maintained consistent with the CLB for the period of extended operation.

In LRA Tables 3.3.2-4, 3.3.2-9, 3.3.2-11, 3.3.2-20, 3.3.2-26, and 3.3.2-35, the applicant stated 

that for polymer [polyvinyl chloride (PVC), polyvinylidene fluoride (PVDF), polypropylene, 

fluoropolymer, polycarbonate, plastic and polyolefin] piping, piping components, and piping 

elements, flexible hose, tanks, and instrument elements exposed to air-indoor uncontrolled 

(internal or external) and air-indoor controlled external environments, there is no aging effect,

and no AMP is proposed. The AMR items cite generic note F. These items also cite 

plant-specific Notes 1 or 2. Plant-specific note 2 states the following:

Unlike metals, polymers do not display corrosion rates. Rather than depending 

on an oxide layer for protection, they depend on chemical resistance to the 

environment to which they are exposed. The plastic is either completely resistant 

to the environment or it deteriorates. Therefore, acceptability for the use of 

polymers within a given environment is a design driven criterion. Once the 

appropriate material is chosen, the system will have no aging effects. This is 

consistent with plant operating experience.

The staff noted that, as identified in Engineering Materials Handbook—Engineering Plastics, 

ASM International, Copyright 1988, rigid polymers are unaffected by water, concentrated alkalis, 

non-oxidizing acids, oils, ozone, sunlight, or humidity changes. The staff also noted that, unlike 

metals, thermoplastics do not display corrosion rates, and rather than depend on an oxide layer 

for protection, they depend on chemical resistance to the environments to which they are 

exposed and the use of thermoplastics in power plant environments is a design-driven criterion. 

The staff further noted that thermoplastic materials are impervious and, once selected for the 

environment, will not have any significant age-related degradation. The staff reviewed the 
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associated items in the LRA and confirmed that no aging effect is applicable for this component, 

material, and environment combination because there is no indication in the industry that 

polymers or thermoplastics exposed to an internal or external indoor air environment have any 

aging effects requiring management. Additionally, the generally low operating temperatures and 

historically good chemical resistance data for polymer components, combined with a lack of 

historically negative operating experience, indicate that polymers are not likely to experience 

any degradation from the non-aggressive indoor air.

In LRA Tables 3.3.2-4, 3.3.2-15, and 3.3.2-36, the applicant stated that, for fiberglass piping and 

fittings and filter housings exposed to condensation (external) or raw water (internal), there is no 

aging effect, and no AMP is proposed. The AMR items cite generic note F and plant-specific 

Notes 1, 5, or 6, which state that “[f]iberglass components in Condensation environment 

(external) or Raw Water environment (internal) are not exposed to high levels of ultraviolet 

radiation, high temperatures, or ozone, and therefore have no aging effects that require aging 

management. This is consistent with plant operating experience.” The staff reviewed the 

associated items in the LRA and found that fiberglass piping exposed to condensation (external) 

or raw water (internal) is not specifically addressed in the GALL Report; however, the staff noted 

that the environments of interest could cause water infiltration into the fiberglass, which could 

induce blistering and spalling or cracking. By letter dated January 5, 2011, the staff issued 

RAI 3.3.2.3.4-1 requesting that the applicant state why the specific specification and grade of 

fiberglass material used in these components is not susceptible to blistering and spalling or 

cracking when exposed to condensation environment (external) or raw water environment 

(internal) or propose how the aging effects will be managed.

In its response dated February 3, 2011, the applicant stated that portions of the chlorination 

system, and all of the fire protection system’s fiberglass piping, is constructed of an epoxy resin 

type of material. Based on technical input from the manufacturer, there is no industry 

experience of blistering, spalling, or cracking due to water absorption in fiberglass piping 

constructed with the epoxy resin. The applicant also stated that fiberglass reinforced vinyl ester 

pipe is used in the chlorination system in the service water pumphouse and the intake and 

discharge structures to supply chlorinated raw water to the pump forebay and to the seawater

inlet. The maximum design temperature for this piping of 100 °F and the maximum seawater

inlet temperature is 65 °F at Seabrook. The applicant further stated that only hot water in the 

range of 170–180 °F or above can cause blistering, spalling, or cracking in vinyl ester resin 

based fiberglass pipe. The applicant stated that the travelling screen system uses fiberglass 

traveling screen enclosures, which are only exposed to condensation or raw water in the spray 

form.

The staff reviewed The Corrosion Resistant Materials Handbook, by D. J. De Renzo and Ibert 

Mellan, and found that both fiberglass reinforced epoxy pipe and reinforced vinyl ester resin 

pipe are acceptable for use up to 200 °F in brine and 10 percent salt water and chlorinated 

water up 200 ppm chlorine. The staff also noted that reinforced vinyl ester resin pipe is 

acceptable for use in chlorine saturated brine up 150 °F and saturated chlorinated water up to 

200 °F; however, fiberglass reinforced epoxy pipe is not recommended under these conditions.

The staff reviewed the fiberglass items in the LRA associated with the fire protection and screen 

wash system and confirmed that no aging effect is applicable for this component, material, and 

environment combination for the following reasons:

• For the fire protection system, LRA Table 3.3.2-15, the components are constructed of 

an epoxy resin type of material, which does not have aging effects until exposed to 
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temperatures above 170 °F, which is above the fire protection systems design 

temperature.

• For the screen wash system, LRA Table 3.3.2-36, the components are only exposed to 

raw water as a spray or condensation. Neither of these environments have a driving 

force for water penetration and blistering.

Based on a review of the UFSAR, the staff could not determine the chlorine level of the water in 

the chlorination system such that a determination of no aging effects could be warranted. By 

letter dated March 30, 2011, the staff issued a followup to RAI 3.3.2.3.4-1 requesting that the 

applicant state the chlorine concentration for in-scope fiberglass pipe in the chlorination system. 

If it exceeds 200 ppm, the staff asked that the applicant state why there is no aging effect or 

propose an AMP.

In its response dated April 22, 2011, the applicant stated that the components exposed to 

chlorine are constructed of fiberglass reinforced vinyl ester or bisphenol-A polyester. The 

applicant also stated that, based on input from the vendor of the components, given the 

operating parameters of the system—less than 65 °F, pH greater than 10, and no direct UV 

exposure—and plant-specific operating experience to date, there is no potential aging effect.

The staff did not find the applicant’s response acceptable because, based on independent 

research, the staff does not agree with the applicant’s assessment that there is no potential 

aging effect for these components. While the applicant’s response to the RAI, and the staff’s 

independent research, established that the materials are suitable for the design parameters of 

the system, proper design does not establish the basis for a 60-year life with no aging effects 

when the environment is an oxidizer and the material is an organic polymer. Therefore, by letter 

dated May 23, 2011, the staff issued a followup to RAI 3.3.2.3.4-1 requesting that the applicant 

state what inspections have been performed to establish a baseline of operating experience and 

what inspections will be conducted to manage aging of the fiberglass piping and fittings in the 

chlorination system exposed to raw water, including sodium hypochlorite.

In its response dated June 2, 2011, the applicant stated that, during the April 2011 RFO, the 

chlorination system piping was disassembled, and the piping was found to be in excellent 

condition with no signs of age-related degradation. The applicant revised the LRA to include a 

one-time inspection of the chlorination system fiberglass piping to validate that no aging effect is 

occurring. The applicant also revised its UFSAR supplement, LRA Section A.2.1.20, to reflect 

that the One-Time Inspection Program will be used to manage the aging effects of cracking, 

blistering, and change in color (i.e., material properties) for fiberglass piping in the chlorination 

system.

The staff finds the applicant’s response acceptable for the following reasons:

• The applicant identified the correct potential aging effects for this material and 

environment combination.

• The applicant revised the LRA to include a one-time inspection of fiberglass piping in the 

chlorination system to verify that aging does not occur.

• The One-Time Inspection Program includes determination of an appropriate sample 

size, identification of inspection locations, and visual inspections that can detect the 

potential aging effects.

The staff’s concern described in RAI 3.3.2.3.4-1 is resolved.
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On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

In LRA Tables 3.3.2-4, 3.3.2-9, and 3.3.2-37, the applicant stated that for polymer (PVC) piping 

and fittings, and filter housing exposed to condensation (internal or external) environment, there 

is no aging effect, and no AMP is proposed. The AMR items cite generic note F. These items 

also cite plant-specific notes 1 or 2. Plant-specific note 2 states the following:

Unlike metals, polymers do not display corrosion rates. Rather than depending 

on an oxide layer for protection, they depend on chemical resistance to the 

environment to which they are exposed. The plastic is either completely resistant 

to the environment or it deteriorates. Therefore, acceptability for the use of 

polymers within a given environment is a design driven criterion. Once the 

appropriate material is chosen, the system will have no aging effects. This is 

consistent with plant operating experience.

The staff noted that, as identified in Engineering Materials Handbook—Engineering Plastics, 

American Society for Metals International, Copyright 1988, rigid polymers are unaffected by 

water, concentrated alkalis, non-oxidizing acids, oils, ozone, sunlight, or humidity changes. The 

staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather 

than depend on an oxide layer for protection, they depend on chemical resistance to the 

environments to which they are exposed and the use of thermoplastics in power plant 

environments is a design-driven criterion. The staff further noted that thermoplastic material is 

impervious and, once selected for the environment, will not have any significant age-related 

degradation. The staff reviewed the associated items in the LRA and confirmed that no aging 

effect is applicable for this component, material, and environment combination because there is 

no indication in the industry that polymers or thermoplastics exposed to an internal or external 

condensation environment have any aging effects requiring management. Additionally, the 

generally low operating temperatures and historically good chemical resistance data for polymer 

components, combined with a lack of historically negative operating experience, indicate that 

polymers are not likely to experience any degradation from the non-aggressive condensation 

environment.

In LRA Tables 3.3.2-4, 3.3.2-11, 3.3.2-26, and 3.3.2-37, the applicant stated that for polymeric 

piping, piping components, piping elements, and filter housings exposed to raw water 

environment, there is no aging effect, and no AMP is proposed. The AMR items cite generic 

note F. These items also cite plant-specific Notes 1 or 2. Plant-specific note 2 states the 

following:

Unlike metals, polymers do not display corrosion rates. Rather than depending 

on an oxide layer for protection, they depend on chemical resistance to the 

environment to which they are exposed. The plastic is either completely resistant 

to the environment or it deteriorates. Therefore, acceptability for the use of 

polymers within a given environment is a design driven criterion. Once the 

appropriate material is chosen, the system will have no aging effects. This is 

consistent with plant operating experience.
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The staff reviewed the associated items in the LRA. The staff noted that polymer degradation 

occurs when it is exposed to high temperature or continuously exposed to ultraviolet rays and 

some chemicals. LRA Table 3.0-1 defines raw water and states that it may contain 

contaminants including oil and boric acid, depending on the location, as well as originally treated 

water that is not monitored by a chemistry program. The staff also noted that it is, therefore, 

possible that these polymeric components could be exposed to an environment of raw water 

that includes oil, microorganisms, or other chemicals and, therefore, could potentially have an 

aging effect of cracking or blistering. By letter dated January 5, 2011, the staff issued 

RAI 3.3.2.3.4-1 requesting that the applicant state why polymeric components in LRA

Tables 3.3.2-4 and 3.3.2-26, exposed to a raw water environment as defined in LRA

Table 3.0-1, will not exhibit any aging effects that require management.

In its response dated February 3, 2011, the applicant stated that the instrument element in LRA

Table 3.3.2-4 is manufactured from PVDF, which is a specialty plastic material in the 

fluoropolymer family and is used generally in applications requiring the highest purity, strength,

and resistance to solvents, acids, bases, and heat. The applicant also stated that the material is 

rugged and unusually resistant to many chemical solvents, bases, and acids. The applicant 

further stated that the instrument element is correctly identified as no aging management 

required.

The staff reviewed the applicant’s response and confirmed that no aging effect is applicable for 

this component, material, and environment combination because the EPRI Non-Class 1 

Mechanical Implementation Guideline and Mechanical Tools Technical Report, Revision 4, 

states that PVDF is highly corrosion resistant and shows no effect in acids or alkalies. It also 

shows that PVDF is resistant to strong acids and organic solvents and has a continuous heat 

resistance of 300 °F.

For the filter housing, the applicant responded that it had inadvertently listed the material as 

polymer (PVC), and this strainer had been replaced with a Hastealloy strainer, which is a 

nickel-alloy material. The staff’s evaluation of nickel alloy in an internal environment of raw 

water is documented in SER Section 3.3.2.1.16. The staff’s evaluation of nickel alloy in an 

external environment of condensation is documented in SER Section 3.3.2.3.15.

The applicant further stated that, in Table 3.3.2-4, piping and fittings were inadvertently shown 

as polymer (PVC). The applicant stated that although there is polymer (PVC) piping in the 

chlorination system, none of it is within the scope of license renewal. Therefore, in

Table 3.3.2-4, on page 3.3-190, the applicant deleted these items. The staff finds the 

applicant’s deletion of these AMR lines from LRA Table 3.3.2-4 acceptable because the 

components are not within the scope of license renewal.

The applicant stated that in LRA Table 3.3.2-26, the applicable PVC piping and valves are 

associated with the sump pumps in the intake and discharge transition structures. The 

applicant also stated that these sump pumps collect seawater leakage from circulating water 

and service water system piping and components in those buildings as well as groundwater 

in-leakage and condensation in the building, and there are no contaminants, including oil and 

boric acid, normally found in sumps that would result in an aging effect requiring management. 

The staff reviewed the applicant’s response and confirmed that no aging effect is applicable for 

this component, material, and environment combination because the EPRI Non-Class 1 

Mechanical Implementation Guideline and Mechanical Tools Technical Report, Revision 4, 

states that polymers such as PVC are resistant to seawater environments up to temperatures of 

150 °F. The staff noted that UFSAR Table 9.2-2 states that the design temperature of 
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components in the service water systems is 200 °F; however, given that these components are 

associated with sump pumps, it is not expected that normal operating temperature of the 

in-scope piping would exceed 150 °F.

Based on its review, as described above, the staff’s concern described in RAI 3.3.2.3.4-1 is 

resolved.

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for these component, material, and environment combinations because polymers 

such as PVDF, PVC, and polypropylene are highly resistant to solvents, acids, and bases, 

which is consistent with industry operating experience.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external) with no AERM and no recommended AMP, citing generic note G, is documented in 

Section 3.3.2.3.3.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

result of material, environment, and AMP combinations not addressed in the GALL Report. The 

staff finds that the applicant 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.5 Containment Air Handling System—Aging Management Evaluation—LRA

Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the 

containment air handling system component groups.

In LRA Tables 3.3.2-5 and 3.3.2-7, the applicant stated that copper-alloy heat exchanger 

components (cooling coil and cooling coil fins) exposed to condensation (external) are being 

managed for reduction in heat transfer by the External Surfaces Monitoring Program. The AMR 

items cite generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, item VII.F1-16, states that copper-alloy components exposed to condensation are 

susceptible to loss of material, which is addressed in other AMR items. Additionally, the 

function of the components of interest is to provide heat transfer; therefore, any accumulation of 

dirt, debris, or scale would prevent the component from performing its intended function, which 

is addressed in these AMR items.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff noted that the External Surfaces Monitoring Program 

includes visual inspections of the external surfaces of components subject to an AMR to identify 

the aging effect of reduction of heat transfer. The staff finds that the applicant’s proposal to 

manage aging using the External Surfaces Monitoring Program is acceptable because the 

program uses periodic visual inspections that would identify corrosion discoloration and 

accumulation of dirt, scale, or debris indicative of fouling and, thus, detect a reduction in heat 

transfer.

In LRA Tables 3.3.2-5, 3.3.2-6, 3.3.2-7, 3.3.2-8, 3.3.2-18, and 3.3.2-28, the applicant stated that 

the elastomer flexible connectors exposed to air with borated water leakage (external) are being 
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managed for loss of material by the External Surfaces Monitoring Program. The AMR items cite 

generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report, item VII.A3-1, indicates that elastomers are susceptible to hardening and loss 

of strength due to elastomer degradation when exposed to treated borated water, which is 

addressed in other AMR items. The applicant also identified that the material is subject to loss 

of material when exposed to the environment of interest, air with borated water leakage, which 

is addressed the AMR items.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff noted that the applicant’s program includes non-visual 

examinations, such as scratching, to determine if scale or residues are present. These 

examinations also determine if there is a breakdown of material, bending, or folding of the 

elastomer to detect cracking that initiates at the surface, stretching, and pressing to determine 

the resistance of the material to hardening effects, and pressing to gauge the materials 

resiliency to maintain its strength. The staff finds that the applicant’s proposal to manage aging 

using the External Surfaces Monitoring Program acceptable because the program includes 

periodic visual inspections as well as non-visual tactile examinations to detect loss of material 

from the component.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.6 Containment Air Purge System—Aging Management Evaluation—LRA

Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the 

containment air purge system component groups.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for elastomer flexible connectors exposed to air with borated water 

leakage (external), which are being managed for loss of material by the External Surfaces 

Monitoring Program citing generic note G, is documented in SER Section 3.3.2.3.5.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging will be 
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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).

3.3.2.3.7 Containment Enclosure Air Handling System—Aging Management Evaluation—LRA

Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the 

containment enclosure air handling system component groups.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for copper-alloy heat exchanger components exposed to condensation 

(external), which are being managed for reduction in heat transfer due to fouling by the External 

Surfaces Monitoring Program citing generic note G, is documented in Section 3.3.2.3.5.

The staff’s evaluation for elastomer flexible connectors exposed to air with borated water 

leakage (external), which are being managed for loss of material by the External Surfaces 

Monitoring Program citing generic note G, is documented in SER Section 3.3.2.3.5.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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 Containment Online Purge System—Aging Management Evaluation—LRA

Table 3.3.2-8

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the 

containment online purge system component groups.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for elastomer flexible connectors exposed to air with borated water 

leakage (external), which are being managed for loss of material by the External Surfaces 

Monitoring Program citing generic note G, is documented in SER Section 3.3.2.3.5.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).
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3.3.2.3.9 Control Building Air Handling System—Aging Management Evaluation—LRA

Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the 

control building air handling systems component groups.

The staff’s evaluation for galvanized steel damper housing exposed to air-outdoor (internal),

which are being managed for loss of material by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program and cite generic note G, is 

documented in SER Section 3.3.2.3.1.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, which are being managed 

for loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for glass piping elements, exposed to air-with borated water leakage 

(external) with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

The staff’s evaluation for polymer (PVC) piping and fittings and filter housing exposed to 

condensation (internal or external) environment, with no aging effect and no AMP proposed 

citing generic note F, is documented in SER Section 3.3.2.3.4.

The staff’s evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, 

plastic and polyolefin) piping, piping components, and piping elements, flexible hose, tanks, and 

instrument elements exposed to air-indoor uncontrolled (internal or external) and air-indoor 

controlled external environments, with no aging effect and no AMP proposed citing generic 

note F, is documented in SER Section 3.3.2.3.4.

In LRA Table 3.3.2-9, the applicant stated that elastomer flexible connectors exposed to 

air-indoor controlled (internal) are being managed for hardening and loss of strength and loss of 

material with 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 confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, Table IX.C, states that elastomers are susceptible to hardening and loss of strength at 

temperatures over about 95 °F (35 °C) and when exposed to additional aging factors such as 

ozone, oxidation, and radiation. The staff noted that the environment of interest, air-indoor 

controlled (internal), has the potential of being in the temperature range for elastomer 

susceptibility to aging. Additionally, the GALL Report, item VII.F1-6, indicates that elastomer 

seals and components are susceptible to loss of material or wear when exposed to an air-indoor 

uncontrolled (internal) environment. Therefore, the staff noted that the aging effects of concern 

are hardening, loss of strength, and loss of material, which are addressed in the AMR.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:

• The program includes periodic visual inspections performed during maintenance and 

surveillance activities which can identify localized discoloration and surface irregularities.
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• The program includes non-visual examinations such as scratching, which will screen for 

residues and breakdown of the material, and stretching and pressing, which will evaluate 

the material resiliency to determine if hardening and loss of strength or loss of material is 

occurring that could result in a loss of the component-intended function.

In LRA Table 3.3.2-9, the applicant stated that stainless steel instrumentation elements, piping 

and fittings, and valve bodies internally exposed to air-outdoor are being managed for loss of 

material due to pitting and crevice corrosion with 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 noted that, even though stainless steel 

instrumentation elements, piping and fittings, and valve bodies exposed to air-outdoor are not 

specifically addressed in the GALL Report, Table IX.C of the GALL Report states that stainless 

steel material is susceptible to a variety of aging effects and mechanisms, including loss of 

material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that 

given the plant’s proximity to the ocean, stainless steel instrumentation elements, piping and 

fittings, and valve bodies internally exposed to the air-outdoor environment would be susceptible 

to cracking due to SCC. However, the staff noted that the applicant did not identify cracking due 

to SCC as an AERM for these components. By letter dated February 24, 2011, the staff issued 

RAI 3.3-1 requesting that the applicant justify its management of this material, environment, 

AERM, and AMP combination.

In its response dated March 22, 2011, the applicant stated that SCC has been added as an 

aging mechanism for stainless steel components exposed to an air-outdoor environment. The 

applicant added new AMR items to manage cracking using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program. The staff finds the applicant’s 

response acceptable because the applicant modified the LRA to include cracking due to SCC as 

an applicable aging effect for stainless steel components exposed to outdoor air and will use 

either magnified visual inspections or ultrasonic inspections, which are capable of detecting 

cracking. The staff’s concern described in RAI 3.3-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicants proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:

• The program includes periodic visual inspections performed during maintenance and 

surveillance activities, which can identify localized discoloration and surface irregularities 

such as rust, scale or deposits, and surface pitting.

• The program includes either magnified visual inspection or ultrasonic inspection to 

determine if material degradation is occurring that could result in a loss of the 

component-intended function.

In LRA Table 3.3.2-9, the applicant stated that for copper-alloy piping, fittings, and valves 

exposed to air-indoor controlled (external), there is no aging effect, and no AMP is proposed. 

The AMR items cite generic note G and plant-specific Notes 11 and 12. Notes 11 and 12 state 

that NUREG-1801 does not include air-indoor controlled for copper alloy and copper alloy 

greater than 15 percent zinc components. Similar to V.F-3 for copper alloy and copper alloy 

greater than 15 percent zinc in air-indoor uncontrolled, there are no aging effects for copper 

alloy and copper alloy greater than 15 percent zinc in air-indoor controlled. The staff reviewed 

the associated items in the LRA and confirmed that no aging effect is applicable for this 
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component, material, and environment combination. GALL item V.F.3 for copper alloy exposed 

to uncontrolled indoor air bounds the consideration for these components in controlled indoor 

air, and item V.F.3 states there are no aging effects for copper-alloy components in uncontrolled 

indoor air.

In LRA Table 3.3.2-9, the applicant stated that for stainless steel valve bodies, thermowells, 

piping and fittings, and instrumentation elements exposed to air-indoor controlled (external),

there is no aging effect, and no AMP is proposed. The AMR items cite generic note G and 

plant-specific note 10, which states that NUREG-1801 does not include air-indoor controlled for 

stainless steel components. However, similar to VII.J-15 for stainless steel in air-indoor 

uncontrolled, there are no aging effects for stainless steel in air-indoor controlled.

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment combination because controlled indoor 

air contains less moisture than uncontrolled indoor air; therefore, uncontrolled indoor air can be 

considered a bounding environment for components exposed to controlled indoor air. The 

GALL Report states that stainless steel components exposed to uncontrolled indoor air do not 

have any aging effects, and no AMP is recommended.

In LRA Tables 3.3.2-9, 3.3.2-12, 3.3.2-29, and 3.3.2-30 the applicant stated that for glass piping 

elements exposed to closed-cycle cooling water (internal) or gas (internal), there is no aging 

effect, and no AMP is proposed. The AMR items cite generic note G. The staff reviewed the 

associated items in the LRA and confirmed that no aging effect is applicable for this component, 

material, and environment combination because the GALL Report has multiple AMR Items that

state that for an environment of indoor uncontrolled air, raw water, or treated water, there is no 

AERM and no recommended AMP, and the closed-cycle cooling water (internal) or gas 

(internal) environment is no more severe than the raw water or indoor uncontrolled air 

environment already addressed in the GALL Report.

In LRA Tables 3.3.2-9, 3.3.2-17, and 3.3.2-40, the applicant stated that the stainless steel filter 

element, piping and fittings, valve body, expansion joint, and filter housing exposed to 

air-outdoor (external) are being managed for loss of material by the External Surfaces 

Monitoring Program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel exposed to air-outdoor (external) is not specifically addressed in the 

GALL Report, Table IX.C of the GALL Report states that stainless steels are susceptible to loss 

of material due to pitting and crevice corrosion and cracking due to SCC. The staff noted that 

the environment of interest, air-outdoor (external) would be expected to contain higher levels of 

chlorides due to the site’s relative proximity to the ocean, which are known to induce SCC. By 

letter dated February 24, 2011, the staff issued RAI 3.3-1 requesting that the applicant provide 

additional information on why atmospheric chloride-induced SCC is not considered to be an 

applicable aging effect for stainless steel components exposed to outdoor-air and explain how 

SCC will be managed if it is determined to be an applicable aging affect.

In its response dated March 22, 2011, the applicant stated that SCC has been added as an 

aging mechanism for stainless steel components exposed to air-outdoor environment. The 

applicant added a new item to manage cracking by either the External Surfaces Monitoring 

Program or the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. The staff finds the applicant’s response acceptable because the 

applicant has modified the LRA to do the following:
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• include SCC as an applicable aging effect for stainless steel components exposed to 

outdoor-air containing high levels of chloride

• include either magnified visual inspection or ultrasonic inspection in the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program

• include SCC as an aging effect to be managed by the External Surfaces Monitoring 

Program, which includes visual inspections that is a capable technique to detect SCC 

The staff’s concern described in RAI 3.3-1 is resolved.

The staff’s evaluations of the applicant’s External Surfaces Monitoring Program and Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program are 

documented in SER Sections 3.0.3.2.14 and 3.0.3.2.15, respectively. The staff finds that the 

applicant’s proposal to manage aging using the External Surfaces Monitoring Program and 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable because the programs use periodic or opportunistic visual inspections that would 

detect loss of material and SCC prior to loss of component-intended function.

In LRA Table 3.3.2-9, the applicant stated that the elastomer flexible connectors exposed to 

air-indoor controlled (external) are being managed for hardening and loss of strength and loss of 

material by the External Surfaces Monitoring Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, item VII.F1-7, states that elastomers exposed to indoor air are susceptible to hardening 

and loss of strength due to elastomer degradation, and GALL item VII.F1-5 states that 

elastomers exposed to indoor air are susceptible to loss of material due to wear, both of which 

are addressed in the AMR items.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff noted that the applicant’s program includes non-visual 

examinations, such as scratching, to determine if scale or residues are present or determine if 

there is a breakdown of material, bending, or folding of the elastomer to detect cracking that 

initiates at the surface. The program also includes stretching and pressing to determine the 

resistance of the material to hardening effects and pressing to gauge the materials resiliency to 

maintain its strength. The staff finds that the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable because the program uses periodic visual 

inspections as well as non-visual tactile examinations, which are capable of detecting loss of 

material and hardness and loss of strength.

In LRA Table 3.3.2-9, the applicant stated that aluminum heat exchanger components exposed 

to condensation (external) are being managed for reduction in heat transfer by the External 

Surfaces Monitoring Program. The AMR item cites generic note F.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effect for this component, material, and environment combination. The GALL 

Report, item VII.F1-14, states that aluminum components exposed to condensation are 

susceptible to loss of material, which is addressed in another AMR item. Additionally, the 

components of interest function in a capacity to provide heat transfer and therefore any 

accumulation of dirt, debris, or scale could prevent the component from performing its intended 

function, which is addressed in this AMR item.
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In LRA Tables 3.3.2-9 and 3.3.2-12, the applicant stated that aluminum heat exchanger 

components exposed to air-indoor uncontrolled (external) are being managed for reduction in 

heat transfer by the External Surfaces Monitoring Program. The AMR item cites generic note F.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination for the 

following reasons:

• The GALL Report, item V.F-2, states that aluminum components exposed to air have no 

aging effects requiring management.

• The components of interest function in a capacity to provide heat transfer; therefore, 

any accumulation of dirt, debris, or scale could prevent the component from performing 

its intended function, which is addressed in this AMR item.

The staff’s evaluation of the applicant’s Inspection of External Surfaces Monitoring Program is 

documented in SER Section 3.0.3.2.14. The staff finds that the applicant’s proposal to manage 

aging using the External Surfaces Monitoring Program acceptable because the program uses 

periodic visual inspections that would identify corrosion discoloration and accumulation of dirt, 

scale, or debris indicative of fouling and, thus, detect any reduction in heat transfer prior to loss 

of the component’s intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.10 Demineralized Water System—Aging Management Evaluation—LRA Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for 

the demineralized water system component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.11 Dewatering System—Aging Management Evaluation—LRA Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for 

the dewatering system component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.
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The staff’s evaluation for glass piping elements, exposed to air-with borated water leakage 

(external) with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

The staff’s evaluation for polymer piping, piping components, piping elements, and filter housing 

exposed to raw water environment, with no aging effect and no AMP proposed citing generic 

note F, is documented in SER Section 3.3.2.3.4.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, 

plastic and polyolefin) piping, piping components, piping elements, flexible hose, tanks, and 

instrument elements exposed to air-indoor uncontrolled (internal or external) and air-indoor 

controlled external environments, with no aging effect and no AMP proposed citing generic 

note F, is documented in SER Section 3.3.2.3.4.

In LRA Tables 3.3.2-11, 3.3.2-20, and 3.3.2-35, the applicant stated that for polymer (PVC, 

polypropylene, fluoropolymer, polycarbonate, polyolefin, and plastic ) piping, piping components 

and piping elements, tank, and flexible hose exposed to air with borated water external 

environment, there is no aging effect, and no AMP is proposed. The AMR items cite generic 

note F. These items also cite plant-specific notes 1 or 2. Plant-specific note 2 states the 

following:

Unlike metals, polymers do not display corrosion rates. Rather than depending 

on an oxide layer for protection, they depend on chemical resistance to the 

environment to which they are exposed. The plastic is either completely resistant 

to the environment or it deteriorates. Therefore, acceptability for the use of 

polymers within a given environment is a design driven criterion. Once the 

appropriate material is chosen, the system will have no aging effects. This is 

consistent with plant operating experience.

The staff noted that, as identified in Engineering Materials Handbook—Engineering Plastics, 

American Society for Metals International, Copyright 1988, rigid polymers are unaffected by 

water, concentrated alkalis, non-oxidizing acids, oils, ozone, sunlight, or humidity changes. The 

staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather 

than depend on an oxide layer for protection, they depend on chemical resistance to the 

environments to which they are exposed, and the use of thermoplastics in power plant 

environments is a design-driven criterion. The staff further noted that thermoplastic materials 

are impervious and, once selected for the environment, will not have any significant age-related 

degradation. The staff reviewed the associated items in the LRA and confirmed that no aging 

effect is applicable for this component, material, and environment combination because there is 

no indication in the industry that polymers or thermoplastics exposed to an internal or external 

indoor air environment have any aging effects requiring management. Additionally, the 

generally low operating temperatures and historically good chemical resistance data for polymer 

components, combined with a lack of historically negative operating experience, indicate that 

polymers are not likely to experience any degradation from the non-aggressive air with borated 

water environment.
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On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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 Diesel Generator—Aging Management Evaluation—LRA Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for 

the diesel generator system component groups.

The staff’s evaluation for aluminum flame arrestor and piping and fittings exposed to air-outdoor 

(external), which are being managed for loss of material by the External Surfaces Monitoring 

Program citing generic note G, is documented in SER Section 3.3.2.3.1.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, which is being managed 

for loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for elastomer flexible hoses exposed to fuel oil or lubricating oil (internal),

which are being managed for 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 SER Section 3.3.2.3.3.

The staff’s evaluation for glass piping elements exposed to closed-cycle cooling water (internal) 

or gas (internal), which cite generic note G, is documented in SER Section 3.3.2.3.9.

The staff’s evaluation for aluminum heat exchanger components exposed to air-indoor 

uncontrolled (external), which are being managed for reduction in heat transfer by the External 

Surfaces Monitoring Program and cite generic note F, is documented in SER Section 3.3.2.3.9.

In LRA Table 3.3.2-12, the applicant stated that the aluminum heat exchanger components 

(DG-MM-888A and DG-MM-888 after cooler tubes) exposed to condensation (internal) are 

being managed for reduction of heat transfer by the Compressed Air Monitoring Program. The 

AMR item cites generic note F.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

even though the GALL Report does not have aluminum heat exchangers exposed to 

condensation, heat exchangers are known to be susceptible to reduction of heat transfer aging 

issues.

The staff’s evaluation of the applicant’s Compressed Air Monitoring Program is documented in 

SER Section 3.0.3.2.6. The staff finds the applicant’s proposal to manage aging using the 

Compressed Air Monitoring Program acceptable because the Compressed Air Monitoring 

Program includes visual inspection techniques that are capable of detecting reduction of heat 

transfer and annual testing to verify that the performance of the system is in accordance with its 

intended functions.

In LRA Tables 3.3.2-12 and 3.3.2-15, the applicant stated that elastomer flexible hoses exposed 

to closed-cycle cooling water (internal) are being managed for hardening and loss of strength 
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with 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 confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, Table IX.C, states that elastomers are susceptible to hardening and loss of strength at 

temperatures over about 95 °F (35 °C) and when exposed to additional aging factors such as 

ozone, oxidation, and radiation. The staff noted that the environment of interest, closed-cycle

cooling water (internal), has the potential of being in the temperature range for elastomer 

susceptibility to aging; therefore, the aging effect of concern is hardening and loss of strength, 

which is addressed in the AMR.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:

• The program includes periodic visual inspections performed during maintenance and 

surveillance activities that can identify localized discoloration and surface irregularities.

• The program includes non-visual examinations, such as scratching, which will screen for 

residues and breakdown of the material, and stretching and pressing which will evaluate 

the material resiliency to determine if hardening and loss of strength is occurring that 

could result in a loss of the component-intended function.

In LRA Table 3.3.2-12, the applicant stated that the elastomer flexible hose exposed to 

condensation (internal) is being managed for hardening and loss of strength by the Compressed 

Air Monitoring Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though elastomer materials exposed to condensation are not in the GALL Report for hardening 

and loss of strength, GALL Report, Tables IX.C and IX.E, indicate that elastomers are 

susceptible to hardening and loss of strength. It was unclear to the staff how the applicant will 

appropriately manage the hardening and loss of strength of the elastomer components because 

the indications of aging are substantially different from those of steel or stainless steel, which 

the GALL Report references. By letter dated January 5, 2011, the staff issued RAI 3.3.2.12-1 

requesting that the applicant provide details on the additional inspection methods to be used to 

ensure that the AMP will adequately address potential aging effects of the elastomer materials.

In its response dated February 3, 2011, the applicant stated that the diesel generator air 

compressors are replaced every 10 years. The applicant stated that during this routine 

maintenance, the flexible hoses on these compressors will also be replaced. The applicant 

stated that because the flexible hoses are periodically replaced, they are not subject to an AMR. 

The applicant also committed under the Compressed Air Monitoring Program to replace the 

flexible hoses every 10 years and within 10 years of the period of extended operation. This 

response is acceptable because the applicant committed to replace the flexible hoses under the 

Compressed Air Monitoring Program, making them subject to replacement, which does not 

need to be included in the license renewal process under 10 CFR Part 54.21(a)(1)(ii). The 

staff’s concern described in RAI 3.3.2.12-1 is resolved.
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In LRA Table 3.3.2-12, the applicant stated that for aluminum filter housings and valve bodies 

exposed to dried air (internal), there is no aging effect, and no AMP is proposed. The AMR 

items cite generic note G. Items associated with aluminum piping, fittings, and valves in

Tables 3.3.2-12 and 3.3.2-20 cite plant-specific notes, which state aluminum exposed to dried 

air environment does not have any applicable aging effect and provide an industry reference as 

a technical basis.

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment combination because, even though 

aluminum exposed to dried air is not specifically addressed in the GALL Report, the GALL 

Report, item V.F.2, states that aluminum piping, components, and elements exposed to 

uncontrolled indoor air have no aging effects or aging mechanisms. The staff considers dried 

air to be less aggressive than uncontrolled indoor air since moisture would not be available to 

cause loss of material due to pitting.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.13 Diesel Generator Air Handling System—Aging Management Evaluation—LRA

Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for 

the diesel generator air handling system component groups.

The staff’s review did not find any items indicating plant-specific Notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.3.2.1.

3.3.2.3.14 Emergency Feed Water Pump House Air Handling System—Aging Management 

Evaluation—LRA Table 3.3.2-14

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for 

the emergency feed water pump house air handling system component groups.

The staff’s review did not find any items indicating plant-specific Notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.3.2.1.

3.3.2.3.15 Fire Protection System—Aging Management Evaluation—LRA Table 3.3.2-15

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for 

the fire protection system component groups.
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The staff’s evaluation for elastomer flexible hose exposed to fuel oil or lubricating oil (internal),

which are being managed for 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 SER Section 3.3.2.3.3.

The staff’s evaluation for elastomer flexible hose exposed to closed-cycle cooling water 

(internal), which are being managed for 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 SER Section 3.3.2.3.12

The staff’s evaluation for fiberglass piping and fittings exposed to raw water (internal) with no 

AERM and no recommended AMP, citing generic note F, is documented in Section 3.3.2.3.4.

In LRA Table 3.3.2-15, the applicant stated that the stainless steel heat exchanger components 

exposed to steam are being managed for reduction of heat transfer by the Water Chemistry 

Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel exposed to steam, by this specific aging effect, is not specifically 

addressed in the GALL Report, Chapter V of the GALL Report states that stainless steel heat 

exchangers are susceptible to reduction of heat transfer in other aqueous environments. In 

addition, the GALL Report also states that stainless steel exposed to steam can undergo loss of 

material or cracking, which the applicant has included in other AMR items. However, it was not 

clear to staff how the Water Chemistry Program alone would ensure that reduction of heat 

transfer is appropriately managed. Typically, for reduction of heat transfer, a Water Chemistry 

Program along with an Inspection Program is used to manage this aging effect. By letter dated 

January 5, 2011, the staff issued RAI 3.3.2.15-1, requesting that the applicant justify how the 

Water Chemistry Program alone is sufficient to determine that steam generator tubes are not 

affected by reduction of heat transfer when exposed to reactor coolant.

In its response dated August 11, 2011, the applicant stated that the steam environment listed in 

LRA Table 3.3.2-15, for FP-E-46 and FP-E-47, is developed from potable water. The applicant 

stated that because the steam environment listed is potable water converted to steam, it is not 

subject to the Water Chemistry Program. The applicant further stated that the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program is more 

appropriate and will be used to manage the heat exchanger reduction of heat transfer. The 

applicant also stated that it has preventive maintenance activities already in place to clean and 

inspect the external surfaces of the heat exchanger tubes for FP-E-46 and FP-E-47 on a 

frequency of approximately every 4 years, and these two items changed from a generic Notes C 

to G. The staff finds the applicant’s response acceptable because the applicant modified the 

LRA to use inspection programs to identify aging in the heat exchanger tubes, which is 

consistent with the guidance in the GALL Report. The staff’s concern described in 

RAI 3.3.2.15-1 is resolved.

In LRA Table 3.3.2-15, the applicant stated that steel and stainless steel bolting exposed to soil 

is being managed for loss of preload and loss of material by the Bolting Integrity Program. The 

AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though steel and stainless steel bolting exposed to soil are not specifically addressed in the 
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GALL Report, Table IX.E of the GALL Report states that loss of preload can occur independent 

of environmental conditions because it can be caused by thermal or mechanical effects. 

Similarly, a soil environment as indicated in the GALL Report is known to cause loss of material.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload or loss of material of steel and 

stainless steel bolting exposed to soil in the auxiliary systems, the GALL Report has items for 

loss of preload and loss of material of bolting managed by the Bolting Integrity Program. The 

staff finds the applicant’s proposal to manage aging using the Bolting Integrity Program 

acceptable because Bolting Integrity Program inspects the bolting to verify that the aging effect, 

loss of preload, will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation. Additionally, the Bolting Integrity 

Program is supplemented by the Buried Piping and Tanks Inspection Program, which will 

visually inspect for leakage when bolted joints are excavated.

In LRA Table 3.3.2-15, the applicant stated that the steel and stainless steel bolting exposed to 

soil is being managed for loss of material by the Buried Piping and Tanks Inspection Program. 

The AMR item cites generic note G.

The staff noted that LRA Table 3.3.2-15 contains an item for the same component with an aging 

effect of loss of preload. The staff also noted that the “parameters monitored/inspected” 

program element of GALL Report AMP XI.M18, “Bolting Integrity,” states that, “[s]pecifically, 

bolting for safety-related pressure-retaining components is inspected for leakage, loss of 

material, cracking, and loss of preload/loss of prestress. Bolting for other pressure-retaining

components is inspected for signs of leakage.” The staff reviewed the associated items in the 

LRA and confirmed that the applicant identified the correct aging effects for this component, 

material, and environment combination because, in addition to managing loss of material, the 

applicant is managing the only other aging effect by using the Bolting Integrity Program to 

manage loss of preload. The staff noted that GALL Report AMP XI.M.18 does not recommend 

managing cracking for nonsafety-related bolting.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. The staff finds that the applicant’s proposal to manage 

aging using the Buried Piping and Tanks Inspection Program is acceptable for the following 

reasons:

• The program includes preventive actions, such as external coatings and wrappings 

installed to industry standard practices and backfill that will not damage the bolting or 

coatings. Some systems are protected by a cathodic protection system.

• Periodic visual inspections will be performed starting 10 years prior to the period of 

extended operation and extend into both 10-year periods during the period of extended 

operation to ensure that coatings remain intact or uncoated bolting has not degraded.

• Plant-specific operating experience will be used to inform inspection locations.

• Alternatives to direct visual inspection, such as pressure tests, are capable of detecting 

degradation of the bolted connection.

In LRA Table 3.3.2-15, the applicant stated that fiberglass piping exposed to soil is being 

managed for cracking, blistering and change in material properties by the Buried Piping and 

Tanks Inspection Program. The AMR item cites generic note G.
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The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Polymeric 

materials share many of the same aging effects as elastomers, and the applicant’s proposed 

aging effects are the same as those applicable aging effects listed in GALL Report Table IX.F 

for elastomeric materials. The staff noted the additional aging effects listed in Table IX.F as 

follows:

• Aging effects of fatigue breakdown would evidence themselves in a similar manner to 

that of cracking.

• Abrasion from localized poor quality backfill would evidence itself as loss of material.

• If the soil contains chemicals that affect the polymeric material, the aging effect would be 

evidenced by loss of material.

• Weathering is not applicable in the soil environment.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. The staff finds that the applicant’s proposal to manage 

aging using the Buried Piping and Tanks Inspection Program is acceptable for the following 

reasons:

• The program includes the preventive action of ensuring that the quality of backfill will not 

damage the piping.

• Periodic visual inspections, including mechanical examination for evidence of changes in 

material properties, will be performed starting 10 years prior to the period of extended 

operation and extend into both 10-year periods during the period of extended operation 

to ensure that the piping has not degraded.

• Plant-specific operating experience will be used to inform inspection locations.

• Alternatives to direct visual inspection such as pressure tests are capable of detecting 

degradation of the piping.

In LRA Tables 3.3.2-15, 3.3.2-17, 3.3.2-36, 3.3.2-37, and 3.3.2-40, the applicant stated that 

copper alloy and copper alloy with greater than 15 percent zinc valve body, instrumentation 

element, nozzle, filter housing, and piping and fittings exposed to air-outdoor (external) and 

nickel-alloy rupture disc, expansion joint, instrumentation element, orifice, and thermowell 

exposed to air-outdoor (external) or condensation (external) are being managed for loss of 

material by the External Surfaces Monitoring Program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, item VII.G-9, states that copper alloys, including copper alloys with greater than 

15 percent zinc, exposed to condensation such as what could occur in an outdoor air 

environment, are susceptible to loss of material, which is addressed in this AMR item. While 

nickel-alloy components exposed to condensation (external) are not specifically addressed in 

the GALL Report for item VII.C1-13, it states that nickel alloys exposed to raw water are 

susceptible to loss of material, which is addressed in the AMR item.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff finds that the applicant’s proposal to manage aging using the 
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External Surfaces Monitoring Program acceptable because the program uses periodic visual 

inspections that would detect loss of material prior to loss of component-intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.16 Fuel Handling System Aging Management Evaluation—LRA Table 3.3.2-16

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for 

the fuel handling system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, which is being managed 

for loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

In LRA Tables 3.3.2-16 and 3.3.2-35, the applicant stated that elastomer flexible hoses exposed 

to treated water (internal) are being managed for hardening and loss of strength with 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 confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report, Table IX.C, states that elastomers are susceptible to hardening and loss of 

strength at temperatures over about 95 °F (35 °C) and when exposed to additional aging factors 

such as ozone, oxidation, and radiation. The staff noted that the environment of interest, 

treated water (internal) has the potential of being in the temperature range for elastomer 

susceptibility to aging; therefore, the aging effect of concern is hardening and loss of strength, 

which is addressed in the AMR.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:

• The program include periodic visual inspections performed during maintenance and 

surveillance activities, which can identify localized discoloration and surface 

irregularities.
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• Non-visual examinations, such as scratching, which will screen for residues and 

breakdown of the material, and stretching and pressing, which will evaluate the material 

resiliency to determine if hardening and loss of strength are occurring that could result in 

a loss of the component-intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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 Fuel Oil System—Aging Management Evaluation—LRA Table 3.3.2-17

The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for 

the fuel oil system component groups.

The staff’s evaluation for steel bolting exposed to air-outdoor, which is being managed for loss 

of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.1.

The staff’s evaluation for stainless steel piping and fittings, valve body, expansion joint, filter 

housing and tanks exposed to air-outdoor (external), which are being managed for loss of 

material by the External Surfaces Monitoring Program citing generic note G, is documented in 

SER Section 3.3.2.3.9.

The staff’s evaluation for copper alloy and copper alloy with greater than 15 percent zinc valve 

body, instrumentation element, nozzle, filter housing, and piping and fittings, and nickel-alloy

piping and fittings, valve body, expansion joint, and rupture disc exposed to air-outdoor 

(external), which are being managed for loss of material by the External Surfaces Monitoring 

Program citing generic note G, is documented in SER Section 3.3.2.3.15.

In LRA Tables 3.3.2-17 and 3.3.2-40, the applicant stated that the stainless steel bolting 

exposed to air-outdoor is being managed for loss of material by the Bolting Integrity Program. 

The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel bolting exposed to air-outdoor is not specifically addressed in the GALL 

Report, Table IX.C of the GALL Report states that stainless steel material is susceptible to a 

variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion and cracking due to SCC. The staff noted that given the plant’s proximity to the 

ocean, stainless steel bolting exposed to the outdoor air environment would be susceptible to 

SCC. However, the staff noted that the applicant did not identify SCC as an AERM for these 

components. By letter dated February 24, 2011, the staff issued RAI 3.3-1 requesting that the 

applicant justify its management of this material, environment, AERM, and AMP combination.

In its response dated March 22, 2011, the applicant stated that SCC has been added as an 

aging mechanism for stainless steel components exposed to air-outdoor environment. The 

applicant added a new item to manage cracking of bolts by the Bolting Integrity Program. The 

staff finds the applicant’s response acceptable because the applicant modified the LRA to 

include cracking due to SCC as an applicable aging effect for stainless steel components 
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exposed to outdoor-air containing high levels of chloride and is managing SCC by the Bolting 

Integrity Program. The staff’s concern described in RAI 3.3-1 is resolved.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for stainless steel bolting exposed to air-outdoor in the 

auxiliary system, the GALL Report has items for other material bolting exposed to air-outdoor 

managed by the Bolting Integrity Program. The staff finds the applicant’s proposal to manage 

aging using the Bolting Integrity Program acceptable because the Bolting Integrity Program 

inspects the bolting through periodic visual inspections to verify that the aging effect, loss of 

material and SCC, will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation; therefore, it is acceptable.

In LRA Tables 3.3.2-17 and 3.3.2-40, the applicant stated that the stainless steel bolting 

exposed to air-outdoor is being managed for loss of preload by the Bolting Integrity Program. 

The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel bolting exposed to air-outdoor is not specifically addressed in the GALL 

Report, Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to 

a variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion and cracking due to SCC. The staff noted that the applicant addressed loss of 

material in additional items for each of these components and the staff evaluated SCC as 

documented in SER Section 3.3.2.3.17 for this component, material, and environment 

combination; therefore, the aging effect of concern is loss of preload, which is addressed in the 

AMR 

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed 

to air-outdoor in the auxiliary system, the GALL Report has items for other material bolting 

exposed to air-outdoor managed by the Bolting Integrity Program. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program conducts bolting assembly and maintenance control such as application of 

appropriate gasket alignment, torque, lubricants, and preload. The program also inspects for 

leakage and loose or missing nuts which verify that the aging effect, loss of preload, will be 

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

for the period of extended operation.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).
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3.3.2.3.18 Fuel Storage Building Air Handling System—Aging Management Evaluation—LRA

Table 3.3.2-18

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for 

the fuel storage building air handling system component groups.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for elastomer flexible connectors exposed to air with borated water 

leakage (external), which are being managed for loss of material by the External Surfaces 

Monitoring Program citing generic note G, is documented in SER Section 3.3.2.3.5.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.19 Hot Water Heating System—Aging Management Evaluation—LRA Table 3.3.2-19

The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for 

the hot water heating system component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

In LRA Tables 3.3.2-19, and 3.3.2-44, the applicant stated that the steel bolting exposed to 

air-indoor uncontrolled (external) is being managed for loss of preload by the Bolting Integrity 

Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though steel bolting exposed to air-indoor uncontrolled is not specifically addressed in the GALL 

Report, Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that steel material is susceptible to a variety 

of aging effects and mechanisms, including loss of material due to general, pitting and crevice 

corrosion. The staff noted that the applicant addressed loss of material in additional items for 

each of these components; therefore, the aging effect of concern is loss of preload, which is 

addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of steel bolting exposed to 

condensation in the auxiliary system, the GALL Report has items for loss of preload of other 

material bolting managed by the Bolting Integrity Program. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program conducts bolting assembly and maintenance control such as application of 

appropriate gasket alignment, torque, lubricants, and preload. The program also inspects for 
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leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be 

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

for the period of extended operation.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.20 Instrument Air System—Aging Management Evaluation—LRA Table 3.3.2-20

The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for 

the instrument air system component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, 

plastic, and polyolefin) piping, piping components, and piping elements, flexible hose, tanks, 

and instrument elements, exposed to air-indoor uncontrolled (internal or external) and air-indoor 

controlled external environments with no aging effect and no AMP proposed citing generic 

note F, is documented in SER Section 3.3.2.3.4.

The staff’s evaluation for polymer (PVC, polypropylene, fluoropolymer, polycarbonate, 

polyolefin, and plastic ) piping, piping components and piping elements, tank and flexible hose 

exposed to air with borated water external environment, with no aging effect and no AMP 

proposed citing generic note F, is documented in SER Section 3.3.2.3.11.

The staff’s evaluation for aluminum filter housings, instrumentation elements, and valve bodies 

exposed to dried air, which cite generic note G, is documented in Section 3.3.2.3.12.

In LRA Table 3.3.2-20, the applicant stated that the aluminum heat exchanger components 

exposed to lubricating oil (internal) are being managed for loss of material by the Lubricating Oil 

Analysis Program, as augmented by the One-Time Inspection Program. The AMR item cites 

generic note F.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because, 

as stated in the ASM Handbook, ASM International, 2005, aluminum is a corrosion-resistant 

material. For aluminum heat exchanger components used in heat exchanger shells and tubes 
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internally exposed to oil, the applicant identified the appropriate aging effect (i.e., loss of 

material). This aging effect is managed by the Lubricating Oil Analysis Program and is 

augmented by the One-Time Inspection Program. The staff’s evaluation of the applicant’s 

Lubricating Oil Analysis Program and One-Time Inspection Program is documented in SER 

Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. The Lubricating Oil Analysis Program performs 

oil condition monitoring activities to manage the aging effects of loss of material due to galvanic, 

general, pitting, crevice, and MIC and fouling and heat transfer degradation due to fouling. The 

One-Time Inspection Program performs a one-time inspection of selected components 

containing lubricating oil determined to be most susceptible to the potential degradation 

mechanisms to verify the effectiveness of the Lubricating Oil Analysis Program.

The staff finds the applicant’s proposal to manage aging using the Lubricating Oil Analysis 

Program, as augmented by the One-Time Inspection Program, acceptable because the 

Lubricating Oil Analysis Program monitors for contaminants that could cause corrosion and for 

degradation of the oil, which could be caused by corrosion products. This analysis is 

supplemented by the One-Time Inspection Program, which uses visual examination and other 

examination techniques to inspect for the loss of material in areas where the most severe aging 

effects would be expected to occur.

In LRA Tables 3.3.2-20 and 3.3.2-23, the applicant stated that the aluminum valve body and 

pump casing components exposed to lubricating oil (internal) are being managed for loss of 

material by the Lubricating Oil Analysis Program, as augmented by the One-Time Inspection 

Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material and environment combination. As stated 

in the ASM Handbook, ASM International, 2005, aluminum is a corrosion-resistant material, and 

for aluminum valve body and pump casing components internally exposed to oil, the applicant 

identified the appropriate aging effects (i.e., loss of material). This aging effect is managed by 

the Lubricating Oil Analysis Program and is augmented by the One-Time Inspection Program. 

The staff’s evaluations of the applicant’s Lubricating Oil Analysis Program and the One-Time 

Inspection Program are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. 

The Lubricating Oil Analysis Program performs oil condition monitoring activities to manage the 

aging effects of loss of material due to galvanic, general, pitting, crevice, and MIC and fouling 

and heat transfer degradation due to fouling. The One-Time Inspection Program performs a 

one-time inspection of selected components containing lubricating oil determined to be most 

susceptible to the potential degradation mechanisms to verify the effectiveness of the 

Lubricating Oil Analysis Program 

The staff finds the applicant’s proposal to manage aging using the Lubricating Oil Analysis 

Program, as augmented by the One-Time Inspection Program, acceptable because the 

Lubricating Oil Analysis Program monitors for contaminants that could cause corrosion and for 

degradation of the oil, which could be caused by corrosion products. This analysis is 

supplemented by the One-Time Inspection Program, which uses visual examination and other 

examination techniques to inspect for the loss of material in areas where the most severe aging 

effects would be expected to occur.

In LRA Table 3.3.2-20, the applicant stated that for polymer (CPVC and fluoropolymer) piping 

and fittings, and flexible hose exposed to dried air internal environment, there is no aging effect,

and no AMP is proposed. The AMR items cite generic note F. These items also cite 

plant-specific note 2, which states the following:
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Unlike metals, polymers do not display corrosion rates. Rather than depending 

on an oxide layer for protection, they depend on chemical resistance to the 

environment to which they are exposed. The plastic is either completely resistant 

to the environment or it deteriorates. Therefore, acceptability for the use of 

polymers within a given environment is a design driven criterion. Once the 

appropriate material is chosen, the system will have no aging effects. This is 

consistent with plant operating experience.

The staff noted that, as identified in Engineering Materials Handbook—Engineering Plastics, 

American Society for Metals International, Copyright 1988, rigid polymers are unaffected by 

water, concentrated alkalis, non-oxidizing acids, oils, ozone, sunlight, or humidity changes. The 

staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather 

than depend on an oxide layer for protection, they depend on chemical resistance to the 

environments to which they are exposed and the use of thermoplastics in power plant 

environments is a design-driven criterion. The staff further noted that thermoplastic material is 

impervious and, once selected for the environment, will not have any significant age-related 

degradation. The staff reviewed the associated items in the LRA and confirmed that no aging 

effect is applicable for this component, material, and environment combination because there is 

no indication in the industry that polymers or thermoplastics exposed to an internal or external 

indoor air environment have any aging effects requiring management. Additionally, the 

generally low operating temperatures and historically good chemical resistance data for polymer 

components, combined with a lack of historically negative operating experience, indicate that 

polymers are not likely to experience any degradation from the non-aggressive dried air 

environment.

In LRA Tables 3.3.2-20 and 3.3.2-23, the applicant stated that the aluminum components 

exposed to lubricating oil are being managed for loss of material by the Lubricating Oil Analysis 

and One-Time Inspection Programs. The AMR item associated with Table 3.3.2-20 cite generic 

note F, and AMR items associated with Tables 3.3.2-23, 3.4.2-6, and 3.4.2-7 cite generic 

note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

loss of material may occur due to pitting and crevice corrosion of the aluminum components 

exposed to lubricating oil in the heat exchanger, valve body, pump casing, and instrumentation 

elements.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs are documented in SER Section 3.0.3.2.16 and 3.0.3.1.8, respectively. 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 was determined 

to be consistent with the GALL Report. Additionally, the applicant stated that the One-Time 

Inspection Program will be used to examine aluminum components and elements to verify the 

effectiveness of the Lubricating Oil Analysis Program.

In LRA Table 3.3.2-20, the applicant stated that elastomer flexible hoses exposed to 

condensation or dried air (internal) are being managed for hardening and loss of strength with 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. 

The AMR item cite generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 
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Report, Table IX.C, states that elastomers are susceptible to hardening and loss of strength at 

temperatures over about 95 °F (35 °C) and when exposed to additional aging factors such as 

ozone, oxidation, and radiation. The staff noted that the environment of interest, condensation 

(internal), has the potential of being in the temperature range for elastomer susceptibility to 

aging; therefore, the aging effect of concern is hardening and loss of strength, which is 

addressed in the AMR.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:

• The program includes periodic visual inspections performed during maintenance and 

surveillance activities, which can identify localized discoloration and surface 

irregularities.

• Non-visual examinations, such as scratching, which will screen for residues and 

breakdown of the material, and stretching and pressing, which will evaluate the material 

resiliency to determine if hardening and loss of strength are occurring that could result in 

a loss of the component-intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

result of material, environment, and AMP combinations not addressed in the GALL Report. The 

staff finds that the applicant 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.21 Leak Detection System—Aging Management Evaluation—LRA Table 3.3.2-21

The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for 

the leak detection system component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.22 Mechanical Seal Supply System—Aging Management Evaluation—LRA

Table 3.3.2-22

The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations for 

the mechanical seal supply system component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor and being managed for 

loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.
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On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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 Miscellaneous Equipment System—Aging Management Evaluation—LRA

Table 3.3.2-23

The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations for 

the miscellaneous equipment system component groups.

The staff’s evaluation for elastomer flexible hose exposed to fuel oil or lubricating oil (internal),

which are being managed for 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 SER Section 3.3.2.3.3.

The staff’s evaluation for aluminum pump casing components, exposed to lubricating oil 

(internal) and being managed for loss of material by the Lubricating Oil Analysis and One-Time 

Inspection Programs citing generic note G, is documented in SER Section 3.3.2.3.20.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for aluminum components, exposed to lubricating oil are being managed 

for loss of material by the by the Lubricating Oil Analysis Program and the One-Time Inspection 

Program citing generic note G, is documented in SER Section 3.3.2.3.20.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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 Nitrogen Gas System—Aging Management Evaluation—LRA Table 3.3.2-24

The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations for 

the nitrogen gas system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, which is being managed 

for loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).
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3.3.2.3.25 Oil Collection for Reactor Coolant Pumps System—Aging Management 

Evaluation—LRA Table 3.3.2-25

The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations for 

the oil collection for reactor coolant pumps system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, which is being managed 

for loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.26 Plant Floor Drain System—Aging Management Evaluation—LRA Table 3.3.2-26

The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations for 

the plant floor drain system component groups.

The staff’s evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, 

plastic, and polyolefin) piping, piping components, and piping elements, flexible hose, tanks, 

and instrument elements exposed to air-indoor uncontrolled (internal or external) and air-indoor 

controlled external environments, with no aging effect and no AMP proposed citing generic 

note F, is documented in SER Section 3.3.2.3.4.

The staff’s evaluation for polymer piping, piping components and piping elements, and filter 

housing exposed to raw water environment, with no aging effect and no AMP proposed citing 

generic note F, is documented in SER Section 3.3.2.3.4.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.27 Potable Water System—Aging Management Evaluation—LRA Table 3.3.2-27

The staff reviewed LRA Table 3.3.2-27, which summarizes the results of AMR evaluations for 

the potable water system component groups.

The staff’s review did not find any items indicating plant-specific Notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.3.2.1.
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3.3.2.3.28 Primary Auxiliary Building Air Handling System—Aging Management Evaluation—

LRA Table 3.3.2-28

The staff reviewed LRA Table 3.3.2-28, which summarizes the results of AMR evaluations for 

the primary auxiliary building air handling system component groups.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for elastomer flexible connectors exposed to air with borated water 

leakage (external), which are being managed for loss of material by the External Surfaces 

Monitoring Program citing generic note G, is documented in SER Section 3.3.2.3.5.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.29 Primary Component Cooling Water System—Aging Management Evaluation—LRA

Table 3.3.2-29

The staff reviewed LRA Table 3.3.2-29, which summarizes the results of AMR evaluations for 

the primary component cooling water system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, which is being managed 

for loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for nickel-alloy components exposed borated water leakage that is not 

subject to an aging effect requiring management, with generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in

SER Section 3.3.2.3.3.

The staff’s evaluation for glass piping elements exposed to closed-cycle cooling water (internal) 

or gas (internal), which cite generic note G, is documented in SER Section 3.3.2.3.9.

In LRA Table 3.3.2-29, the applicant stated that the nickel-alloy flexible hoses and valve bodies 

exposed to closed-cycle cooling water are being managed for loss of material by the 

Closed-Cycle Cooling Water System Program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA in order to confirm that the applicant 

identified the correct aging effect(s) for this component, material, and environment combination. 

The staff noted that GALL Table IX.F states that nickel based alloy components are susceptible 

to crevice corrosion and that high temperatures are required for nickel alloys to be susceptible 

to certain types of SCC. The staff confirmed the applicant identified the correct aging effect 

because, as noted in the GALL Report, nickel-alloy components are susceptible to loss of 
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material, and the maximum temperature in the primary component cooling water system is less 

than 140 °F and is not high enough to cause SCC for this material.

The staff’s evaluation of the applicant’s Closed-Cycle Cooling Water Program is documented in 

SER Section 3.0.3.2.4. The staff noted that the Closed-Cycle Cooling Water Program consists 

of visual inspections, chemistry control, and monitoring of corrosion coupons. The staff finds 

the applicant’s proposal to manage aging using the Closed-Cycle Cooling Water Program 

acceptable for the following reasons:

• The applicant will conduct visual inspections that are capable of identifying loss of 

material.

• The applicant is using chemistry control techniques that will minimize the susceptibility to 

corrosion.

• The applicant will monitor corrosion coupons that will provide an indication of corrosion 

in the closed-cycle cooling water systems.

In LRA Table 3.3.2-29, the applicant stated that the titanium heat exchanger components 

exposed to closed-cycle cooling water and raw water are being managed for reduction of heat 

transfer by the Closed-Cycle Cooling Water System and Open-Cycle Cooling Water System 

Programs. The AMR items cite generic note F.

The staff reviewed the associated items in the LRA in order to confirm that the applicant 

identified the correct aging effects for this component, material, and environment combination. 

The staff finds consideration of reduction in heat transfer for titanium heat exchanger 

components exposed to closed-cycle cooling or raw water environments to be appropriate 

because the GALL Report includes this aging effect for all other heat exchanger component 

materials in these environments. However, titanium is known to be susceptible to cracking in 

certain environments depending upon the type of titanium, and it can also undergo loss of 

material due to crevice corrosion at certain chloride levels and temperatures. The applicant did 

not address cracking or loss of material as relevant aging effects for the titanium alloy heat 

exchanger tubes. By letter dated January 5, 2011, the staff issued RAI 3.3.2.3.29-1 asking the 

applicant to justify why cracking and loss of material had not been considered as relevant aging 

effects for the titanium alloy heat exchanger tubes.

In its response dated February 3, 2011, the applicant stated that the titanium components within 

the scope of license renewal are titanium Grade 1 or Grade 2. The applicant also stated that 

although the maximum design temperature for the heat exchangers is 200 °F (93 °C), the 

normal operating temperature is well below 160 °F (71 °C). The applicant cited statements in 

Revision 2 of the GALL Report, which indicate that unalloyed titanium (including Grade 1 and

Grade 2) are not susceptible to SCC in seawater or brackish raw water but may be susceptible

to crevice corrosion in saltwater environments at elevated temperature greater than 160 °F 

(71 °C). The applicant also cited statements in the EPRI Report, “Non-Class 1 Mechanical 

Implementation Guideline and Mechanical Tools,” which indicate that titanium alloys exhibit 

negligible corrosion rates in seawater for temperatures as high as 500 °F (260 °C) and that 

crevice corrosion requires significant amounts of chloride. The applicant further stated that 

operating experience did not indicate any cracking or loss of material during the 14 years these 

components have been in service. The staff finds the applicant’s justification acceptable 

because loss of material or SCC would not be expected for the grades of titanium being used in 

the environmental conditions with normal operating temperatures less than 160 °F (71 °C). The 

staff’s concern described in RAI 3.3.2.3.29-1 is resolved. The staff confirmed that the applicant 
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identified the correct aging effects for this component, material, and environment combination

for the associated items in the LRA because loss of material and cracking should not occur, 

based on the above RAI response.

The staff’s evaluations of the applicant’s Closed-Cycle Cooling Water System and Open-Cycle 

Cooling Water System Programs are documented in SER Sections 3.0.3.2.4 and 3.0.3.2.3, 

respectively. The staff finds the applicant’s proposal to manage aging using the referenced 

programs acceptable because the Closed-Cycle Cooling Water and Open-Cycle Cooling Water 

Programs verify that reduction in heat transfer does not occur through internal inspections of 

opportunity or through periodic performance testing.

In LRA Table 3.3.2-29, the applicant stated that, for the titanium heat exchanger components 

(channel head) and piping and fittings exposed externally to uncontrolled indoor air, there is no 

aging effect, and no AMP is proposed. The AMR item cite generic note F. Items associated 

with heat exchanger components (channel head) and piping and fittings in LRA Table 3.3.2-29 

cite plant-specific note 3, which states that titanium material has superior resistance to general, 

pitting, crevice, and MIC in both air and water environments due to a protective oxide film. The 

applicant also stated that this is consistent with plant operating experience.

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment combination because of the excellent 

corrosion resistance that titanium exhibits in air, oxidizing, and aqueous conditions. This is 

supported by information in the Metals Handbook (Reference 1) and the Metals Properties 

Handbook: Titanium Alloys (Reference 2). Titanium and its alloys are fully resistant to general 

corrosion and pitting in water, natural waters and steam to 600 °F (315 °C). In addition, multiple 

references (References 3, 4, and 5) state that titanium is resistant to pitting, general, and 

crevice corrosion and SCC in turbine exhaust steam environments in essence due to its 

formation of very stable, continuous, highly adherent, and protective oxide films on metal 

surfaces. In addition, the staff also notes that, due to its corrosion resistance capabilities, 

titanium is widely used in the refinery industry for condenser tubing and the aerospace industry 

in temperature applications up to 1,112 °F (600 °C). Based on these references and industry 

applications, the staff finds the applicant’s proposal, that there are no other AERMs, acceptable 

based on titanium’s resistance to pitting, general, and crevice corrosion and SCC in air and 

aqueous systems.

In LRA Table 3.3.2-29, the applicant stated that for titanium heat exchanger components 

(channel head) and piping and fittings exposed to air with borated water leakage, there is no 

aging effect, and no AMP is proposed. The AMR item cite generic note F.

The staff reviewed the associated items in the LRA and noted that the components of interest, 

heat exchanger components and piping and fittings, may be in a temperature regime that would 

make it susceptible to crevice attack. In addition, the environment, air with borated water 

leakage, may—along with higher temperatures—place the titanium alloy material in a condition 

where it would be susceptible to SCC. By letter dated January 5, 2011, the staff issued 

RAI 3.3.2.3.29-1 requesting that the applicant justify the exclusion of the crevice corrosion and 

SCC aging effects. If the crevice corrosion and SCC aging effects need to be considered during 

the period of extended operation, the staff asked the applicant to describe the AMP that will 

manage the aging effects.

In its response dated February 3, 2011, the applicant stated that the tubes and all tube-side 

wetted components and surfaces are titanium Grade 2, except for the tubesheet and channel 

head cover, which are steel clad with titanium Grade 1. The small-bore piping is also titanium 
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Grade 2. Grade 1 and Grade 2 titanium are unalloyed titanium. The applicant also stated that 

the maximum design temperature for the heat exchangers is 200 °F; however, normal operating 

temperatures are well below 160 °F (heat exchanger inlet and outlet temperatures are less than 

70 °F with the plant at 100 percent power) for the shell side (closed-cycle cooling water) 

materials and less than 65 °F for the tube side (raw water and seawater) materials. During 

RFOs, with RHR in service, heat exchanger inlet and outlet temperatures are less than 100 °F. 

The applicant further quoted EPRI Mechanical Tools (Reference 6), which states the following:

[T]itanium and titanium alloys are also susceptible to crevice corrosion although it 

requires significant aqueous chloride contamination (> 1000 ppm) at elevated 

temperatures (> 160 °F) to be subject to this attack. Grades 1, 2, 7, 11 and 12 of 

titanium and its alloys are virtually immune to SCC except in a few specific 

environments (such as anhydrous methanol/halide solutions, red fuming nitric 

acid (HNO3) and liquid cadmium), none of which are applicable in raw water 

systems.

The applicant concluded by stating that these titanium components have been in service for 

approximately 14 years, with no indications of cracking or loss of material.

The staff finds the applicant’s response acceptable because the staff noted that titanium alloys 

are resistant to water, seawater, and boric acid (Reference 4). In addition, the current staff 

position is that titanium and titanium alloys may be susceptible to crevice corrosion in saltwater 

environments at elevated temperatures (greater than 160 °F), and ASTM Grades 1, 2, 7, 11, or 

12 are not susceptible to SCC in seawater or brackish raw water. The staff further noted that 

the operating temperatures of the applicant’s titanium components are well below 160 °F. In 

addition, the staff noted that applicant’s titanium components are either Grade 1 or 2 material, 

which is susceptible to SCC only in a few specific cases; however, these conditions are not 

found in the applicant’s operating environment. The staff further noted the applicant’s operating 

experience confirmed that there has not been loss of material since the equipment entered 

service. Therefore, the staff’s concern described in RAI 3.3.2.3.29-1 is resolved.

In LRA Table 3.3.2-29, the applicant stated that for the titanium and steel with titanium cladding 

heat exchanger components (channel head, head cover, and tubesheet) and piping and fittings 

exposed internally to raw water, there is no aging effect, and no AMP is proposed. The AMR 

item cites generic note F. Items associated with heat exchanger components (channel head, 

head cover, and tubesheet) and piping and fittings in Table 3.3.2-29 cite plant-specific note 3,

which states that titanium material has superior resistance to general, pitting, crevice, and MIC

in both air and water environments due to a protective oxide film. The applicant also indicated 

that this was consistent with plant operating experience.

The staff reviewed the associated items in the LRA and noted that, in LRA Table 3.0-1, the 

applicant defined raw water as raw, untreated fresh, salt, potable, or groundwater. The staff 

noted that although titanium has excellent corrosion resistance in air, oxidizing, and aqueous 

conditions, certain alloys of titanium can exhibit crevice corrosion and SCC in seawater at 

temperatures greater than 167 °F (75 °C) (Reference 7). The components of interest, heat 

exchanger components and piping and fittings, may be in a temperature regime that would 

make it susceptible to crevice attack. In addition, the environment, raw water, may—along with 

higher temperatures—place the titanium alloy material in a condition where it would be 

susceptible to SCC. By letter dated January 5, 2011, the staff issued RAI 3.3.2.3.29-1 

requesting that the applicant justify the exclusion of the crevice corrosion and SCC aging 

effects. Additionally, if the crevice corrosion and SCC aging effects need to be considered 
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during the period of extended operation, the staff asked the applicant to describe the AMP that 

will manage the aging effects.

In its response dated February 3, 2011, the applicant stated that the tubes and all tube side 

wetted components and surfaces are titanium Grade 2, except for the tubesheet and channel 

head cover, which are steel clad with titanium Grade 1. The small-bore piping is also titanium 

Grade 2. Grade 1 and Grade 2 titanium are unalloyed titanium. The applicant also stated that 

the maximum design temperature for the heat exchangers is 200 °F; however, normal operating 

temperatures are well below 160 °F (heat exchanger inlet and outlet temperatures are less than 

70 °F with the plant at 100 percent power) for the shell side (closed-cycle cooling water) 

materials and less than 65 °F for the tube side (raw water and seawater) materials. During 

RFOs, with RHR in service, heat exchanger inlet and outlet temperatures are less than 100 °F. 

The applicant further quoted EPRI Mechanical Tools (Reference 6), which states the following:

[T]itanium and titanium alloys are also susceptible to crevice corrosion although it 

requires significant aqueous chloride contamination (> 1000 ppm) at elevated 

temperatures (> 160 °F) to be subject to this attack. Grades 1, 2, 7, 11 and 12 of 

titanium and its alloys are virtually immune to SCC except in a few specific 

environments (such as anhydrous methanol/halide solutions, red fuming nitric 

acid (HNO3) and liquid cadmium), none of which are applicable in raw water 

systems.

The applicant concluded by stating that these titanium components have been in service for 

approximately 14 years, with no indications of cracking or loss of material.

The staff finds the applicant’s response acceptable because the operating temperatures of the 

applicant’s titanium components were well below 160 °F, a temperature above which crevice 

corrosion could be an issue. In addition, the current staff position is that titanium and titanium 

alloys may be susceptible to crevice corrosion in saltwater environments at elevated 

temperatures (greater than 160 °F), and ASTM Grades 1, 2, 7, 11, or 12 are not susceptible to 

SCC in seawater or brackish raw water. In addition, the staff noted that applicant’s titanium 

components are either Grade 1 or 2 material, which is susceptible to SCC in a few specific 

cases; however, these conditions are not found in the applicant’s operating environment. The 

staff further noted the applicant’s operating experience confirmed that there has not been loss of 

material since the equipment entered service. Therefore, the staff’s concern described in 

RAI 3.3.2.3.29-1 is resolved.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.30 Radiation Monitoring System—Aging Management Evaluation—LRA Table 3.3.2-30

The staff reviewed LRA Table 3.3.2-30, which summarizes the results of AMR evaluations for 

the radiation monitoring system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, which is being managed 

for loss of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.
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The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

The staff’s evaluation for glass piping elements exposed to closed-cycle cooling water (internal) 

or gas (internal), which cite generic note G, is documented in SER Section 3.3.2.3.9.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.31 Reactor Makeup Water System—Aging Management Evaluation—LRA

Table 3.3.2-31

The staff reviewed LRA Table 3.3.2-31, which summarizes the results of AMR evaluations for 

the reactor makeup water system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.32 Release Recovery System—Aging Management Evaluation—LRA Table 3.3.2-32

The staff reviewed LRA Table 3.3.2-32, which summarizes the results of AMR evaluations for 

the release recovery system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.33 Resin Sluicing System—Aging Management Evaluation—LRA Table 3.3.2-33

The staff reviewed LRA Table 3.3.2-33, which summarizes the results of AMR evaluations for 

the resin sluicing system component groups.
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The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.34 Roof Drains System—Aging Management Evaluation—LRA Table 3.3.2-34

The staff reviewed LRA Table 3.3.2-34, which summarizes the results of AMR evaluations for 

the roof drains system component groups.

The staff’s review did not find any items indicating plant-specific Notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.3.2.1.

3.3.2.3.35 Sample System—Aging Management Evaluation—LRA Table 3.3.2-35

The staff reviewed LRA Table 3.3.2-35, which summarizes the results of AMR evaluations for 

the sample system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

The staff’s evaluation for polymer (PVC, PVDF, polypropylene, fluoropolymer, polycarbonate, 

plastic, and polyolefin) piping, piping components, and piping elements, flexible hose, tanks, 

and instrument elements exposed to air-indoor uncontrolled (internal or external) and air-indoor 

controlled external environments, with no aging effect and no AMP proposed citing generic 

note F, is documented in SER Section 3.3.2.3.4.

The staff’s evaluation for polymer (PVC, polypropylene, fluoropolymer, polycarbonate, 

polyolefin, and plastic ) piping, piping components and piping elements, tank and flexible hose 

exposed to air with borated water external environment, with no aging effect and no AMP 

proposed citing generic note F, is documented in SER Section 3.3.2.3.11.

In LRA Table 3.3.2-35, the applicant stated that for polymer (polycarbonate, plastic, polyolefin) 

instrumentation element and traps exposed to treated water or treated borated water internal 

environment, there is no aging effect, and no AMP is proposed. The AMR items cite generic 

note F. These items also cite plant-specific note 1, which states the following:

Unlike metals, polymers do not display corrosion rates. Rather than depending 

on an oxide layer for protection, they depend on chemical resistance to the 
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environment to which they are exposed. The plastic is either completely resistant 

to the environment or it deteriorates. Therefore, acceptability for the use of 

polymers within a given environment is a design driven criterion. Once the 

appropriate material is chosen, the system will have no aging effects. This is 

consistent with plant operating experience.

The staff noted that, as identified in Engineering Materials Handbook—Engineering Plastics, 

American Society for Metals International, Copyright 1988, rigid polymers are unaffected by 

water, concentrated alkalis, non-oxidizing acids, oils, ozone, sunlight, or humidity changes. The 

staff also noted that, unlike metals, thermoplastics do not display corrosion rates, and rather 

than depend on an oxide layer for protection, they depend on chemical resistance to the 

environments to which they are exposed and the use of thermoplastics in power plant 

environments is a design-driven criterion. The staff further noted that thermoplastic material is 

impervious and, once selected for the environment, will not have any significant age-related 

degradation. The staff reviewed the associated items in the LRA and confirmed that no aging 

effect is applicable for this component, material, and environment combination because there is 

no indication in the industry that polymers or thermoplastics exposed to an internal or external 

indoor air environment have any aging effects requiring management. Additionally, the 

generally low operating temperatures and historically good chemical resistance data for polymer 

components, combined with a lack of historically negative operating experience, indicate that 

polymers are not likely to experience any degradation from the non-aggressive treated water or 

treated borated water environment.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

result of material, environment, and AMP combinations not addressed in the GALL Report. The 

staff finds that the applicant 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 for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.36 Screen Wash System—Aging Management Evaluation—LRA Table 3.3.2-36

The staff reviewed LRA Table 3.3.2-36, which summarizes the results of AMR evaluations for 

the screen wash system component groups.

The staff’s evaluation for steel bolting exposed to condensation, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.19.

The staff’s evaluation for nickel alloy exposed to condensation, being managed for loss of 

material by the External Surfaces Program citing generic note G, is documented in SER 

Section 3.3.2.3.15.

The staff’s evaluation for fiberglass filter housings exposed to condensation (external) or raw 

water (internal) with no AERM and no recommended AMP, citing generic note F, is documented 

in Section 3.3.2.3.4.

In LRA Table 3.3.2-36, the applicant stated that the stainless steel bolting exposed to 

condensation is being managed for loss of preload by the Bolting Integrity Program. The AMR 

item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 
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though stainless steel bolting exposed to condensation is not specifically addressed in the GALL 

Report, Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to 

a variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion and cracking due to SCC. The staff noted that the environment of interest, 

condensation would not induce SCC in stainless steel material because stainless steel is 

inherently resistant to SCC in a condensation environment and becomes susceptible to SCC 

only at temperatures above 140 °F (60 °C). The staff noted that the applicant addressed loss of 

material in additional items for each of these components; therefore, the aging effect of concern 

is loss of preload, which is addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed 

to condensation in the auxiliary system, the GALL Report has items for loss of preload of other 

material bolting managed by the Bolting Integrity Program. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program conducts bolting assembly and maintenance control such as application of 

appropriate gasket alignment, torque, lubricants, and preload. Additionally, the program 

inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of 

preload, will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.37 Service Water System—Aging Management Evaluation—LRA Table 3.3.2-37

The staff reviewed LRA Table 3.3.2-37, which summarizes the results of AMR evaluations for 

the service water system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for nickel-alloy components exposed borated water leakage that is not 

subject to an aging effect requiring management, with generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

The staff’s evaluation for polymer piping, piping components and piping elements, and filter 

housing exposed to raw water environment, with no aging effect and no AMP proposed citing 

generic note F, is documented in SER Section 3.3.2.3.4.
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The staff’s evaluation for polymer (PVC) piping and fittings and filter housing exposed to 

condensation (internal or external) environment, with no aging effect and no AMP proposed 

citing generic note F, is documented in SER Section 3.3.2.3.4.

The staff’s evaluation for copper alloy and copper alloy with greater than 15 percent zinc valve 

body, instrumentation element, nozzle, filter housing, and piping and fittings, and nickel-alloy

piping and fittings, valve body, expansion joint, and rupture disc exposed to air-outdoor 

(external), which are being managed for loss of material by the External Surfaces Monitoring 

Program citing generic note G, is documented in SER Section 3.3.2.3.15.

In LRA Table 3.3.2-37, the applicant stated that the stainless steel bolting exposed to raw water 

is being managed for loss of preload by the Bolting Integrity Program. The AMR item cites 

generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material and environment combination. Even 

though stainless steel bolting exposed to raw water is not specifically addressed in the GALL 

Report, Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that stainless steel material is susceptible to 

a variety of aging effects and mechanisms, including loss of material due to pitting and crevice 

corrosion, MIC, and cracking due to SCC. The staff noted that the environment of interest, raw 

water, would not induce SCC in stainless steel material because stainless steel becomes 

susceptible to corrosion in the raw water environment only at temperatures above 140 °F 

(60 °C). The staff noted that the applicant addressed loss of material in additional items for 

each of these components; therefore, the aging effect of concern is loss of preload, which is 

addressed in the AMR

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed 

to raw water in the auxiliary system, the GALL Report has items for loss of preload of other 

material bolting managed by the Bolting Integrity Program. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program conducts bolting assembly and maintenance control such as application of 

appropriate gasket alignment, torque, lubricants, and preload. The program also inspects for 

leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be 

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

for the period of extended operation.

In LRA Table 3.3.2-37, the applicant stated that steel bolting exposed to raw water is being 

managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic 

note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though steel bolting exposed to raw water is not specifically addressed in the GALL Report,

Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that steel material is susceptible to a variety 

of aging effects and mechanisms, including loss of material due to general, pitting, and crevice 

corrosion. The staff noted that the applicant addressed loss of material in additional items for 
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each of these components; therefore, the aging effect of concern is loss of preload, which is 

addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of steel bolting exposed to raw 

water in the auxiliary system, the GALL Report has items for loss of preload of other material 

bolting managed by the Bolting Integrity Program. The staff finds the applicant’s proposal to 

manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity 

Program conducts bolting assembly and maintenance control such as application of appropriate 

gasket alignment, torque, lubricants, and preload. The program also inspects for leakage and 

loose or missing nuts, which verify that the aging effect, loss of preload, will be adequately 

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

period of extended operation.

In LRA Table 3.3.2-37, the applicant stated that the elastomer expansion joint exposed to 

condensation (external) are being managed for hardening and loss of strength by the External 

Surfaces Monitoring Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, Table IX.C, indicates that elastomers are susceptible to hardening and loss of strength 

at temperatures over 95 °F (35 °C), and the environment of interest, condensation, can be in a 

temperature range where the elastomer is susceptible to hardening and loss of strength.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff noted that the applicant’s program includes non-visual 

examinations, such as scratching, to determine if scale or residues are present or determine if 

there is a breakdown of material. The program includes bending or folding of the elastomer to 

detect cracking that initiates at the surface, stretching and pressing to determine the resistance 

of the material to hardening effects, and pressing to gauge the materials resiliency. The staff 

finds the applicant’s proposal to manage aging using the External Surfaces Monitoring Program 

acceptable because the program uses periodic visual inspections as well as non-visual tactile 

examinations, which are capable of detecting hardening and loss of strength.

In LRA Table 3.3.2-37, the applicant stated that copper-alloy (greater than 15 percent zinc) 

bolting exposed to raw water is being managed for loss of preload by the Bolting Integrity 

Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though copper-alloy (greater than 15 percent zinc) bolting exposed to raw water is not 

specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss of 

preload can occur independent of environmental conditions because it can be caused by 

thermal or mechanical effects. In addition, the applicant included loss of material, which is 

another applicable aging affect. Additionally, Table IX.C of the GALL Report states that 

copper-alloy (greater than 15 percent zinc) material is susceptible to a variety of aging effects 

and mechanisms, including loss of material and selective leaching. The staff noted that the 

applicant addressed loss of material in additional items for each of these components and the 

aging effect loss of preload, which is addressed in this AMR. However, the staff noted that the 

applicant did not reference the GALL Report AMR, item 3.3.1-84, for loss of material due to 

selective leaching in copper-alloy (greater than 15 percent zinc) bolting exposed to raw water. 
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By letter dated February 24, 2011, the staff issued RAI 3.3.2-37.1 requesting that the applicant 

justify its management of this material, environment, AERM, and AMP combination.

In its response dated March 22, 2011, the applicant stated that loss of material due to selective 

leaching has been added as an aging mechanism for copper alloy greater than 15 percent zinc 

components exposed to raw water environment. The staff finds the applicant’s response 

acceptable because the applicant has modified the LRA to include selective leaching as an 

applicable aging effect for copper-alloy (greater than 15 percent zinc) bolting exposed to raw 

water and manage the selective leaching by the Selective Leaching of Materials Program. The 

staff’s concern described in RAI 3.3.2.3.37-1 is resolved

The staff’s evaluations of the applicant’s Bolting Integrity Program and Selective Leaching of 

Materials Program are documented in SER Section 3.0.3.1.7 and 3.0.3.2.12, respectively. 

While there is no AMR for loss of preload of steel bolting exposed to raw water in the auxiliary 

system, the GALL Report has items for loss of preload of other material bolting managed by the 

Bolting Integrity Program. The staff finds the applicant’s proposal to manage aging using the 

Bolting Integrity Program and Selective Leaching of Material Program acceptable for the 

following reasons:

• The Bolting Integrity Program conducts bolting assembly and maintenance control such 

as application of appropriate gasket alignment, torque, lubricants, and preload and 

inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of 

preload.

• The Selective Leaching of Materials Program conducts visual inspections and 

mechanical examination techniques, such as Brinell hardness testing or destructive 

testing, to ensure that aging will be adequately managed so that the intended functions 

will be maintained consistent with the CLB for the period of extended operation.

In LRA Table 3.3.2-37, the applicant stated that the copper alloy with greater than 15 percent

zinc bolting exposed to air-indoor uncontrolled is being managed for loss of preload by the 

Bolting Integrity Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though copper alloy with greater than 15 percent zinc bolting exposed to air-indoor uncontrolled 

is not specifically addressed in the GALL Report, Table IX.E of the GALL Report states that loss 

of preload can occur independent of environmental conditions because it can be caused by 

thermal or mechanical effects. Additionally, Table IX.C of the GALL Report states that steel 

material is susceptible to a variety of aging effects and mechanisms, including loss of material. 

The staff noted that the applicant addressed loss of material in additional items for each of these 

components; therefore, the aging effect of concern is loss of preload, which is addressed in the 

AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of copper alloy with greater than 

15 percent zinc bolting exposed to air-indoor uncontrolled in the auxiliary system, the GALL 

Report has items for loss of preload of bolting managed by the Bolting Integrity Program. The 

staff finds the applicant’s proposal to manage aging using the Bolting Integrity Program 

acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance 

control, such as application of appropriate gasket alignment, torque, lubricants, and preload. 

The program also inspects for leakage and loose or missing nuts, which verify that the aging 
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effect, loss of preload, will be adequately managed so that the intended functions will be 

maintained consistent with the CLB for the period of extended operation.

In LRA Table 3.3.2-37, the applicant stated that the copper alloy with greater than 15 percent

zinc, steel, and stainless steel bolting exposed to raw water is being managed for loss of 

material by the Buried Piping and Tanks Inspection Program. The AMR item cites generic 

note G.

The staff noted that LRA Table 3.3.2-37 contains items for the same components with an aging 

effect of loss of preload. The staff also noted that the “parameters monitored/inspected” 

program element of GALL Report AMP XI.M18, “Bolting Integrity,” states that, “[s]pecifically, 

bolting for safety-related pressure-retaining components is inspected for leakage, loss of 

material, cracking, and loss of preload/loss of prestress.” The staff further noted that the 

“detection of aging effects” program element of GALL Report AMP XI.M18 states that for 

Classes 1, 2, and 3 bolting, system leakage tests would detect degradation of closure bolting 

due to crack initiation, loss of pre-stress, or loss of material because all three of these aging 

effects would result in joint leakage. The staff noted that in addition to loss of material, copper 

alloy with greater than 15 percent zinc bolting in a raw water environment would be susceptible 

to selective leaching. For these same LRA items, the staff issued RAI 3.3.2-37 requesting that 

the applicant state why it is acceptable to manage selective leaching with a visual inspection 

program (i.e., Bolting Integrity, Buried Piping and Tanks Inspection Program) or provide an AMR 

item, which credits an alternate AMP that includes mechanical examination techniques to 

manage the loss of material due to selective leaching aging effect for copper-alloy (greater than 

15 percent Zn) bolting exposed to raw water in the service water system. The applicant’s 

response and staff evaluation is provided in SER Section 3.3.2.3.37.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. The staff finds that the applicant’s proposal to manage 

aging using the Buried Piping and Tanks Inspection Program is acceptable for the following 

reasons:

• The program includes preventive actions, such as external coatings and wrappings 

installed to industry standard practices, and some systems are protected by a cathodic 

protection system.

• Periodic visual inspections will be performed starting 10 years prior to the period of 

extended operation and extend into both 10-year periods during the period of extended 

operation to ensure that coatings remain intact or uncoated bolting has not degraded.

• Plant-specific operating experience will be used to inform inspection locations.

• Alternatives to direct visual inspection such as pressure tests are capable of detecting 

degradation of the bolted connection.

• Selective leaching is addressed in SER Section 3.3.2.3.37.

In LRA Table 3.3.2-37, the applicant stated that for glass piping elements exposed to 

air-outdoor (external) or condensation (external), there is no aging effect, and no AMP is 

proposed. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and confirmed that no aging effect is 

applicable for this component, material, and environment combination. For the condensation 

environment, GALL Report item V.F-8 states that there are no aging effects for glass exposed to 
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raw water, and raw water is no more severe an environment than condensation. For the 

air-outdoor environment, glass will not exhibit aging effects that will cause its CLB function to 

not be met as evidenced by the widespread successful use of glass in commercial and industrial 

outdoor settings.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.38 Service Water Pump House Air Handling System—Aging Management Evaluation—

LRA Table 3.3.2-38

The staff reviewed LRA Table 3.3.2-38, which summarizes the results of AMR evaluations for 

the service water pump house air handling system component groups.

The staff’s review did not find any items indicating plant-specific Notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with Notes A–E is documented in SER Section 3.3.2.1.

3.3.2.3.39 Spent Fuel Pool Cooling System—Aging Management Evaluation—LRA

Table 3.3.2-39

The staff reviewed LRA Table 3.3.2-39, which summarizes the results of AMR evaluations for 

the spent fuel cooling system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for glass piping elements exposed to air-with borated water leakage 

(external), with no AERM and no recommended AMP citing generic note G, is documented in 

SER Section 3.3.2.3.3.

The staff’s evaluation for elastomer flexible connectors and flexible hose exposed to air with 

borated water leakage (external), which are being managed for hardening and loss of strength 

by the External Surfaces Monitoring Program citing generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for stainless steel heat exchanger components exposed to treated 

borated water, being managed for reduction of heat transfer due to fouling by the Water 

Chemistry Program citing generic note H, is documented in SER Section 3.2.2.3.2.

In LRA Table 3.3.2-39, the applicant stated that the stainless steel bolting exposed to treated 

borated water is being managed for loss of preload by the Bolting Integrity Program. The AMR 

item cites generic note G.
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The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel bolting exposed to treated borated water is not specifically addressed in 

the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur 

independent of environmental conditions because it can be caused by thermal or mechanical 

effects. Additionally, GALL Report, Revision 2, item VII.I.AP-265, states that stainless steel 

bolting exposed to treated borated water is only susceptible to loss of preload. The staff noted 

that the applicant addressed loss of material in additional items for each of these components; 

therefore, the aging effect of concern is loss of preload, which is addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed 

to treated borated water in the auxiliary system, the GALL Report has items for loss of preload 

of other material bolting managed by the Bolting Integrity Program. The staff finds the 

applicant’s proposal to manage aging using the Bolting Integrity Program acceptable because 

the Bolting Integrity Program conducts bolting assembly and maintenance control, such as 

application of appropriate gasket alignment, torque, lubricants, and preload. The program also 

inspects for leakage and loose or missing nuts, which verify that the aging effect, loss of 

preload, will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.40 Switchyard—Aging Management Evaluation—LRA Table 3.3.2-40

The staff reviewed LRA Table 3.3.2-40, which summarizes the results of AMR evaluations for 

the switchyard component groups.

The staff’s evaluation for nickel-alloy components exposed borated water leakage that is not 

subject to an aging effect requiring management, with generic note G, is documented in SER 

Section 3.3.2.3.3.

The staff’s evaluation for stainless steel bolting exposed to air-outdoor, being managed for loss 

of material by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.17.

The staff’s evaluation for stainless steel bolting exposed to air-outdoor, being managed for loss 

of preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.17.

The staff’s evaluation for stainless steel piping and fittings, valve body, expansion joint, filter 

housing, and tanks exposed to air-outdoor (external), which are being managed for loss of 

material by the External Surfaces Monitoring Program citing generic note G, is documented in 

SER Section 3.3.2.3.9.

The staff’s evaluation for copper alloy and copper alloy with greater than 15 percent zinc valve 

body, instrumentation element, nozzle, filter housing, and piping and fittings, and nickel-alloy
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piping and fittings, valve body, expansion joint, and rupture disc exposed to air-outdoor 

(external), which are being managed for loss of material by the External Surfaces Monitoring 

Program citing generic note G, is documented in SER Section 3.3.2.3.15.

The staff’s evaluation for steel bolting exposed to air-outdoor, being managed for loss of preload 

by the Bolting Integrity Program citing generic note G, is documented in SER Section 3.3.2.3.1.

The staff’s evaluation for aluminum flame arrestor and piping and fittings exposed to air-outdoor 

(external), which are being managed for loss of material by the External Surfaces Monitoring 

Program citing generic note G, is documented in SER Section 3.3.2.3.1.

In LRA Table 3.3.2-40, the applicant stated that the aluminum bolting exposed to air-outdoor is 

being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic 

note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though aluminum bolting exposed to air-outdoor is not specifically addressed in the GALL 

Report, Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. The staff 

noted that the applicant addressed loss of material in additional items for each of these 

components; therefore, the aging effect of concern is loss of preload, which is addressed in the 

AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of aluminum bolting exposed to airoutdoor in the auxiliary system, the GALL Report has items for loss of preload of other material 

bolting managed by the Bolting Integrity Program. The staff finds the applicant’s proposal to 

manage aging using the Bolting Integrity Program acceptable because the Bolting Integrity 

Program conducts bolting assembly and maintenance control, such as application of 

appropriate gasket alignment, torque, lubricants, and preload. The program also inspects for 

leakage and loose or missing nuts, which verify that the aging effect, loss of preload, will be 

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

for the period of extended operation.

In LRA Table 3.3.2-40, the applicant stated that the aluminum bolting exposed to air-outdoor is 

being managed for loss of material by the Bolting Integrity Program. The AMR item cites 

generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though aluminum bolting exposed to air-outdoor is not specifically addressed in the GALL 

Report, aluminum has been shown to undergo loss of material due to general, pitting, and 

crevice corrosion in air (ASM Handbook, Corrosion of Aluminum and Aluminum Alloys, 

Corrosion: Materials, Volume 13B). The staff noted that the applicant addressed loss of 

preload in additional items for each of these components; therefore, the aging effect of concern 

is loss of material, which is addressed in the AMR

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of material of aluminum bolting exposed to 

condensation in the auxiliary system, the GALL Report has items for loss of material of other 

material bolting managed by the Bolting Integrity Program. The staff finds the applicant’s 
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proposal to manage aging using the Bolting Integrity Program acceptable because the Bolting 

Integrity Program inspects the bolting through periodic visual inspections to verify that the aging 

effect, loss of material, will be adequately managed so that the intended functions will be 

maintained consistent with the CLB for the period of extended operation.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.41 Valve Stem Leak-off System—Aging Management Evaluation—LRA Table 3.3.2-41

The staff reviewed LRA Table 3.3.2-41, which summarizes the results of AMR evaluations for 

the valve stem leak-off system component groups.

The staff’s review did not find any items indicating plant-specific Notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.3.2.1.

3.3.2.3.42 Vent Gas System—Aging Management Evaluation—LRA Table 3.3.2-42

The staff reviewed LRA Table 3.3.2-42, which summarizes the results of AMR evaluations for 

the vent gas system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.43 Waste Gas System—Aging Management Evaluation—LRA Table 3.3.2-43

The staff reviewed LRA Table 3.3.2-43, which summarizes the results of AMR evaluations for 

the waste gas system component groups.

The staff’s review did not find any items indicating plant-specific Notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.3.2.1.
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3.3.2.3.44 Waste Processing Liquid System—Aging Management Evaluation—LRA

Table 3.3.2-44

The staff reviewed LRA Table 3.3.2-44, which summarizes the results of AMR evaluations for 

the waste processing liquid system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

The staff’s evaluation for steel bolting exposed to condensation, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.19.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.2.3.45 Waste Processing Liquid Drains System—Aging Management Evaluation—LRA

Table 3.3.2-45

The staff reviewed LRA Table 3.3.2-45, which summarizes the results of AMR evaluations for 

the waste processing liquid drains system component groups.

The staff’s evaluation for stainless steel bolting exposed to air-indoor, being managed for loss of 

preload by the Bolting Integrity Program citing generic note G, is documented in SER 

Section 3.3.2.3.2.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.3.3 Conclusion

The staff concludes that 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).

3.4

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

steam and power conversion systems components and component groups of the following 

systems:

Aging Management of Steam and Power Conversion Systems 

• auxiliary steam system

• auxiliary steam condensate system
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• auxiliary steam heating system

• circulating water system

• condensate system

• feedwater system

• main steam system

• steam generator blowdown system

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 

Evaluations for Steam and Power Conversion Systems,” 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 the issuance of the GALL Report.

3.4.2 Staff Evaluation 

The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient information 

to demonstrate that the effects of aging for the steam and power conversion systems 

components and component groups, which are 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 reviewed the 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 audit evaluation are 

documented in SER Section 3.4.2.1.

The staff also reviewed AMRs identified by the applicant as 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 3.4.2.2 acceptance criteria. The 

staff’s audit evaluations are documented in SER Section 3.4.2.2.

The staff reviewed the remaining AMRs identified by the applicant as 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 3.4.2.3.

For SCs, which 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.
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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.

Table 3.4-1. Staff evaluation for steam and power conversion systems components in 

the GALL Report 

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

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

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Yes TLAA Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.1)

Steel piping, piping 

components, and 

piping elements 

exposed to steam

(3.4.1-2)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.2)

Steel heat 

exchanger 

components 

exposed to treated 

water

(3.4.1-3)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.2)

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water

(3.4.1-4)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.2)

Steel heat 

exchanger 

components 

exposed to treated 

water

(3.4.1-5)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.2.9)

Steel and stainless 

steel tanks exposed 

to treated water

(3.4.1-6)

Loss of material 

due to general,

(steel only) pitting,

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.2 and 

3.4.2.2.7)

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil

(3.4.1-7)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Lubricating Oil 

Analysis and

One-Time 

Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.2)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.4.1-8)

Loss of material 

due to general, 

pitting, crevice, 

and MIC, and 

fouling

Plant-specific Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.3) 

Stainless steel and 

copper-alloy heat 

exchanger tubes 

exposed to treated 

water

(3.4.1-9)

Reduction of heat 

transfer due to 

fouling

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.4)

Steel, stainless 

steel, and 

copper-alloy heat 

exchanger tubes 

exposed to 

lubricating oil

(3.4.1-10)

Reduction of heat 

transfer due to 

fouling

Lubricating Oil 

Analysis and

One-Time 

Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.4)

Buried steel piping, 

piping components, 

piping elements, 

and tanks (with or 

without coating or 

wrapping) exposed 

to soil

(3.4.1-11)

Loss of material 

due to general, 

pitting, crevice, 

and MIC

Buried Piping and 

Tanks 

Surveillance 

or

Buried Piping and 

Tanks Inspection

No

Yes

Buried Piping 

and Tanks 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.5)

Steel heat 

exchanger 

components 

exposed to 

lubricating oil

(3.4.1-12)

Loss of material 

due to general, 

pitting, crevice, 

and MIC

Lubricating Oil 

Analysis and

One-Time 

Inspection

Yes Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.2.5)

Stainless steel 

piping, piping 

components, piping 

elements exposed 

to steam

(3.4.1-13)

Cracking due to 

SCC

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.4.2.2.6)

Stainless steel 

piping, piping 

components, piping 

elements, tanks, 

and heat exchanger 

components 

exposed to treated 

water > 140 °F 

(> 60 °C)

(3.4.1-14)

Cracking due to 

SCC

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.6)
Aging Management Review Results

3-399

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Aluminum and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.4.1-15)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.7)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks, and heat 

exchanger 

components 

exposed to treated 

water

(3.4.1-16)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.7)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil

(3.4.1-17)

Loss of material 

due to pitting and 

crevice corrosion

Plant-specific Yes Buried Piping 

and Tanks 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.7)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil

(3.4.1-18)

Loss of material 

due to pitting and 

crevice corrosion

Lubricating Oil 

Analysis and

One-Time 

Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.7)

Stainless steel 

piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to 

lubricating oil

(3.4.1-19)

Loss of material 

due to pitting, 

crevice, and MIC

Lubricating Oil 

Analysis and

One-Time 

Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.2.8)

Steel tanks exposed 

to air-outdoor

(external)

(3.4.1-20)

Loss of material, 

general, pitting, 

and crevice 

corrosion

Aboveground 

Steel Tanks

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.1.1)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.4.1-21)

Cracking due to 

cyclic loading, 

SCC

Bolting Integrity No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.1.1)
Aging Management Review Results

3-400

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel bolting and 

closure bolting 

exposed to air with 

steam or water 

leakage, air-outdoor

(external), or airindoor uncontrolled 

(external)

(3.4.1-22)

Loss of material 

due to general, 

pitting and crevice 

corrosion and loss 

of preload due to 

thermal effects, 

gasket creep, and 

self-loosening

Bolting Integrity No Bolting Integrity

and Buried 

Piping and 

Tanks 

Inspection

Consistent with 

GALL Report (see 

SER 3.4.2.1.2) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

> 140 °F (> 60 °C)

(3.4.1-23)

Cracking due to 

SCC

Closed-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (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 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System

Consistent with 

GALL Report

Stainless steel 

piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.4.1-25)

Loss of material 

due to pitting and 

crevice corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water

System

Consistent with 

GALL Report

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water

(3.4.1-26)

Loss of material 

due to pitting, 

crevice, and 

galvanic corrosion

Closed-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.1.1)

Steel, stainless 

steel, and 

copper-alloy heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water

(3.4.1-27)

Reduction of heat 

transfer due to 

fouling

Closed-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.1.1)
Aging Management Review Results

3-401

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel external 

surfaces exposed to 

air-indoor

uncontrolled 

(external), 

condensation 

(external), or airoutdoor (external)

(3.4.1-28)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring and 

Buried Piping 

and Tanks 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.1.3)

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water

(3.4.1-29)

Wall thinning due 

to flow-accelerated 

corrosion

Flow-Accelerated 

Corrosion

No FlowAccelerated 

Corrosion

Consistent with 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to airoutdoor (internal) or 

condensation 

(internal)

(3.4.1-30)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report

Steel heat 

exchanger 

components 

exposed to raw 

water

(3.4.1-31)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and MIC, 

and fouling

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.4.2.1.4)

Stainless steel and 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.4.1-32)

Loss of material 

due to pitting, 

crevice, and MIC

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.4.2.1.5)

Stainless steel heat 

exchanger 

components 

exposed to raw 

water

(3.4.1-33)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion, and 

fouling

Open-Cycle 

Cooling Water 

System

No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.1.1)

Steel, stainless 

steel, and 

copper-alloy heat 

exchanger tubes 

exposed to raw 

water

(3.4.1-34)

Reduction of heat 

transfer due to 

fouling

Open-Cycle 

Cooling Water 

System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report (see 

SER Section 

3.4.2.1.6)
Aging Management Review Results

3-402

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Copper-alloy

> 15% Zn piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water, raw water, or 

treated water

(3.4.1-35)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Selective 

Leaching of 

Materials

Consistent with 

GALL Report

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil, 

treated water, or raw 

water

(3.4.1-36)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Selective 

Leaching of 

Materials

Consistent with 

GALL Report

Steel, stainless 

steel, and nickelbased alloy piping, 

piping components, 

and piping elements 

exposed to steam

(3.4.1-37)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry No Water 

Chemistry and 

Steam 

Generator Tube 

Integrity 

Consistent with 

GALL Report (see 

SER Section 

3.4.2.1.7)

Steel bolting and 

external surfaces 

exposed to air with 

borated water 

leakage

(3.4.1-38)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion

Consistent with 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to steam

(3.4.1-39)

Cracking due to 

SCC

Water Chemistry No Water 

Chemistry,

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components, 

and One-Time 

Inspection

Consistent with 

GALL Report (see 

SER Section 

3.4.2.1.8)

Glass piping 

elements exposed 

to air, lubricating oil, 

raw water, and 

treated water

(3.4.1-40)

None None No None Consistent with 

GALL Report
Aging Management Review Results

3-403

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Stainless steel, 

copper-alloy, and 

nickel-alloy piping, 

piping components, 

and piping elements 

exposed to airindoor uncontrolled 

(external)

(3.4.1-41)

None None No None Consistent with 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to airindoor controlled 

(external)

(3.4.1-42)

None None No Not applicable Not applicable to 

Seabrook (see 

SER Section 

3.4.2.1.1)

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.4.1-43)

None None No None Consistent with 

GALL Report

Steel, stainless 

steel, aluminum, 

and copper-alloy

piping, piping 

components, and 

piping elements 

exposed to gas

(3.4.1-44)

None None No None Consistent with 

GALL Report

The staff’s review of the steam and power conversion systems components and component 

groups followed 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 Aging Management Review 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:

• Bolting Integrity Program

• Boric Acid Corrosion Program
Aging Management Review Results

3-404

• Buried Piping and Tanks Inspection Program

• Closed-Cycle Cooling Water System Program

• External Surfaces Monitoring Program

• Flow-Accelerated Corrosion Program

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program

• Lubricating Oil Analysis Program

• One-Time Inspection Program

• Open-Cycle Cooling Water System Program

• Selective Leaching of Materials Program

• Water Chemistry Program

LRA Tables 3.4.2-1 through 3.4.2-8 summarize AMRs for the steam and power conversion 

systems components and component groups and indicate AMRs claimed to be consistent with 

the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine if the plant-specific components in these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR item describing how the information in the tables 

aligns with the information in the GALL Report. The staff reviewed those AMRs with Notes A–E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these items to verify consistency with the GALL Report and the validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff reviewed these items to verify consistency with the 

GALL Report and to ensure that it had reviewed and accepted the identified exceptions to the 

GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the 

site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

items to verify consistency with the GALL Report. The staff also determined whether the AMR 

item of the different component applied to the component under review and whether the AMR 

was valid for the site-specific conditions.
Aging Management Review Results

3-405

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 AMP identified in the GALL Report. The staff reviewed 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 exceptions 

to the GALL Report AMPs was reviewed and accepted by the staff. The staff also determined 

whether the AMP identified by the applicant was consistent with the AMP identified in the GALL 

Report and whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff reviewed these items 

to verify consistency with the GALL Report and determined whether the identified AMP would 

manage the aging effect consistent with the AMP identified in the GALL Report and whether the 

AMR was valid for the site-specific conditions.

The staff 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.

3.4.2.1.1 Aging Management Review Results Identified as Not Applicable

In LRA Table 3.4.1, for items 3.4.1-20, 3.4.1-21, 3.4.1-23, 3.4.1-26, 3.4.1-27, and 3.4.1-33, 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.

LRA Table 3.4.1, item 3.4.1-42 addresses steel piping, piping components, and piping elements 

exposed to controlled indoor air (external) and states that there are no aging effects, aging 

mechanisms, or AMPs. The GALL Report, Table VIII, item VIII.I-13 (SP-1) identifies no aging 

effect or aging mechanism and AMP is recommended for this component group exposed to this 

environment. Therefore, the staff finds the applicant’s determination acceptable.

3.4.2.1.2 Loss of Material due to General, Pitting, and Crevice Corrosion

LRA Table 3.4.1, item 3.4.1-22, addresses steel bolting and closure bolting exposed to 

air-indoor, which are being managed for loss of material. In Supplement 2 to the LRA, dated 

November 15, 2010, the applicant stated that it will use the Buried Piping and Tanks Inspection 

Program to manage the effects of aging on bolting exposed to air-indoor uncontrolled (external) 

in the auxiliary steam condensate and auxiliary steam heating systems. The GALL Report 

recommends GALL Report AMP XI.M18, “Bolting Integrity,” to ensure that these aging effects 

are adequately managed. For the bolting AMR results in these two systems, the applicant cited 

generic note E indicating that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M18 recommends Classes 1, 2, and 3 components using ASME Code

Section XI, Tables IWB 2500-1, IWC 2500-1, or IWD 2500-1, which mainly require either visual 

inspection or volumetric examination or both to manage the aging of these components. For 

other pressure-retaining bolting, AMP XI.M18 recommends periodic system walkdowns to 

detect leakage before the leakage becomes excessive. In its review of components associated 

with LRA Table 3.4.1, item 3.4.1-22, for which the applicant cited generic note E, the staff noted 
Aging Management Review Results

3-406

that the Buried Piping and Tanks Inspection Program proposes to manage the aging of steel 

bolting through the use of the following:

• preventive actions, such as external coatings and wrappings installed in accordance with

industry standard practices, and some systems protected by a cathodic protection 

system

• periodic visual inspections, which will be performed starting 10 years prior to the period 

of extended operation and extend into both 10-year periods during the period of 

extended operation to ensure that coatings remain intact or uncoated bolting has not 

degraded

• alternatives to direct visual inspection such as pressure tests, which are capable of 

detecting degradation of the bolted connection

The staff’s evaluation of the applicant’s Inspection of Buried Piping and Tanks Inspection 

Program is documented in SER Section 3.0.3.3.1. In its review of components associated with 

LRA Table 3.4.1, item 3.4.1-22, the staff finds that the applicant’s proposal to manage aging 

using the Buried Piping and Tanks Inspection Program acceptable for the following reasons:

• The program includes preventive actions, such as external coatings and wrappings,

installed in accordance with industry standard practices.

• Periodic visual inspections will be performed starting 10 years prior to the period of 

extended operation and extend into both 10-year periods during the period of extended 

operation to ensure that coatings remain intact or uncoated bolting has not degraded.

• Plant-specific operating experience will be used to inform inspection locations.

• Alternatives to direct visual inspection, such as pressure tests, are capable of detecting 

degradation of the bolted connection.

The staff concludes that the applicant 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).

3.4.2.1.3 Loss of Material Due to General Corrosion

LRA Table 3.4.1, item 3.4.1-28, addresses steel external surfaces exposed to air-indoor 

uncontrolled (external), which are being managed for loss of material due to general corrosion. 

In Supplement 2 to the LRA, the applicant credits the Buried Piping and Tanks Inspection 

Program to manage the aging effect. The GALL Report recommends GALL Report 

AMP XI.M36, “External Surfaces Monitoring,” to ensure that these aging effects are adequately 

managed. The associated AMR items cite generic note E indicating that the AMR item is 

consistent with the GALL Report for material, environment, and aging effect, but a different AMP 

is credited. The applicant stated that the components are in an underground pit with an external 

environment of air-indoor uncontrolled, and the plant-specific Buried Piping and Tanks 

Inspection Program is substituted to manage the aging effect.

GALL Report AMP XI.M36 recommends using visual inspections for general corrosion to 

manage the aging effect of the item. In its review of components associated with LRA 

Table 3.4.1, item 3.4.1-28, for which the applicant cited generic note E, the staff noted that the 

Buried Piping and Tank Inspection Program proposes to manage the aging of piping and 
Aging Management Review Results

3-407

components through the use of periodic visual inspections. The staff also noted that although 

the components are exposed to an external air-indoor uncontrolled environment, they are in an 

underground pit.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. In its review of components associated with 

item 3.4.1-28, the staff finds the applicant’s proposal to manage aging using the Buried Piping 

and Tanks Inspection Program acceptable because it includes visual inspections that can detect 

loss of material on the external surfaces of the components, and the components are in an 

underground pit.

The staff concludes that the applicant 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).

3.4.2.1.4 Loss of Material Due To General, Pitting, Crevice, Galvanic, and 

Microbiologically-Influenced Corrosion and Fouling

LRA Table 3.4.1, item 3.4.1-31, addresses steel heat exchanger components exposed to raw 

water, which are being managed for loss of material due to general, pitting, crevice, galvanic, 

and MIC and fouling. The applicant credits the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program to manage the aging effect. The GALL Report 

recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that 

these aging effects are adequately managed. The associated AMR items cite generic note E 

indicating that the AMR item is consistent with the GALL Report for material, environment, and 

aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, the GALL Report AMP XI.M20 Program 

recommends using chemical treatments whenever the potential for biological fouling species 

exists and also recommends the use of periodic flushing. In its review of components 

associated with LRA Table 3.4.1, item 3.4.1-31, for which the applicant cited generic note E, the 

staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program proposes to manage the aging of steel heat exchanger components 

through the use of periodic inspection on the internal surfaces of components. It was not clear 

to the staff how the opportunistic visual inspections will be able to manage aging of components 

in a raw water system that does not include chemical treatments or surveillances. By letter 

dated January 5, 2011, the staff issued RAI 3.3.2.2-1 requesting that the applicant justify the 

use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Component 

Program, which is only a visual inspection program, to manage aging in the raw water 

environment.

In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 
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function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows for managing of components exposed to raw water, which are not part of the 

open-cycle cooling water system, to be managed with the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Component Program. Therefore, the applicant’s proposal 

complies with the current staff position. The staff’s concern described in RAI 3.3.2.2-1 is 

resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.4.1, item 3.4.1-31, 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 conducts visual inspections 

during periodic system surveillances or maintenance activities when internal surfaces are 

accessible and monitors parameters such as corrosion, corrosion byproducts, coating 

degradation, scale/deposits, pits, and surface discoloration and discontinuities. In addition, the 

staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is acceptable to manage these components exposed to raw water 

because the raw water is associated with potable water and is not part of the open-cycle cooling 

system; therefore, the use of this program is consistent with the current staff position.

The staff concludes that the applicant 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).

3.4.2.1.5 Loss of Material Due To Pitting, Crevice, and Microbiologically-Influenced Corrosion

LRA Table 3.4.1, item 3.4.1-32, addresses stainless steel and copper-alloy piping, piping 

components, and piping elements exposed to raw water, which are being managed for loss of 

material due to pitting, crevice, and MIC. The applicant credits the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging 

effect. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water 

System,” to ensure that these aging effects are adequately managed. The associated AMR 

items cite generic note E indicating that the AMR item is consistent with the GALL Report for 

material, environment, and aging effect, but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, the GALL Report AMP XI.M20 program 

recommends using chemical treatments whenever the potential for biological fouling species 

exists and also recommends the use of periodic flushing. In its review of components 

associated with LRA Table 3.3.1, item 3.4.1-32, for which the applicant cited generic note E, the 

staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program proposes to manage the aging of stainless steel and copper-alloy piping, 

piping components, and piping elements through the use of periodic inspection on the internal 

surfaces of components. It was not clear to the staff how the opportunistic visual inspections 

will be able to manage aging of components in a raw water system that does not include 

chemical treatments or surveillances. By letter dated January 5, 2011, the staff issued 

RAI 3.3.2.2-1 requesting that the applicant justify the use of the Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Component Program, which is only a visual inspection 

program, to manage aging in the raw water environment.
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In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 to the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPS. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows components exposed to raw water, which are not part of the open-cycle

cooling water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Component Program; therefore, the applicant’s proposal complies with the 

current staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.4.1, item 3.4.1-32, 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 conducts visual inspections 

during periodic system surveillances or maintenance activities when internal surfaces are 

accessible and monitors parameters such as corrosion, corrosion byproducts, coating 

degradation, scale/deposits, pits, and surface discoloration and discontinuities. In addition, the 

staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is acceptable to manage these components exposed to raw water 

because the raw water is associated with potable water or radioactive liquid waste drainage 

systems and not part of the open-cycle cooling system. Therefore, the use of this program is 

consistent with the current staff position.

The staff concludes that the applicant 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).

3.4.2.1.6 Reduction of Heat Transfer Due To Fouling

LRA Table 3.4.1, item 3.4.1-34, addresses steel, stainless steel, and copper-alloy heat 

exchanger tubes exposed to raw water, which are being managed for reduction of heat transfer 

due to fouling. The applicant credits the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program to manage the aging effect. The GALL Report recommends 

GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these aging 

effects are adequately managed. The associated AMR items cite generic note E indicating that 

the AMR item is consistent with the GALL Report for material, environment, and aging effect, 

but a different AMP is credited.

GALL Report AMP XI.M20 recommends using condition and performance monitoring programs 

to manage the aging of these items. In addition, the GALL Report AMP XI.M20 program 

recommends using chemical treatments whenever the potential for biological fouling species 

exists and also recommends the use of periodic flushing. In its review of components 

associated with LRA Table 3.4.1, item 3.4.1-34, for which the applicant cited generic note E, the 

staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program proposes to manage the aging of steel, stainless steel, and copper-alloy
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heat exchanger tubes through the use of periodic inspection on the internal surfaces of 

components. It was not clear to the staff how the opportunistic visual inspections will be able to 

manage aging of components in a raw water system that does not include chemical treatments 

or surveillances. By letter dated January 5, 2011, the staff issued RAI 3.3.2.2-1 requesting that 

the applicant justify the use of the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program, which is only a visual inspection program, to manage aging in 

the raw water environment.

In its response dated February 3, 2011, the applicant stated that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program was chosen because the 

internal raw water environments are not covered by any other AMP. The applicant also stated 

that its conclusion to use this AMP is supported by information in Revision 2 of the GALL 

Report, that this program applies to components exposed to any water systems not included in 

the open-cycle cooling water, closed treated water, or fire water AMPs. The applicant further 

stated that its equipment inspections have been successful at identifying and resolving 

corrosion or degradation before it affects the ability of the component to perform its intended 

function. The staff finds the applicant’s response acceptable because the GALL Report, 

Revision 2, allows components exposed to raw water, that not part of the open-cycle cooling 

water system, to be managed with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Component Program. Therefore, the applicant’s proposal complies with the current 

staff position. The staff’s concern described in RAI 3.3.2.2-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. In its review of 

components associated with LRA Table 3.4.1, item 3.4.1-34, 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 conducts visual inspections 

during periodic system surveillances or maintenance activities when internal surfaces are 

accessible and monitors parameters such as corrosion, and corrosion byproducts. In addition, 

the staff finds that the use of Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program is acceptable to manage these components exposed to raw 

water because the raw water is associated with potable water and not part of the open-cycle

cooling system. Therefore, the use of this program is consistent with the current staff position.

The staff concludes that the applicant 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).

3.4.2.1.7 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.4.1, item 3.4.1-37, addresses nickel-alloy steam generator orifices, steam 

generator feedwater inlet rings (J tube), steam generator feedwater nozzles, and steam 

generator tubes exposed to secondary feedwater and steam, which are being managed for loss 

of material due to pitting and crevice corrosion. The LRA credits the Water Chemistry Program 

to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M2, “Water 

Chemistry” to ensure that these aging effects are adequately managed. The associated AMR 

items cite generic note A.
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In its review of components associated with item 3.4.1-37, the staff noted three potential 

inconsistencies between the aging management approach proposed by the applicant for these 

components and the approach contained in, or implied by, the GALL Report.

The first potential inconsistency involves the environment to which the components are 

exposed. For LRA Table 2 items contained in Table 3.1.2-4, which are subordinate to LRA 

Table 3.4.1-37, the environment listed is “secondary feedwater/steam.” The environment for the 

corresponding item in the GALL Report is steam. The GALL Report recommends managing 

loss of material for nickel-alloy components exposed to steam through the use of the GALL 

Report AMP XI.M2, Water Chemistry. Alternatively, the GALL Report recommends managing 

cracking due to SCC for nickel-alloy components exposed to steam and water environments 

through the use of GALL Report AMP XI.M2, “Water Chemistry,” and an inspection-based 

verification program. For piping and pressure boundary components, the Inspection Program is 

typically GALL Report AMP XI.M32, “One Time Inspection,” or GALL Report AMP XI.M1, 

“ASME Section XI, Inservice Inspection.” For steam generator internal components, the 

Inspection Program is typically GALL Report AMP XI.M19, “Steam Generator Tube Integrity.”

This difference in environments appears to make the use of item 3.4.1-37 inappropriate for 

these components.

The second potential inconsistency involves the aging effects proposed for these components. 

Based on LRA Table 3.2.1-4, “Steam Generator,” it appears that the aging effects “cracking” 

and “loss of material” are proposed for nickel-alloy steam generator tubes, while only “loss of 

material” is proposed for the remaining nickel-alloy components. Although the remaining 

components are not specifically addressed in the GALL Report, the staff finds no specific 

distinction that would permit the applicant to propose only “loss of material” for any of the 

components under consideration.

The third potential inconsistency involves the classification of the components. SRP-LR 

Table 3.4-1, ID 37, classifies the components under consideration as “piping, piping 

components, or piping elements.” The staff agrees with the applicant that the orifices and the 

steam generator feedwater nozzle (thermal sleeve) may be appropriately considered piping, 

piping components, and piping elements. The staff finds that the steam generator feedwater 

inlet ring (J tube) and the steam generator tubes are more appropriately classified as steam 

generator internal components. This classification appears to make the use of item 3.4.1-37 

inappropriate for the J tubes and the steam generator tubes.

To address these potential inconsistencies in aging management approach, the staff issued 

RAI 3.4.1-37-1 by letter dated January 5, 2011, requesting that the applicant do the following: 

(a) propose to manage aging of these components using water chemistry and an 

appropriate verification AMP, as indicated by the GALL Report, for the management of 

aging in a secondary feedwater or steam environment or justify why the use of a 

verification AMP is either inconsistent with the GALL Report or technically unnecessary

(b) justify why is it unnecessary to consider both the aging effects “loss of material” and 

“cracking” for each of the components under consideration

(c) classify the steam generator feedwater inlet ring (J tube) and the steam generator tubes 

as steam generator internal components (making the appropriate verification AMP the 

Steam Generator Tube Integrity Program) or justify why these components should be 

considered piping, piping components, or piping elements, as proposed by item 3.4.1-37

In its response dated February 3, 2011, the applicant took the following actions:
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(a) redesignated the steam generator feedwater inlet ring (J tube) and steam generator 

tubes as steam generator components, as opposed to piping, and proposed to manage 

the aging associated with these components through the use of its Water Chemistry and

Steam Generator Tube Integrity Programs

(b) added the aging effect “cracking” for components as necessary to ensure that both the 

aging effects “loss of material” and “cracking” were managed for each component under 

consideration

(c) acknowledged that the “steam” environment described in SRP-LR Table 3.4.1, ID 37, is 

inconsistent with the secondary feedwater or steam environment to which these 

components are exposed

As a result of this acknowledgement, the applicant changed the designation of these items from 

SRP-LR Table 3.4.1, ID 37, generic note A, to “not consistent with the GALL Report,” generic 

note H.

The staff reviewed each of these actions with respect to its consistency with the GALL Report, 

its sufficiency to manage aging and its responsiveness to the RAI. The staff determined the 

following:

(a) The applicant’s redesignation of the inlet feedwater ring and steam generator tubes—

from being consistent with SRP-LR Table 3.1.4, ID 37, to being not consistent with the 

GALL Report—is acceptable because it appropriately identifies these components as 

being internal to the steam generator. The applicant’s use of its Water Chemistry and 

Steam Generator Tube Integrity AMPs to manage aging is acceptable because these 

programs are generally recommended by the GALL Report for managing the aging of 

steam generator internal components and will adequately manage the aging of these 

components.

(b) The applicant’s redesignation of the feedwater nozzle thermal sleeve and orifice—from 

being consistent with SRP-LR Table 3.1.4, ID 37, to being not consistent with the GALL 

Report—may not be acceptable. It appears to the staff that the components, materials,

and aging effects currently under consideration are consistent with SRP-LR Table 3.1-1,

ID 84. The applicant’s use of its Water Chemistry AMP to manage this aging also may 

be not acceptable as SRP-LR Table 3.1-1, ID 84, recommends that aging be managed 

through the use of GALL Report AMPS XI.M2, “Water Chemistry,” and either 

AMP XI.M32, “One Time Inspection,” or AMP XI.M1, “ASME Section XI, Inservice 

Inspection.” The staff notes that, in its response to RAI 3.4.1-37-1, the applicant stated 

that these components were not available for inspection. The staff also notes that these 

components have been addressed in many recent license renewal SERs. While there 

have been differences in the approaches to the management of aging of these 

components from plant to plant, in each case, the SER indicates that the accepted 

method of aging management involves the use of an AMP to manage water chemistry 

and an AMP to perform at least a one-time inspection to verify the efficacy of the Water 

Chemistry Program. This indicates to the staff that Water Chemistry and Inspection 

Programs are necessary for adequate aging management and that these components 

are generally inspectable.

(c) The applicant’s addition of the aging effect “cracking” for components as necessary to 

ensure that both the aging effects “loss of material” and “cracking” were managed for 

each component under consideration is acceptable because the applicant has now 
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identified all the reasonable aging effects for these components and because the 

programs proposed to manage this aging are adequate.

(d) In combination, the applicant’s actions (a) and (b) are fully responsive (although not fully 

acceptable) to RAI issues (a) and (c). The applicant’s action (b) is fully responsive (and 

fully acceptable) to RAI issue (b).

To resolve the issue addressed in Subparagraph (b) above, the staff issued RAI 3.4.1-37-2 by 

letter dated March 7, 2011, requesting that the applicant do the following:

• demonstrate why the aging management guidance provided by SRP-LR Table 3.4-1,

ID 84, need not be followed

• demonstrate why the components under consideration are inspectable at other plants 

and not at the applicant’s plant

• propose to manage aging of these components in a manner consistent with or 

equivalent to SRP-LR Table 3.4-1, ID 84

In its response dated April 5, 2011, the applicant did the following: 

• stated that it has recirculating steam generators and, therefore, chose not to use SRPLR Table 3.1-1, ID 84, for the components under consideration because this item refers 

only to item R-36, which appears only in GALL Report Table IV.D2, which addresses 

only once through steam generators

• described the construction and location of the steam generator steam flow restricting 

orifice and concluded that, due to the location of the component and the lack of 

manways or other access points in the vicinity of the component, inspection of the 

component by either direct or remote means was not practical without a plant 

modification

• described the construction and location of the steam generator feedwater nozzle thermal 

sleeve and concluded direct visual inspection of this component was not possible but 

remote visual inspection was possible via the feedwater ring J tube opening

• proposed that, due to the lack of industry experience of aging effects associated with the 

steam generator steam flow restricting orifice and the absence of a recommendation to 

inspect these components in the EPRI Steam Generator Integrity Assessment 

Guidelines (EPRI 1012987, Revision 2), the use of the Water Chemistry Program AMP 

was sufficient to manage aging of this component without the use of the One-Time 

Inspection AMP

• proposed to include the steam generator feedwater nozzle thermal sleeve in its Steam 

Generator Tube Integrity Program to verify the effectiveness of its Water Chemistry 

Program despite the lack of specific plant and industry operating experience showing a 

need to inspect this component or an EPRI recommendation to inspect the component

The staff reviewed each of these actions with respect to its consistency with the GALL Report, 

its sufficiency to manage aging, and its responsiveness to the RAI. The agrees with the 

applicant’s observation that SRP-LR Table 3.1-1, ID 84, applies specifically only to once through 

steam generators (Table IV.D2). The staff, therefore, accepts the applicant’s use of generic 

note H as opposed to using Table 3.1-1, ID 84, generic note A. Given that components meeting 

the general criteria of Table 3.1-1, ID 84, are present in both once through and recirculating 

steam generators, the staff will consider inclusion of this AMR item in both Tables IV.D2 and D1 
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in a future revision of the GALL Report. The staff finds no fault with the applicant’s description 

of the steam generator steam flow restricting orifice. The staff agrees that, absent manways or 

other means of access in the vicinity of this component, inspection is not reasonably possible at 

this plant. The staff finds no fault with the applicant’s description of the steam generator 

feedwater nozzle thermal sleeve. The staff agrees that direct inspection of this component is 

not possible but that remote inspection should be possible. Given the lack of specific plant or 

industry operating experience, which points directly to the need to inspect the steam generator 

steam flow restricting orifice and the significance of the modifications to the plant which would 

be necessary to inspect this component, the staff agrees with the applicant’s proposal to 

manage the aging of this component solely through the use of its Water Chemistry Program. 

Lastly, the staff agrees with the applicant’s proposal to manage the aging of its steam generator 

feedwater nozzle thermal sleeve through the use of its Water Chemistry and Steam Generator 

Tube Integrity Programs. The Steam Generator Tube Integrity Program contains provisions for 

inspections, which will permit the verification of the effectiveness of the Water Chemistry 

Program in preventing component degradation.

The staff finds that the applicant has been fully responsive to the questions raised in the RAIs 

and that the applicant’s proposals included in their RAI responses are technically sufficient to 

accomplish their intended goals. The staff’s concerns described in RAIs 3.4.1-37-1 and 

3.4.1-37-2 are resolved.

The staff’s evaluation of the applicant’s Water Chemistry Program and Steam Generator Tube 

Integrity Program are documented in SER Sections 3.0.3.1.2 and 3.0.3.2.2, respectively. In its 

review of components associated with LRA Table 3.4.1, item 3.4.1-37, the staff finds the 

applicant’s proposal to manage aging using the Water Chemistry Program and Steam 

Generator Tube Integrity Program acceptable because the Water Chemistry Program 

establishes the plant water chemistry control parameters and their limits to mitigate the 

environmental effect on the aging and establishes corrective actions if the parameters exceed 

the limits so that the environmental effect on the aging is minimized. Also, the Steam Generator 

Tube Integrity Program contains provisions for inspections, which will permit the verification of 

the effectiveness of the Water Chemistry Program in preventing component degradation. 

Therefore, the use of these programs are consistent with the current staff position.

The staff concludes that the applicant 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).

3.4.2.1.8 Cracking due to Stress Corrosion Cracking

In LRA Table 3.4.1, item 3.4.1-39, addresses stainless steel piping, piping components, and 

piping elements exposed to steam, which are being managed for cracking due to SCC. The 

LRA credits the Water Chemistry Program and Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program to manage the aging effect. The GALL Report 

recommends GALL Report AMP XI.M2, “Water Chemistry,” to ensure that these aging effects 

are adequately managed. The associated AMR items cite generic Notes A, C, and E.

GALL Report AMP XI.M2 recommends using water chemistry control to mitigate the aging of 

these items. In its review of components associated with item 3.4.1-39, for which the applicant 

cited generic note E, the staff noted that LRA Table 3.4.2-3 indicates that the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program is proposed to 
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manage cracking due SCC of stainless steel heat exchanger components, valve body, and filter 

elements. The staff also noted that LRA Section B.2.1.25 describes that the applicant’s 

program uses inspections of opportunity and that the inspection techniques used to detect this 

aging effect of the components will be either visual inspection with a magnified resolution, as 

described in 10 CFR 50.55a(b)(2)(xxi)(A), or an ultrasonic inspection method. By letter dated 

January 5, 2011, the staff issued RAI 3.4.2.3-01 requesting that the applicant clarify why the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, 

which relies on inspections of opportunity without water chemistry control, is adequate to detect 

and manage cracking due to SCC in the stainless steel components exposed to steam.

In its response dated February 3, 2011, the applicant stated that the makeup water for the 

auxiliary steam heating system in LRA Table 3.4.2-3 is potable water obtained from the Town of 

Seabrook, which is not the same steam environment listed in items 3.4.1-37 and 3.4.1-39. The 

applicant also stated that the PWR secondary Plant Water Chemistry Program is not applicable 

to potable water; therefore, the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program is a more appropriate program for managing the aging of these 

components. The applicant further stated that the applicant will provide for a one-time 

inspection of the stainless steel components addressed in Table 3.4.2-3, and any evidence of 

cracking will be documented and evaluated under the Corrective Action Program. In addition, 

the applicant stated that the LRA has been revised to credit the One-Time Inspection Program 

that will verify that cracking does not occur. The applicant also revised the generic note for 

these components from E to G indicating that, for this component and material, the environment 

is not in the GALL Report.

Based on its review, the staff finds the applicant’s response to RAI 3.4.2.3-01 acceptable 

because the applicant clarified that the source of the makeup water is potable water, to which 

the Water Chemistry Program is not applicable. The staff also finds that LRA Tables 3.4.2-3 

and 3.4.1 and LRA Section B.2.1.20 have been revised to implement the One-Time Inspection 

Program, which will confirm that cracking does not occur. The staff also finds that the One-Time 

Inspection Program is adequate to confirm the effectiveness of the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program for managing cracking due 

to SCC of the components. The staff’s concern described in RAI 3.4.2.3-01 is resolved.

The staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program and One-Time Inspection Program, and the staff’s evaluations are 

documented in SER Sections 3.0.3.2.15 and 3.0.3.1.8, respectively. In its review, the staff finds 

the applicant’s use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program and One-Time Inspection Program acceptable to manage the aging 

effect for the following reasons:

• The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program includes periodic inspections to detect cracking using either visual inspection 

with a magnified resolution, as described in 10 CFR 50.55a (b)(2)(xxi)(A), or an 

ultrasonic inspection method, which is adequate to detect the aging effect.

• The source of water, which is converted to steam, is potable water, to which the Water 

Chemistry Program is not applicable.

• The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program, with periodic inspections, is also augmented by the One-Time Inspection 

Program to confirm that cracking does not occur.
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• Any evidence of cracking will be documented and evaluated under the Corrective Action 

Program, which is adequate to manage the aging effect.

In its review of components associated with item 3.4.1-39, for which the applicant cited generic 

note C, the staff noted that the GALL Report does not contain a specific AMR item for cracking 

due to stress corrosion of stainless steel heat exchanger components exposed to steam. The 

staff also noted that for heat exchanger components of other materials and environments, the 

GALL Report typically recommends a Water Chemistry Program in conjunction with an 

Inspection Program that verifies the effectiveness of the Water Chemistry Program to manage 

cracking due to SCC.

In LRA Tables 3.3.2-15 and 3.4.2-5, the applicant indicated that cracking due to SCC is 

applicable for stainless steel heat exchanger components (FP-E-46 and FP-E-47 and

1-CO-E-111 components, respectively) exposed to steam and that the applicant’s Water 

Chemistry Program is credited to manage the aging effect in these components associated with 

LRA item 3.4.1-39. By letter dated January 5, 2011, the staff issued RAI 3.3.2.15-01 asking the 

applicant to justify why the Water Chemistry Program alone is adequate to manage cracking 

due to SCC in these heat exchanger components exposed to steam.

In its response dated February 3, 2011, the applicant stated that the external steam 

environment of the heat exchanger tubes in CO-E-111 is steam supplied from the main steam 

system, which is subject to the Water Chemistry Program; therefore, the selection of Water 

Chemistry Program as the AMP is appropriate. The applicant also stated that, in addition to the 

Water Chemistry Program, the heat exchanger tubes for CO-E-111 will be inspected under the 

One-Time Inspection Program to verify that the cracking does not occur and that any evidence 

of cracking will be documented and evaluated under the Corrective Action Program. The staff 

finds that this portion of the applicant’s response regarding the aging management of the heat 

exchanger components (1-CO-E-111 tubes) acceptable because the applicant revised the LRA 

to implement the One-Time Inspection Program that will confirm that cracking due to SCC does 

not occur and that the Water Chemistry Program is effective to manage the aging effect.

In its response, the applicant also stated that the steam environment listed in Table 3.3.2-15 for 

the other heat exchangers (FP-E-46 and FP-E-47) is potable water converted to steam, which is 

not the same steam environment listed in item 3.4.1-39. The applicant further stated that the 

shell side steam environment for the two heat exchangers comes from the auxiliary steam 

heating system, which uses potable water. In addition, the applicant stated that the potable 

water is not subject to the Water Chemistry Program and that the Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components Program is a more appropriate program to 

manage the aging of these components. In addition, the applicant stated that it has preventive 

maintenance activities already in place to clean and inspect the external surface of the heat 

exchanger tubes at a frequency of approximately every 4 years and that, if evidence of cracking 

is found, it will be documented and evaluated under the Corrective Action Program. The 

applicant stated that, as part of the response to this RAI, the other components of these two 

heat exchangers (FP-E-46 and FP-E-47), which were inadvertently assigned to the Water 

Chemistry Program, are being reassigned to the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program. The applicant stated that the generic 

note for these components (FP-E-46 and FP-E-47 components) was revised from C to G, 

indicating that the environment is not in the GALL Report for this component and material.

Based on its review, the staff finds the applicant’s response to this portion of RAI 3.3.2.15-01 

acceptable because the applicant clarified that the Water Chemistry Program is not applicable 
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to the components (FP-E-46 and FP-E-47) exposed to potable water. Additionally, the applicant 

revised the LRA to credit its Inspection of Internal Surfaces in Miscellaneous Piping Program, 

which includes periodic inspection capable of detecting cracking due to SCC. The staff also 

finds the applicant’s response acceptable because the applicant revised the LRA to manage the 

aging effect of the heat exchanger components (1-CO-E-111 tubes) exposed to steam supplied 

from the main steam system using the Water Chemistry Program, augmented by the One-Time 

Inspection Program, which will confirm the effectiveness of the Water Chemistry Program. The 

staff’s concern described in RAI 3.3.2.15-01 is resolved.

The staff reviewed the Water Chemistry Program, One-Time Inspection Program, and 

Inspection of Internal Surfaces in Miscellaneous Piping Program, and the staff’s evaluations are 

documented in SER Sections 3.0.3.1.2, 3.0.3.1.8, and 3.0.3.2.15, respectively. In its review, the 

staff finds the applicant’s use of the Water Chemistry Program, augmented by the One-Time 

Inspection of Internal Surfaces in Miscellaneous Piping Program, acceptable to manage the 

aging effect for the following reasons: 

• The Water Chemistry Program establishes the plant water chemistry control parameters 

and their limits to mitigate the environmental effect on the aging.

• The Water Chemistry Program also takes corrective actions if the parameters exceed 

the limits so that the environmental effect on the aging is minimized.

• The One-Time Inspection Program includes a one-time inspection of selected 

components to confirm the effectiveness of the Water Chemistry Program for managing 

cracking due to SCC in a manner consistent with the GALL Report and SRP-LR.

• The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program includes periodic inspections, which are capable to detect cracking due to 

SCC, and if evidence of cracking is found, it will be documented and evaluated under the 

Corrective Action Program.

The staff evaluated the applicant’s claim of consistency with the GALL Report. 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 indeed 

consistent with its AMRs. Therefore, the staff concludes that the applicant 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 Aging Management Review 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 component 

groups and provides information concerning how it will manage the following aging effects:

• cumulative fatigue damage

• loss of material due to general, pitting, and crevice corrosion

• loss of material due to general, pitting, crevice, and MIC and fouling

• reduction of heat transfer due to fouling

• loss of material due to general, pitting, crevice, and MIC
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• cracking due to SCC

• loss of material due to pitting and crevice corrosion

• loss of material due to pitting, crevice, and MIC

• loss of material due to general, pitting, crevice, and galvanic 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 

reviewed the applicant’s evaluation to determine if 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 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 

10 CFR 54.3. These TLAAs are to be evaluated in accordance with the TLAA acceptance 

criteria requirements in 10 CFR 54.21(c)(1) and in accordance with SRP-LR Section 4.3, “Metal 

Fatigue Analysis.” The staff reviewed the applicant’s AMR items and finds that the AMR results 

are consistent with the recommendations of the GALL Report and SRP-LR for managing 

cumulative fatigue damage in steel piping, piping components, and piping elements exposed to 

steam or treated water.

Based on its review, the staff concludes that the applicant 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 the applicant 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 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.4.2.2.2 against the following criteria in SRP-LR 

Section 3.4.2.2.2:

(1) LRA Section 3.4.2.2.2.1, is associated with LRA Table 3.4.1, items 3.4.1-2, 3.4.1-3, 

3.4.1-4, and 3.4.1-6 (steel only). It addresses steel piping, piping components, piping 

elements, tanks, and heat exchanger components exposed to treated water, and steel 

piping, piping components, piping elements exposed to steam, which are being 

managed for loss of material due to general, pitting, and crevice corrosion by the Water 

Chemistry and One-Time Inspection Programs. The criteria in SRP-LR 
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Section 3.4.2.2.2, item 1, state that loss of material due to general, pitting, and crevice 

corrosion could occur for steel piping, piping components, piping elements, tanks, and 

heat exchanger components exposed to treated water and in steel piping, piping 

components, and piping elements exposed to steam. The SRP-LR also states that the 

existing AMP relies on monitoring and control of water chemistry to mitigate degradation,

and a one-time inspection of select components at susceptible locations is an 

acceptable method to determine if an aging effect does not occur or progressing very 

slowly such that the component’s intended function will be maintained during the period 

of extended operation. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that loss of material due to general, pitting, and crevice corrosion of 

steel piping, tanks, and heat exchanger components exposed to treated water, and steel 

piping, piping components, piping elements exposed to steam will be managed by the 

Water Chemistry and One-Time Inspection Programs.

The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its 

review of components associated with items 3.4.1-2, 3.4.1-3, 3.4.1-4, and 3.4.1-6, the 

staff finds that the applicant met the further evaluation criteria, and the applicant’s 

proposal to manage aging using the Water Chemistry and One-Time Inspection 

Programs is acceptable because the Water Chemistry Program uses chemical sampling 

and corrective actions to ensure that impurities are minimized to reduce aging due to 

loss of material. Additionally, the One-Time Inspection Program will perform a one-time 

inspection of select components to verify the effectiveness of the Water Chemistry 

Program for managing the aging effects of loss of material.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2, item 1, criteria. For those items that apply to LRA 

Section 3.4.2.2.2.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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 3.4.2.2.2.2, referenced by LRA Table 3.4.1, item 3.4.1-7, addresses steel 

piping, piping components, and piping elements exposed to lubricating oil, which are 

being managed for loss of material due to general, pitting, and crevice corrosion by the 

Lubricating Oil Analysis and One-Time Inspection Programs. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that the One-Time Inspection 

Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program 

to manage loss of material through examination of susceptible locations in steel piping, 

piping components, and piping elements exposed to lubricating oil in the feedwater and 

main steam systems.

The staff reviewed LRA Section 3.4.2.2.2.2 against the criteria in SRP-LR 

Section 3.4.2.2.2, item 2, which state that loss of material due to general, pitting, and 

crevice corrosion could occur for steel piping, piping components, and piping elements 

exposed to lubricating oil. The SRP-LR also states that the existing AMP relies on the 

periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

The SRP-LR further states that control of lube oil contaminants may not always have 

been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil 

contaminant control should be confirmed to ensure that corrosion does not occur. The 
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SRP-LR also states that the GALL Report recommends further evaluation of programs to 

manage corrosion to verify the effectiveness of the Lubricating Oil Analysis Program for 

which a one-time inspection of selected components at susceptible locations is an 

acceptable method to ensure that corrosion does not occur and that the component’s 

intended function will be maintained during the period of extended operation.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.4.1-7, the staff finds the 

applicant’s proposal to manage aging using the One-Time Inspection Program to verify 

the effectiveness of the Lubricating Oil Analysis Program acceptable because the 

Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Time Inspection Program will be used to 

examine stainless steel piping, piping components, and piping elements to verify the 

effectiveness of the Lubricating Oil Analysis Program. This satisfies the acceptance 

criteria in SRP-LR Section 3.4.2.2.2, item 2; therefore, the applicant’s AMR is consistent 

with the GALL Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2, item 2, criteria. For those items that apply to LRA 

Section 3.4.2.2.2.2, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

3.4.2.2.3 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion and Fouling 

LRA Section 3.4.2.2.3 is associated with LRA Table 3.4.1, item 3.4.1-8, and addresses steel 

piping, piping components, and piping elements exposed to raw water, which are being 

managed for loss of material due to general, pitting, crevice, galvanic, and MIC and fouling by 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. 

The criteria in SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, 

crevice, and MIC and fouling could occur in steel piping, piping components, and piping 

elements exposed to raw water. The SRP-LR also states that the GALL Report recommends 

further evaluation of a plant-specific AMP to ensure that the aging effect is adequately 

managed. The SRP-LR further states that the acceptance criteria for the further evaluation of 

the plant-specific AMP are described in BTP RSLB-1. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that loss of material due to pitting, crevice, galvanic, 

and MIC in steel piping components and tanks exposed to raw water will be managed by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

staff noted that LRA Table 3.4-1, item 3.4.1-8, states that fouling was excluded as an aging 

mechanism since the raw water is associated with potable domestic water from the Town of 

Seabrook.

The applicant stated that for item 3.4.1-8, the applicability is limited to steel auxiliary steam 

condensate and auxiliary steam heating system piping components and tanks exposed to raw 

water. The staff noted that a search of LRA Section 3.4 and the applicant’s UFSAR confirmed 

that no in-scope piping, piping components, piping elements, and tanks exposed to raw water 

are present in the steam and power conversion systems, except for those listed in LRA 

Section 3.4.2.2.3 and item 3.4.1-8.
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In its review of components associated with item 3.4.1-8, the staff noted that the applicant’s 

proposed program to manage steel and gray cast iron components in raw water is only an 

Opportunistic Inspection Program and does not include chemical treatments to eliminate 

biological activity. By letter dated January 5, 2011, the staff issued RAI 3.4.2.2-1 requesting 

that the applicant justify how loss of material in steel and gray cast iron components exposed to 

raw water will be managed in the absence of a preventive program with chemical sampling and 

corrective actions, in light of the potential infrequent inspections that may occur due to 

managing these components with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program.

In its response dated February 3, 2011, the applicant stated that the makeup water to the 

auxiliary steam condensate and auxiliary steam heating systems is potable water or drinking 

water, which is not considered treated water as it does not begin as demineralized water and 

receive any other chemical treatment; therefore, it is considered a raw water environment. The 

applicant also stated that the Town of Seabrook’s drinking water is not covered by the 

Open-Cycle Cooling Water Program since the applicant’s open-cycle cooling water source is the 

Atlantic Ocean, and the program focuses on aging management of components in the ocean 

water environment. The applicant further stated that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program is the appropriate AMP for this 

environment and crediting this AMP is consistent with item VII.E5.AP-270 of the GALL Report,

Revision 2, for which GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” is recommended to manage loss of material 

due to general, pitting, and crevice corrosion for steel and stainless steel piping, piping 

components, and piping elements exposed to raw water.

The staff finds the applicant’s response acceptable because potable water is neither treated 

water nor raw water from the ultimate heat sink. Additionally, the GALL Report identifies the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as 

appropriate for an internal environment (such as indoor uncontrolled air, condensation, and 

steam) that is not included in other AMPs for loss of material. Also, the AMP includes periodic 

visual inspections with a frequency that is informed by inspection results to provide reasonable 

assurance that component degradation will be detected prior to loss of intended function. The 

staff’s concern described in RAI 3.4.2.2-1 is resolved.

The staff also noted that fouling was excluded as an aging mechanism. By letter dated 

January 21, 2011, the staff also issued RAI 3.4.2.2-2 requesting that the applicant justify why 

fouling in steel and gray cast iron components exposed to raw water was excluded as an aging 

mechanism.

In its response dated February 18, 2011, the applicant stated that fouling and loss of material 

due to fouling is not expected to occur in the potable water or drinking water. The applicant also 

stated that the levels of total dissolved solids in the Town of Seabrook’s drinking water are 

periodically monitored, which are less than the maximum total dissolved solids level 

recommended by the Environmental Protection Agency. The applicant further stated that a 

review of the plant operating experience showed no evidence of fouling and loss of material due 

to fouling in the portable water environment.

The staff finds the applicant’s response acceptable because the inspections to be performed by 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

for loss of material due to corrosion are the same as those to identify loss of material due to 

fouling. The plant operating experience supports the applicant’s determination that loss of 
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material due to fouling in steel and gray cast iron components exposed to portable water is not a 

potential aging mechanism. The staff’s concern described in RAI 3.4.2.2-2 is resolved.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

that the applicant met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is acceptable because the program uses periodic visual inspections 

during maintenance or surveillance activities to identify the presence of corrosion by inspecting 

for discoloration and surface irregularities such as rust, scale or deposits, and surface pitting. 

These visual inspections can detect the aging effect of loss of material prior to the loss of 

component-intended function, and inspection results will be reviewed to ensure that the number 

of locations and inspection intervals are appropriate.

Based on the program identified above, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.4.2.2.3 criteria. For those items that apply to LRA Section 3.4.2.2.3, the staff 

determined that the LRA is consistent with the GALL Report, and the applicant 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).

3.4.2.2.4 Reduction of Heat Transfer Due to Fouling 

The staff reviewed LRA Section 3.4.2.2.4 against the following criteria in SRP-LR 

Section 3.4.2.2.4:

(1) LRA Section 3.4.2.2.4.1, is associated with LRA Table 3.4.1, item 3.4.1-9, and 

addresses stainless steel and copper heat exchanger tubes exposed to treated water, 

which are being managed for reduction of heat transfer due to fouling by the Water 

Chemistry and the One-Time Inspection Programs. The criteria in SRP-LR 

Section 3.4.2.2.4, item 1, state that reduction of heat transfer due to fouling may occur 

for stainless steel and copper-alloy heat exchanger tubes exposed to treated water. The 

SRP-LR also states that although the existing AMP relies on control of water chemistry 

to manage this aging effect, the control of water chemistry may not always have been 

adequate to preclude fouling. The SRP-LR recommends that the effectiveness of the 

Water Chemistry Control Program be confirmed and states that a one-time inspection is 

an acceptable verification method.

The staff’s evaluations of the applicant’s Water Chemistry and the One-Time Inspection 

Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its 

review of components associated with item 3.4.1-9, the staff finds that the applicant met 

the further evaluation criteria. Additionally, the applicant’s proposal to manage aging 

using the specified programs is acceptable because the Water Chemistry Program 

includes control of detrimental contaminants below the levels known to cause cracking, 

and the One-Time Inspection Program will verify the effectiveness of the chemistry 

controls by inspecting a sample of similar components exposed to the same 

environment.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.4, item 1, criteria. For those items that apply to LRA 

Section 3.4.2.2.4.1, the staff determined that the LRA is consistent with the GALL 
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Report, and the applicant 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 3.4.2.2.4.2, is associated with LRA Table 3.4.1, item 3.4.1-10, and 

addresses steel, stainless steel and copper-alloy heat exchanger tubes exposed to 

lubricating oil, which are being managed for reduction of heat transfer due to fouling by 

the Lubricating Oil Analysis and One-Time Inspection Programs. The criteria in SRP-LR 

Section 3.4.2.2.4, item 2, state that reduction of heat transfer due to fouling may occur in 

steel, stainless steel, and copper-alloy heat exchanger tubes exposed to lubricating oil. 

The SRP-LR also states that existing AMP controls lube oil chemistry to mitigate this 

aging effect, and the effectiveness should be confirmed because the control of lube oil 

chemistry may not be fully effective in precluding fouling. The SRP-LR further states 

that a one-time inspection of selected components at susceptible locations is an 

acceptable method to verify the program’s effectiveness. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that it will implement the One-Time 

Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program to 

manage loss of heat transfer due to fouling in the feedwater system.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.4.1-10, the staff finds 

that the applicant met the further review criteria. Additionally, the applicant’s proposal to 

manage aging using the specified AMPs acceptable because the Lubricating Oil 

Analysis Program includes periodic sampling and analysis of lubricating oil to maintain 

contaminants within acceptable limits, and the One-Time Inspection Program will verify 

the effectiveness of the Lubricating Oil Analysis Program to manage this aging effect.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.4, item 2, criteria. For those items that apply to LRA 

Section 3.4.2.2.4.2, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

3.4.2.2.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

The staff reviewed LRA Section 3.4.2.2.5 against the following criteria in SRP-LR 

Section 3.4.2.2.5:

(1) LRA Section 3.4.2.2.5.1 is associated with LRA Table 3.4.1, item 3.4.1-11, and 

addresses buried steel (with or without coating or wrapping) piping, piping components, 

piping elements, and tanks exposed to soil, which are being managed for loss of 

material due to general, pitting, crevice, and MIC by the Buried Piping and Tanks 

Inspection Program. The criteria in SRP-LR Section 3.4.2.2.5, item 1, state that the loss 

of material due to general, pitting, crevice, and MIC could occur for buried steel (with or 

without coating or wrapping) piping, piping components, piping elements, and tanks 

exposed to soil environment. The SRP-LR also states that the Buried Piping and Tanks 

Inspection Program relies on industry practice, frequency of pipe excavation, and 

operating experience to manage the effects of loss of material aging effect. The 
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applicant addressed the further evaluation criteria of the SRP-LR by stating that the 

Buried Piping and Tanks Inspection Program will use external coatings and wrappings 

on buried piping as well as periodic inspections to determine loss of material. The staff 

noted that the applicant stated, in LRA Section B.2.1-22 under the “detection of aging 

effects” program element, that inspections locations would be, in part, based on areas 

with a history of corrosion problems.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. In its review of components associated with LRA 

Table 3.4.1, item 3.4.1-11, the staff finds that the applicant met the further evaluation 

criteria, and the applicant’s proposal to manage aging using the Buried Piping and Tanks 

Inspection Program is acceptable for the following reasons:

• The program includes preventive actions, such as external coatings and 

wrappings installed to industry standard practices and backfill that will not 

damage the piping or coatings, and some systems are protected by a 

cathodic protection system.

• Periodic visual inspections will be performed starting 10 years prior to the 

period of extended operation and extend into both 10-year periods during 

the period of extended operation to ensure that coatings remain intact or 

uncoated piping has not degraded.

• Plant-specific operating experience will be used to inform inspection 

locations.

• Alternatives to direct visual inspection such as pressure tests or ultrasonic 

inspections are capable of detecting piping degradation.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.5, item 1, criteria. For those items that apply to LRA 

Section 3.4.2.2.5.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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 3.4.2.2.5.2, is associated with LRA Table 3.4.1, item 3.4.1-12, and 

addresses loss of material due to general, pitting, crevice, and MIC in steel heat 

exchanger components exposed to lubricating oil. The applicant stated that this item is 

not applicable because there are no steel heat exchanger components exposed to 

lubricating oil in the steam and power conversion systems. The staff reviewed LRA 

Sections 2.3.4 and 3.4, and the UFSAR, and confirmed that no in-scope steel heat 

exchanger components exposed to lubricating oil are present in the steam and power 

conversion systems; therefore, it finds the applicant’s claim acceptable.

Based on the above, the staff concludes that SRP-LR Section 3.4.2.2.5, item 2, criteria 

do not apply.

3.4.2.2.6 Cracking Due to Stress Corrosion Cracking 

LRA Section 3.4.2.2.6, associated with LRA Table 3.4.1, items 3.4.1-13 and 3.4.1-14, 

addresses stainless steel piping components exposed to treated water greater than 140 °F 

(60 °C), which are being managed for cracking due to SCC by the Water Chemistry Program 
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and the One-Time Inspection Program. The criteria in SRP-LR Section 3.4.2.2.6 states that 

cracking due to SCC could occur for stainless steel piping, piping components, piping elements, 

tanks, and heat exchanger components exposed to treated water greater than 140 °F (60 °C). 

The SRP-LR also states that cracking due to SCC could occur for stainless steel piping, piping 

components, and piping elements exposed to steam. The SRP-LR further states that the 

existing AMP relies on monitoring and control of primary water chemistry. In addition, the 

SRP-LR states that high concentrations of impurities in crevices and locations of stagnant flow 

conditions could cause SCC; therefore, the GALL Report recommends that this aging issue be 

managed by a One-Time Inspection Program to verify the effectiveness of the Water Chemistry 

Control Program. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the Water Chemistry Program effectiveness will be confirmed by the One-Time 

Inspection Program. The applicant also stated that, for item 3.4.1-13, the applicability of the 

item is limited to BWRs; therefore, the item is not applicable to this LRA. In its review, the staff 

performed a search of the SRP-LR and confirmed that item 3.4.1-13 is only applicable for BWR 

plants.

The staff’s evaluations of the applicant’s Water Chemistry Program and the One-Time 

Inspection Program are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In 

its review of components associated with item 3.4.1-14, the staff finds that the applicant met the 

further evaluation criteria, and the applicant’s proposal to manage aging using the Water 

Chemistry Program and the One-Time Inspection Program is acceptable for the following 

reasons:

• The Water Chemistry Program establishes the plant water chemistry control parameters 

and their limits to mitigate the environmental effect on the aging.

• The Water Chemistry Program also takes corrective actions if the parameters exceed 

the limits.

• The One-Time Inspection will be used to confirm the effectiveness of the Water 

Chemistry Program consistent with the GALL Report.

Based on the program identified above, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.4.2.2.6 criteria. For those items that apply to LRA Section 3.4.2.2.6, the staff 

determined that the LRA is consistent with the GALL Report, and the applicant 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).

3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.4.2.2.7 against the following criteria in SRP-LR 

Section 3.4.2.2.7:

(1) LRA Section 3.4.2.2.7.1, is associated with LRA Table 3.4.1, items 3.4.1-6 (stainless 

steel tanks only), 3.4.1-15, and 3.4.1-16, and addresses aluminum, copper alloy, and 

stainless steel piping, piping components, piping elements, and stainless steel tanks, 

and heat exchanger components exposed to treated water, which are being managed 

for loss of material due to pitting and crevice corrosion by the Water Chemistry and 

One-Time Inspection Programs. The criteria in SRP-LR Section 3.4.2.2.7, item 1, state 

that loss of material due to pitting and crevice corrosion could occur for stainless steel, 

aluminum, and copper-alloy piping, piping components, and piping elements and for 
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stainless steel tanks and heat exchanger components exposed to treated water. The 

SRP-LR also states that the existing AMP relies on monitoring and control of water 

chemistry to mitigate degradation, and a one-time inspection of select components at 

susceptible locations is an acceptable method to determine if an aging effect does not 

occur or progresses very slowly such that the component’s intended function will be 

maintained during the period of extended operation. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that loss of material due to pitting and 

crevice corrosion of stainless steel piping, heat exchanger components, and tanks, and 

copper-alloy piping, heat exchanger components, and heater coils exposed to treated 

water will be managed by the Water Chemistry and One-Time Inspection Programs.

The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its 

review of components associated with items 3.4.1-6, 3.4.1-15, and 3.4.1-16, the staff 

finds that the applicant met the further evaluation criteria. The applicant’s proposal to 

manage aging using the Water Chemistry and One-Time Inspection Programs is 

acceptable because the Water Chemistry Program uses chemical sampling and 

corrective actions to ensure that impurities are minimized to reduce aging due to loss of 

material. Additionally, the One-Time Inspection Program will perform a one-time 

inspection of select components to verify the effectiveness of the Water Chemistry 

Program for managing the aging effects of loss of material.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.7, item 1, criteria. For those items that apply to LRA 

Section 3.4.2.2.7.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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 3.4.2.2.7.2 is associated with LRA Table 3.4.1, item 3.4.1-17, and 

addresses stainless steel piping, piping components, and piping elements exposed to 

soil, which are being managed for loss of material due to pitting and crevice corrosion by 

the Buried Piping and Tanks Inspection Program. The criteria in SRP-LR 

Section 3.4.2.2.7, item 2, states that the loss of material due to pitting and crevice 

corrosion could occur for stainless steel piping, piping components, and piping elements 

exposed to soil environment. The SRP-LR also states that a plant-specific AMP will be 

used to manage the loss of material aging effect. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the Buried Piping and Tanks Inspection 

Program will use external coatings and wrappings on buried piping as well as periodic 

inspections to determine loss of material.

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.3.1. In its review of components associated with LRA 

Table 3.4.1, item 3.4.1-17, the staff finds that the applicant met the further evaluation 

criteria, and the applicant’s proposal to manage aging using the Buried Piping and Tanks 

Inspection Program is acceptable for the following reasons:

• The program includes preventive actions, such as external coatings and 

wrappings installed to industry standard practices and backfill that will not 

damage the piping or coatings, and some systems are protected by a 

cathodic protection system.
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• Periodic visual inspections will be performed starting 10 years prior to the 

period of extended operation and extend into both 10-year periods during 

the period of extended operation to ensure that coatings remain intact or 

uncoated piping has not degraded.

• Plant-specific operating experience will be used to inform inspection 

locations.

• Alternatives to direct visual inspection, such as pressure tests or 

ultrasonic inspections, are capable of detecting piping degradation.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.7, item 2, criteria. For those items that apply to LRA 

Section 3.4.2.2.7.2, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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) LRA Section 3.4.2.2.7.3, referenced by LRA Table 3.4.1, item 3.4.1-18, addresses 

copper-alloy piping, piping components, and piping elements exposed to lubricating oil, 

which are being managed for loss of material due to pitting and crevice corrosion by the 

Lubricating Oil Analysis and One-Time Inspection Programs. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that the One-Time Inspection 

Program will be used to verify the effectiveness of the Lubricating Oil Analysis Program 

to manage loss of material due to pitting and crevice corrosion through examination of 

susceptible locations in copper-alloy piping, piping components, and copper-alloy heat 

exchanger components exposed to lubricating oil.

The staff reviewed LRA Section 3.4.2.2.7.3 against the criteria in SRP-LR 

Section 3.4.2.2.7, item 3, which states that loss of material due to pitting and crevice 

corrosion could occur for copper-alloy piping, piping components, and piping elements 

exposed to lubricating oil. The SRP-LR also states that the existing AMP relies on the 

periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion. 

The SRP-LR further states that control of lube oil contaminants may not always have 

been adequate to preclude corrosion; therefore, the effectiveness of lubricating oil 

contaminant control should be confirmed to ensure that corrosion does not occur. The 

SRP-LR also states that the GALL Report recommends further evaluation of programs to 

manage corrosion to verify the effectiveness of the Lubricating Oil Analysis Program. 

The GALL Report also states that a one-time inspection of selected components at 

susceptible locations is an acceptable method to ensure that corrosion does not occur

and that the component’s intended function will be maintained during the period of 

extended operation.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time 

Inspection Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. In its review of components associated with item 3.4.1-18, the staff finds 

the applicant’s proposal to manage aging using the One-Time Inspection Program to 

verify the effectiveness of the Lubricating Oil Analysis Program acceptable because the 

Lubricating Oil Analysis Program was determined to be consistent with the GALL Report. 

Additionally, the applicant stated that the One-Time Inspection Program will be used to 

examine copper-alloy piping, piping components, and copper-alloy heat exchanger 
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components to verify the effectiveness of the Lubricating Oil Analysis Program. This 

satisfies the acceptance criteria in SRP-LR Section 3.4.2.2.7, item 3; therefore, the 

applicant’s AMR is consistent with the GALL Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.7, item 3, criteria. For those items that apply to LRA 

Section 3.4.2.2.7.3, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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).

3.4.2.2.8 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

LRA Section 3.4.2.2.8 is associated with LRA Table 3.4.1, item 3.4.1-19, and addresses 

stainless steel piping, piping components, piping elements, and heat exchanger components 

exposed to lubricating oil, which are being managed for reduction of heat transfer due to fouling 

by the Lubricating Oil Analysis and the One-Time Inspection Programs. The criteria in SRP-LR 

Section 3.4.2.2.8 state that loss of material due to pitting, crevice, and MIC could occur in 

stainless steel piping components and heat exchanger components exposed to lubricating oil 

and that the existing AMP controls lube oil chemistry to maintain contaminants within limits that 

are not conducive to corrosion. The SRP-LR also states that the effectiveness of the program 

should be confirmed because control of lube oil chemistry may not have precluded corrosion, 

and a one-time inspection of selected components at susceptible locations is an acceptable 

verification method.

The staff’s evaluations of the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, respectively. In its review 

of components associated with item 3.4.1-19, the staff finds the applicant met the further 

evaluation review criteria. The staff finds the applicant’s proposal to manage aging using the 

specified AMPs acceptable because the Lubricating Oil Analysis Program maintains 

contaminants within acceptable limits, and the One-Time Inspection Program will verify the 

effectiveness of the Lubricating Oil Analysis Program to manage this aging effect.

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.8 criteria. For those items that apply to LRA Section 3.4.2.2.8, the staff 

determined that the LRA is consistent with the GALL Report. The applicant 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).

3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion 

LRA Section 3.4.2.2.9 is associated with LRA Table 3.4.1, item 3.4.1-5, and addresses loss of 

material due to general, pitting, crevice, and galvanic corrosion in steel heat exchanger 

components exposed to treated water. The applicant stated that this item is not applicable 

because there are no steel heat exchanger components exposed to treated water in the steam 

and power conversion systems. The staff reviewed LRA Section 3.4 and noted that, contrary to 

the applicant’s statement, there are steel heat exchanger components exposed to treated water 

in the steam and power conversion systems. The staff noted, however, the applicant aligned 

these heat exchanger components to LRA Table 3.4.1, item 3.4.1-3, which addresses the same 

aging effect for similar components in treated water in PWRs. The staff also noted that these 
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items are the subject of SRP-LR Section 3.4.2.2.2, item 1, and the further evaluation criteria are 

identical. The staff further noted that SRP-LR item 3.4.1-5 is for BWR components; therefore, it 

finds the applicant’s claim, that this item is not applicable, acceptable.

Based on the above, the staff concludes that SRP-LR Section 3.4.2.2.9 criteria do not apply.

3.4.2.2.10 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 Aging Management Review Results Not Consistent with or Not Addressed in 

the GALL Report 

In LRA Tables 3.4.2-1 through 3.4.2-8, 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 3.4.2-8, via Notes F–J, the applicant indicated which 

combinations of component type, material, environment, and AERM do 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 if the applicant 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 Auxiliary Steam 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 

auxiliary steam system component groups.

In LRA Table 3.4.2-1, the applicant stated that the copper-alloy greater than 15 percent zinc 

valve bodies exposed to steam are being managed for loss of material by the Water Chemistry 

Program and One-Time Inspection Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though copper alloys, greater than 15 percent zinc, exposed to steam are not specifically 

addressed in the GALL Report, Chapter V of the GALL Report indicates that copper alloys 

exposed to aqueous environments are susceptible to loss of material.
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The staff’s evaluation of the applicant’s Water Chemistry Program and One-Time Inspection 

Program is documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. The staff notes 

that the Water Chemistry Program relies upon periodic monitoring and control of detrimental 

contaminants in the water to manage loss of material. The staff also notes that the One-Time 

Inspection Program uses non-destructive examination methods to verify the effectiveness of the 

Water Chemistry Program. The staff finds the applicant’s proposal to manage aging using the 

Water Chemistry Program and One-Time Inspection Program acceptable because the 

maintenance of water chemistry will prevent the buildup of impurities that could lead to a loss of 

material, and the non-destructive examinations will verify the effectiveness of the Water 

Chemistry Program.

In LRA Tables 3.4.2-1 and 3.4.2-3, the applicant stated that the gray cast iron and copper-alloy

(greater than 15 percent zinc) components exposed to steam (internal) are being managed for 

loss of material by the Selective Leaching of Materials Program. The AMR items cite generic 

note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. For each 

AMR item that identifies selective leaching as an aging effect, there is an additional item that 

identifies loss of material (e.g., pitting, crevice corrosion) as an aging effect that will be managed 

by the Water Chemistry and One-Time Inspection Programs, or the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Program. Therefore, other loss of material aging 

effects will be managed. The staff noted that the GALL Report Table IX.C states that copper 

alloy (greater than 15 percent zinc) is susceptible to SCC. However, this aging effect would not 

be expected to occur in a steam environment because there are no compounds (e.g., ammonia) 

that cause SCC in this material ( “Conditions Contributing to Underground Copper Corrosion,” 

American Water Works Association Journal, August 1984).

The staff’s evaluation of the applicant’s Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.12. The staff finds the applicant’s proposal to manage aging using the 

Selective Leaching of Materials Program acceptable because the proposed program includes 

visual inspections and mechanical examination techniques that will determine whether loss of 

material due to selective leaching is occurring.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.4.2.3.2 Auxiliary Steam Condensate System—Summary of Aging Management Review—

LRA Table 3.4.2-2

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the 

auxiliary steam condensate system component groups.

The staff’s review did not find any items indicating plant-specific notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.4.2.1.
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3.4.2.3.3 Auxiliary Steam Heating 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 

auxiliary steam heating system component groups.

In LRA Table 3.4.2-3, the applicant stated that steel, stainless steel, and gray cast iron piping 

components and steel and stainless steel heat exchanger components exposed to steam are 

being managed for loss of material by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program. The AMR items cite generic note G and 

plant-specific note 1, which states that the environment is potable water converted to steam.

The staff noted that in the LRA received June 1, 2010, the AMR items originally cited generic 

note E and referenced LRA Table 3.4.1, item 3.4.1-37, which addressed steel and stainless 

steel piping and heat exchanger components exposed to steam being managed for loss of 

material due to general (steel only), pitting, and crevice corrosion. For these items, the GALL 

Report recommends GALL Report AMP XI.M2, “Water Chemistry Program,” to ensure that 

these aging effects are adequately managed. In its review of components associated with 

item 3.4.1-37, for which the applicant cited generic note E, the staff also noted that the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

proposes to manage the aging of steel and stainless steel components through the use of 

opportunistic visual inspections. By letter dated January 5, 2011, the staff issued RAI 3.4.2.3-1 

requesting that the applicant justify how loss of material in steel and stainless steel components 

exposed to steam will be managed in the absence of preventive actions, including chemical 

sampling and corrective actions, in light of the potential infrequent inspections that may occur 

due to managing these components with the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program.

In its response dated February 3, 2011, the applicant stated that the steam environment listed in 

Table 3.4.2-3 for the auxiliary steam heating system components is potable water converted to 

steam, which is not the same steam environment listed in item 3.4.1-37. The applicant also 

stated that the PWR secondary plant Water Chemistry Program is not applicable to potable 

water; therefore, item 3.4.1-37 should not have been selected for steam environment converted 

from potable water. The AMR items in Table 3.4.2-3 were revised to cite generic note G. The 

applicant further stated that the selection of the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program is the appropriate AMP for this environment. It is 

consistent with item VII.E5.AP-270 of the GALL Report, Revision 2, for which GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” is recommended to manage loss of material due to general (steel only), pitting, 

and crevice corrosion for steel and stainless steel piping, piping components, and piping 

elements exposed to raw water (potable).

The staff finds the applicant’s response acceptable because steam generated from untreated 

water is not an environment in the GALL Report, and the GALL Report identifies the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as appropriate 

for an internal environment, such as steam, that is not included in other AMPs for loss of 

material. The AMP includes periodic visual inspections that are capable of detecting loss of 

material, with a frequency that is informed by inspection results to provide reasonable 

assurance that component degradation will be detected prior to loss of intended function. The 

staff’s concern described in RAI 3.4.2.3-1 is resolved.
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The staff noted that GALL Report Tables IX.C and IX.E state that the applicable aging effects 

for gray cast iron, steel, and stainless steel include loss of material, cracking (stainless steel 

only), and reduction in heat transfer. The staff also noted that although the GALL Report does 

not specifically address aging in potable water converted to steam, the applicable aging effects 

would be expected to be consistent with those listed in Tables IX.C and IX.E. The staff 

reviewed the associated items in the LRA and confirmed that the applicant identified the correct 

aging effects for this component, material, and environment combination because the applicant 

addressed the other applicable aging effects, cracking and reduction of heat transfer, in 

Table 3.4.2-3.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. 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 visual inspections during maintenance or surveillance activities, which are capable of 

detecting the presence of corrosion by inspecting for localized discoloration and surface 

irregularities such as rust, scale or deposits, and surface pitting. Additionally, inspection results 

will be reviewed to ensure that the number of locations and inspection intervals are appropriate.

In LRA Table 3.4.2-3, the applicant stated that aluminum heat exchanger components exposed 

to air-indoor uncontrolled (external) are being managed for reduction in heat transfer by the 

External Surfaces Monitoring Program. The AMR item cites generic note F.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, item V.F-2, states that aluminum components exposed to air have no aging effects 

requiring management. Also, the components of interest function in a capacity to provide heat 

transfer; therefore, any accumulation of dirt, debris, or scale could prevent the component from 

performing its intended function, which is addressed in this AMR item.

The staff’s evaluation of the applicant’s Inspection of External Surfaces Monitoring Program is 

documented in SER Section 3.0.3.2.14. The staff finds the applicant’s proposal to manage 

aging using the External Surfaces Monitoring Program acceptable because the program uses 

periodic visual inspections that would identify corrosion discoloration and accumulation of dirt, 

scale, or debris indicative of fouling; thus, it would detect any reduction in heat transfer prior to 

loss of component-intended function.

The staff’s evaluation for gray cast iron and copper-alloy (greater than 15 percent zinc) 

components, exposed to stream (internal) and being managed for loss of material by the 

Selective Leaching of Materials Program citing generic note G, is documented in SER 

Section 3.4.2.3.1.

In LRA Table 3.4.2-3, the applicant stated that steel, stainless steel, and gray cast iron piping 

components and steel and stainless steel heat exchanger components exposed to steam are 

being managed for loss of material by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program. The AMR items cite generic note G and 

plant-specific note 1, which states that the environment is potable water converted to steam.

The staff noted that in the LRA received June 1, 2010, the AMR items originally cited generic 

note E and referenced LRA Table 3.4.1, item 3.4.1-37, which addressed steel and stainless 

steel piping and heat exchanger components exposed to steam being managed for loss of 

material due to general (steel only), pitting, and crevice corrosion. For these items, the GALL 
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Report recommends GALL Report AMP XI.M2, “Water Chemistry,” to ensure that these aging 

effects are adequately managed. In its review of components associated with item 3.4.1-37, for 

which the applicant cited generic note E, the staff also noted that the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program proposes to manage the 

aging of steel and stainless steel components through the use of opportunistic visual 

inspections. By letter dated January 5, 2011, the staff issued RAI 3.4.2.3-1 requesting that the 

applicant justify how loss of material in steel and stainless steel components exposed to steam 

will be managed in the absence of preventive actions, including chemical sampling and 

corrective actions, in light of the potential infrequent inspections that may occur due to 

managing these components with the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program.

In its response dated February 3, 2011, the applicant stated that the steam environment listed in 

Table 3.4.2-3 for the auxiliary steam heating system components is potable water converted to 

steam, which is not the same steam environment listed in item 3.4.1-37. The applicant also 

stated that the PWR secondary plant Water Chemistry Program is not applicable to potable 

water; therefore, item 3.4.1-37 should not have been selected for steam environment converted 

from potable water. The AMR items in Table 3.4.2-3 were revised from generic note E and 

plant-specific note 1 to generic note G and plant-specific note 1. The applicant further stated 

that the selection of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is the appropriate AMP for this environment. It is consistent with 

item VII.E5.AP-270 of the GALL Report, Revision 2, for which GALL Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” is 

recommended to manage loss of material due to general (steel only), pitting, and crevice 

corrosion for steel and stainless steel piping, piping components, and piping elements exposed 

to raw water (potable).

The staff finds the applicant’s response acceptable because steam generated from untreated 

water is not an environment in the GALL Report, and the GALL Report identifies the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as appropriate 

for an internal environment, such as steam, that is not included in other AMPs for loss of 

material. The AMP includes periodic visual inspections that are capable of detecting loss of 

material, with a frequency that is informed by inspection results to provide reasonable 

assurance that component degradation will be detected prior to loss of intended function. The 

staff’s concern described in RAI 3.4.2.3-1 is resolved.

The staff noted that GALL Report Tables IX.C and IX.E state that the applicable aging effects 

for gray cast iron, steel, and stainless steel include loss of material, cracking (stainless steel 

only), and reduction in heat transfer. The staff also noted that although the GALL Report does 

not specifically address aging in potable water converted to steam, the applicable aging effects 

would be expected to be consistent with those listed in Tables IX.C and IX.E. The staff 

reviewed the associated items in the LRA and confirmed that the applicant identified the correct 

aging effects for this component, material, and environment combination because the applicant 

addressed the other applicable aging effects, cracking, and reduction of heat transfer in 

Table 3.4.2-3.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. 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 visual inspections during maintenance or surveillance activities, which are capable of 
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detecting the presence of corrosion by inspecting for localized discoloration and surface 

irregularities such as rust, scale or deposits, and surface pitting. Additionally, inspection results 

will be reviewed to ensure that the number of locations and inspection intervals are appropriate.

In LRA Table 3.4.2-3, the applicant stated that stainless steel heat exchanger components, 

exposed to steam (internal or external) are being managed for reduction of heat transfer with 

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 confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

the GALL Report, Table IX.B, states that heat exchanger components are susceptible to 

reduction of heat transfer, which is addressed in the AMR. The staff noted that the material of 

the component, stainless steel, is also susceptible to loss of material due to pitting and crevice 

corrosion and cracking due to SCC aging effects, both of which are addressed in other AMR 

items.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable. The program includes 

periodic visual inspections performed during maintenance and surveillance activities, which can 

identify localized discoloration and surface irregularities such as rust, scale or deposits, and 

surface pitting to determine if material degradation is occurring that could result in loss of the 

component-intended function.

In LRA Table 3.4.2-3, the applicant stated that copper alloy and copper alloy greater than 

15 percent zinc piping, fittings, and valve bodies exposed to steam (internal) are being managed 

for loss of material due to general, pitting, and crevice corrosion with 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 confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Although 

copper exposed to steam is not specifically addressed in the GALL Report, Table IX.C of the 

GALL Report states that copper alloys and copper alloys with greater than 15 percent zinc are 

susceptible to loss of material due to pitting and crevice corrosion. The GALL Report, 

Table IX.C, also states that copper alloys with greater than 15 percent zinc are susceptible to 

selective leaching and SCC. The staff noted that the applicant addressed selective leaching in 

another AMR item. The staff also noted that copper alloys with greater than 15 percent zinc are 

only susceptible to SCC in the presence of ammonia (Handbook of Corrosion Data, 1995), and 

the staff did not find any evidence that ammonia is present in the auxiliary steam heating 

system. Therefore, the only aging effects of concern are loss of material due to pitting and 

crevice corrosion and loss of material due to selective leaching, which are addressed in the 

AMR.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable. The program includes 

periodic visual inspections performed during maintenance and surveillance activities, which can 

identify localized discoloration and surface irregularities such as rust, scale or deposits, and 
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surface pitting to determine if material degradation is occurring that could result in a loss of 

component-intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.4.2.3.4 Circulating Water System—Summary of Aging Management Review—LRA 

Table 3.4.2-4

The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for the 

circulating water system component groups.

In LRA Table 3.4.2-4, the applicant stated that the steel bolting exposed to condensation is 

being managed for loss of preload by the Bolting Integrity Program. The AMR item cites generic 

note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though steel bolting exposed to condensation is not specifically addressed in the GALL Report, 

Table IX.E of the GALL Report states that loss of preload can occur independent of 

environmental conditions because it can be caused by thermal or mechanical effects. 

Additionally, Table IX.C of the GALL Report states that steel material is susceptible to a variety 

of aging effects and mechanisms, including loss of material due to general, pitting, and crevice 

corrosion. The staff noted that the applicant addressed loss of material in additional items for 

each of these components; therefore, the aging effect of concern is loss of preload, which is 

addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of steel bolting exposed to 

condensation uncontrolled in the steam and power conversion system, the GALL Report has 

items for loss of preload of other material bolting managed by the Bolting Integrity Program. 

The staff finds the applicant’s proposal to manage aging using the Bolting Integrity Program 

acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance 

control such as application of appropriate gasket alignment, torque, lubricants, and preload. 

Additionally, the program inspects for leakage and loose or missing nuts, which verify that the 

aging effect, loss of preload, will be adequately managed so that the intended functions will be 

maintained consistent with the CLB for the period of extended operation.

In LRA Table 3.4.2-4, the applicant stated that nickel alloy and copper alloy with greater than 

15 percent zinc valve body and nickel-alloy piping and fittings and thermowell exposed to 

condensation (external) are being managed for loss of material by the External Surfaces 

Monitoring Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. While 

nickel-alloy components exposed to condensation (external) are not specifically addressed in 

the GALL Report, item VII.C1-13 states that nickel alloys exposed to raw water are susceptible 

to loss of material, which is addressed in the AMR item. Separately, the GALL Report, 

item VII.F1-16 states that copper-alloy components exposed to condensation are susceptible to 
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loss of material. Copper alloy with greater than 15 percent zinc components is a subset of 

copper-alloy components, and the GALL Report states that copper alloy with greater than 

15 percent zinc components is susceptible to selective leaching. By letter dated 

February 24, 2011, the staff issued RAI 3.4.2.3.4-1 requesting that the applicant clarify if the 

copper alloy with greater than 15 percent zinc is managed for selective leaching or not. The 

staff also asked the applicant to state the AMP and inspection method(s) being used to manage 

the loss of material if it is determined that the copper alloy with greater than 15 percent zinc 

should be managed for selective leaching.

In its response dated March 22, 2011, the applicant stated that selective leaching has been 

added as an aging mechanism for copper alloy greater than 15 percent zinc components 

exposed to internal or external condensation environment. In addition, the applicant stated the 

following:

• Selective leaching has also been added as an aging mechanism for gray cast iron 

components exposed to internal or external condensation environment.

• Affected LRA Tables 3.3.2-4, 3.3.2-9, 3.3.2-12, 3.3.2-15, 3.3.2-19, 3.3.2-20, 3.3.2-36, 

3.3.2-37, 3.3.2-44, and 3.4.2-4 have been updated to reflect the addition.

• The program description language in LRA Appendices A (Section A.2.1.21) and B 

(Section B.2.1.21) has been modified to include condensation as an environment 

managed by the Selective Leaching of Materials Program.

The staff finds the applicant’s response acceptable because the applicant included selective 

leaching as an aging mechanism for copper alloy greater than 15 percent zinc components 

exposed to internal or external condensation environment, and the Selective Leaching of 

Materials Program will be used to manage the effects of aging. The staff’s concern described in 

RAI 3.4.2.3.4-1 is resolved.

The staff’s evaluations of the applicant’s Selective Leaching of Materials and External Surfaces 

Monitoring Programs are documented in SER Sections 3.0.3.2.12 and 3.0.3.2.14, respectively. 

The staff finds the applicant’s proposal to manage aging using the External Surfaces Monitoring 

and Selective Leaching of Materials Programs acceptable because the External Surfaces 

Monitoring Program uses periodic visual inspections. Additionally, the Selective Leaching of 

Materials Program uses a one-time visual inspection and hardness measurement of selective 

set of sample components, which would detect loss of material prior to loss of 

component-intended function.

In LRA Table 3.4.2-4, the applicant stated that the elastomer expansion joints exposed to 

condensation (external) are being managed for hardening and loss of strength by the External 

Surfaces Monitoring Program. The AMR item cites generic note H.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. The GALL 

Report, Table IX.C, indicates that elastomers are susceptible to hardening and loss of strength 

at temperatures over 95 °F (35 °C), and the environment of interest, condensation, can be in a 

temperature range in which elastomers are susceptible to hardening and loss of strength, which 

is addressed in the AMR.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.14. The staff noted that the applicant’s program includes non-visual 

examinations, such as scratching, to determine if scale or residues are present or determine if 
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there is a breakdown of material, bending or folding of the elastomer to detect cracking that 

initiates at the surface, stretching and pressing to determine the resistance of the material to 

hardening effects, and pressing to gauge the materials resiliency. The staff finds the applicant’s 

proposal to manage aging using the External Surfaces Monitoring Program acceptable because 

the program uses periodic visual inspections as well as non-visual tactile examinations, which 

are capable of detecting hardening and loss of strength.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.4.2.3.5 Condensate System—Summary of Aging Management Review—LRA Table 3.4.2-5

The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for the 

condensate system component groups.

In LRA Tables 3.4.2-5, 3.4.2-6, 3.4.2-7, and 3.4.2-8, the applicant stated that the stainless steel 

bolting exposed to air-indoor uncontrolled is being managed for loss of preload by the Bolting 

Integrity Program. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 

though stainless steel bolting exposed to air-indoor uncontrolled is not specifically addressed in 

the GALL Report, Table IX.E of the GALL Report states that loss of preload can occur 

independent of environmental conditions because it can be caused by thermal or mechanical 

effects. Additionally, Table IX.C of the GALL Report states that stainless steel material is 

susceptible to a variety of aging effects and mechanisms, including loss of material due to 

pitting and crevice corrosion and cracking due to SCC. The staff noted that the environment of 

interest, air-indoor, would not induce SCC or loss of material in stainless steel material because 

stainless steel is inherently resistant to corrosion in the air-indoor environment. Therefore, the 

aging effect of concern is loss of preload, which is addressed in the AMR.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.7. While there is no AMR for loss of preload of stainless steel bolting exposed 

to air-indoor uncontrolled in the steam and power conversion system, the GALL Report has 

items for loss of preload of other material bolting managed by the Bolting Integrity Program. 

The staff finds the applicant’s proposal to manage aging using the Bolting Integrity Program 

acceptable because the Bolting Integrity Program conducts bolting assembly and maintenance 

control such as application of appropriate gasket alignment, torque, lubricants, and preload. 

The program also inspects for leakage and loose or missing nuts, which verify that the aging 

effect, loss of preload, will be adequately managed so that the intended functions will be 

maintained consistent with the CLB for the period of extended operation.

In LRA Table 3.4.2-5, the applicant stated that the stainless steel tanks exposed to air-outdoor 

(external) are being managed for loss of material by the External Surfaces Monitoring Program. 

The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination. Even 
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though stainless steel exposed to air-outdoor (external) is not specifically addressed in the 

GALL Report, Table IX.C of the GALL Report states that stainless steels are susceptible loss of 

material and cracking due to SCC. The staff noted that the environment of interest, air-outdoor 

(external), would be expected to contain higher levels of chlorides due to the site’s relative 

proximity to the ocean, which are known to induce SCC. By letter dated February 24, 2011, the 

staff issued RAI 3.3-1 requesting that the applicant provide additional information on why 

atmospheric chloride-induced SCC is not considered to be an applicable aging effect for 

stainless steel components exposed to outdoor-air. The staff also asked the applicant to 

explain how SCC will be managed if it is determined to be an applicable aging affect.

In its response dated March 22, 2011, the applicant stated that SCC has been added as an 

aging mechanism for stainless steel components exposed to air-outdoor environment. The 

applicant added a new item to manage cracking by the External Surfaces Monitoring Program. 

The staff finds the applicant’s response acceptable because the applicant modified the LRA to 

include SCC as an applicable aging effect for stainless steel components exposed to outdoor-air 

containing high levels of chloride and include SCC as an aging effect to be managed by the 

External Surfaces Monitoring Program, which includes visual inspection that is a capable 

technique to detect SCC. The staff’s concern described in RAI 3.3-1 is resolved.

The staff’s evaluation of the applicant’s Inspection of External Surfaces Monitoring Program is 

documented in SER Section 3.0.3.2.14. The staff finds that the applicant’s proposal to manage 

aging using the External Surfaces Monitoring Program acceptable because the program uses 

periodic visual inspections that would detect loss of material and detect SCC prior to loss of 

component-intended function.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant 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).

3.4.2.3.6 Feedwater System—Summary of Aging Management Review—LRA Table 3.4.2-6

The staff reviewed LRA Table 3.4.2-6, which summarizes the results of AMR evaluations for the 

feedwater system component groups.

In LRA Tables 3.4.2-6 and 3.4.2-7, the applicant stated that the aluminum instrumentation 

element components exposed to lubricating oil (internal) are being managed for loss of material 

by the Lubricating Oil Analysis Program, as augmented by the One-Time Inspection Program. 

The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because,

as stated in the ASM Handbook, ASM International, 2005, aluminum is a corrosion-resistant 

material. For aluminum instrumentation element components internally exposed to oil, the 

applicant identified the appropriate aging effects (i.e., loss of material). This aging effect is 

managed by the Lubricating Oil Analysis Program, as augmented by the One-Time Inspection 

Program. The staff’s evaluations of the applicant’s Lubricating Oil Analysis Program and the 

One-Time Inspection Program are documented in SER Sections 3.0.3.2.16 and 3.0.3.1.8, 

respectively. The Lubricating Oil Analysis Program performs oil condition monitoring activities 
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to manage the aging effects of loss of material due to galvanic, general, pitting, crevice, and 

MIC, fouling, and heat transfer degradation due to fouling. The One-Time Inspection Program 

visually inspects components for loss of material.

The staff finds the applicant’s proposal to manage aging using the Lubricating Oil Analysis 

Program, as augmented by the One-Time Inspection Program, acceptable because the 

Lubricating Oil Analysis Program monitors for contaminants that could cause corrosion and for 

degradation of the oil that could be caused by corrosion products. This analysis is 

supplemented by the One-Time Inspection Program, which uses visual examinations and other 

examination techniques to inspect for the loss of material in areas where the most severe aging 

effects would be expected to occur.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor uncontrolled and being 

managed for loss of preload by the Bolting Integrity Program citing generic note G, is 

documented in SER Section 3.4.2.3.5.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.4.2.3.7 Main Steam System—Summary of Aging Management Review—LRA Table 3.4.2-7

The staff reviewed LRA Table 3.4.2-7, which summarizes the results of AMR evaluations for the 

main steam system component groups.

In LRA Table 3.4.2-7, the applicant stated that stainless steel valve bodies, piping, fittings, and 

orifices exposed to air-outdoor (internal) are being managed for loss of material due to general, 

pitting, and crevice corrosion 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 noted that, even though stainless steel 

valve bodies, piping, fittings, and orifices exposed to air-outdoor are not specifically addressed 

in the GALL Report, Table IX.C of the GALL Report states that stainless steel material is 

susceptible to a variety of aging effects and mechanisms, including loss of material due to 

pitting and crevice corrosion and cracking due to SCC. The staff noted that given the plant’s 

proximity to the ocean, stainless steel components exposed to the air-outdoor (internal) 

environment would be susceptible to cracking due to SCC. However, the staff noted that the 

applicant did not identify SCC as an AERM for these components. By letter dated 

February 24, 2011, the staff issued RAI 3.3-1 requesting that the applicant justify its 

management of this material, environment, AERM, and AMP combination.

In its response dated March 22, 2011, the applicant stated that SCC has been added as an 

aging mechanism for stainless steel components exposed to an air-outdoor environment. The 

applicant added new AMR items to manage cracking using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program. The staff finds the applicant’s 

response acceptable because the applicant modified the LRA to include cracking due to SCC as 

an applicable aging effect for stainless steel components exposed to outdoor air, and it will use 

either magnified visual inspections or ultrasonic inspections, which are capable of detecting 

cracking. The staff’s concern described in RAI 3.3-1 is resolved.
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The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.15. The staff finds 

the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable for the following reasons:

• The program includes periodic visual inspections performed during maintenance and 

surveillance activities, which can identify localized discoloration and surface irregularities 

such as rust, scale or deposits, and surface pitting.

• The program includes either magnified visual inspection or ultrasonic inspection to 

determine if material degradation is occurring that could result in a loss of the 

component-intended function.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor uncontrolled and being 

managed for loss of preload by the Bolting Integrity Program citing generic note G, is 

documented in SER Section 3.4.2.3.5.

The staff’s evaluation for aluminum instrumentation element components, exposed to lubricating 

oil (internal) and being managed for loss of material by the Lubricating Oil Analysis Program, as 

augmented by the One-Time Inspection Program citing generic note G, is documented in SER 

Section 3.4.2.3.6.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).

3.4.2.3.8 Steam Generator Blowdown System—Summary of Aging Management Review—

LRA Table 3.4.2-8

The staff reviewed LRA Table 3.4.2-8, which summarizes the results of AMR evaluations for the 

steam generator blowdown system component groups.

The staff’s evaluation for stainless steel bolting, exposed to air-indoor uncontrolled and being 

managed for loss of preload by the Bolting Integrity Program citing generic note G, is 

documented in SER Section 3.4.2.3.5.

In LRA Table 3.4.2-8 the applicant stated that for glass piping elements exposed to air-with 

borated water leakage (external) there is no aging effect and no AMP is proposed. The AMR 

item cites generic note G. The staff reviewed the associated item in the LRA and confirmed that 

no aging effect is applicable for this component, material and environment combination because 

the GALL Report, item V.F-9, states that for an environment of treated borated water there is no 

AERM and no recommended AMP, and the air with borated water leakage environment is no 

more severe than the treated borated water environment.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant 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).
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3.4.3 Conclusion 

The staff concludes that 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).

3.5

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

following structures and component supports groups:

Aging Management of Containments, Structures, and Component Supports

• buildings and structures within license renewal

• containment structures

• fuel handling and overhead cranes

• miscellaneous yard structures

• primary structures

• supports

• turbine building

• water control structures

3.5.1 Summary of Technical Information in the Application 

LRA Section 3.5 provides AMR results for the containment, structures, and component supports 

groups. LRA Table 3.5-1, “Summary of Aging Management Evaluations for Structures and 

Component Supports,” is a summary comparison of the applicant’s AMRs with those evaluated 

in the GALL Report for the structures and component supports 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 

CRs 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 if the applicant 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).

The staff conducted a review of the AMR items that the applicant identified as being consistent 

with the GALL Report 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 3.5.2.1.
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The staff also conducted a review of 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 3.5.2.2 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, which 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.

Table 3.5-1. Staff evaluation for structures and component supports components in the 

GALL Report

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

PWR concrete (reinforced and prestressed) and steel containments

Concrete 

elements—walls, 

dome, basemat, ring 

girder, buttresses, 

containment (as 

applicable)

(3.5.1-1)

Aging of 

accessible and 

inaccessible 

concrete areas 

due to 

aggressive 

chemical attack, 

and corrosion of 

embedded steel

ISI (IWL) and for 

inaccessible 

concrete, an 

examination of 

representative 

samples of belowgrade concrete, and 

periodic monitoring 

of groundwater if 

environment is 

nonaggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive.

Yes, plantspecific, if 

environment 

is 

aggressive

ISI (IWL); 

Structures 

Monitoring 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.1)

Concrete 

elements—All

(3.5.1-2)

Cracks and 

distortion due to 

increased 

stress levels 

from settlement

Structures 

Monitoring 

Program—If a 

dewatering system 

is relied upon for 

control of 

settlement, then the 

applicant is to 

ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program or 

a 

dewatering

system is 

relied upon. 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.2.1)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Concrete 

elements—

foundation, subfoundation

(3.5.1-3)

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement due 

to erosion of 

porous concrete 

subfoundation

Structures 

Monitoring 

Program—If a 

dewatering system 

is relied upon to 

control erosion of 

cement from porous 

concrete 

subfoundations,

then the applicant is 

to ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program or 

a 

dewatering

system is 

relied upon.

Not 

applicable—

Porous 

concrete 

subfoundation 

is not 

incorporated 

into the design 

and 

construction of 

foundation

Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.1)

Concrete 

elements—dome, 

wall, basemat, ring 

girder, buttresses, 

containment, 

concrete fill-in 

annulus (as 

applicable)

(3.5.1-4)

Reduction of 

strength and 

modulus of 

concrete due to 

elevated 

temperature

A plant-specific 

AMP is to be 

evaluated.

Yes, plantspecific if 

temperature 

limits are 

exceeded

Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.1)

Steel elements—

drywell; torus;

drywell head;

embedded shell and 

sand pocket

regions; drywell

support skirt; torus

ring girder;

downcomers; liner

plate, ECCS suction 

header, support 

skirt, region shielded 

by diaphragm floor,

suppression

chamber (as 

applicable) 

(3.5.1-5)

Loss of material 

due to general, 

pitting, and 

crevice

corrosion

ISI (IWE) and

10 CFR Part 50,

Appendix J

Yes, if 

corrosion is

significant 

for

inaccessible 

areas

Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.2.1)

Steel elements—

steel liner, liner

anchors, integral 

attachments 

(3.5.1-6)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

ISI (IWE) and

10 CFR Part 50, 

Appendix J

Yes, if 

corrosion is

significant 

for 

inaccessible 

areas

ISI (IWE) and 

10 CFR

Part 50, 

Appendix J 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.2.1)
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Prestressed 

containment 

tendons

(3.5.1-7)

Loss of 

prestress due to 

relaxation, 

shrinkage, 

creep, and 

elevated 

temperature

TLAA, evaluated in 

accordance with 

10 CFR 54.21 (c)

Yes, TLAA Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.1)

Steel and stainless 

steel elements—

vent line, vent 

header, vent line 

bellows; 

downcomers 

(3.5.1-8)

Cumulative 

fatigue damage 

(CLB fatigue 

analysis exists)

TLAA evaluated in 

accordance with 

10CFR 54.21(c)

Yes, TLAA Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.2.1)

Steel, stainless steel 

elements, dissimilar 

metal welds—

penetration sleeves, 

penetration bellows; 

suppression pool

shell, unbraced 

downcomers 

(3.5.1-9)

Cumulative 

fatigue damage 

(CLB fatigue 

analysis exists)

TLAA evaluated in 

accordance with 

10CFR 54.21(c)

Yes, TLAA. TLAA, 

evaluated in 

accordance 

with 10 CFR

54.21(c)

Consistent with 

GALL Report (See 

SER Section 

3.5.2.2.1)

Stainless steel 

penetration sleeves, 

penetration bellows, 

dissimilar metal

welds 

(3.5.1-10)

Cracking due to 

stress corrosion 

cracking

ISI (IWE) and 

10 CFR Part 50, 

Appendix J and 

additional 

appropriate

examinations/

evaluations for 

bellows assemblies 

and dissimilar metal 

welds

Yes, 

detection of 

aging is to 

be 

evaluated

Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.1)

Stainless steel vent 

line bellows

(3.5.1-11)

Cracking due to 

SCC

ISI (IWE) and 

10 CFR Part 50, 

Appendix J, and 

additional 

appropriate

examinations/evalu

ations for bellows

assemblies and 

dissimilar metal 

welds

Yes, 

detection of 

aging is to 

be 

evaluated

Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.2.1)

Steel, stainless steel 

elements, dissimilar

metal welds—

penetration sleeves, 

penetration bellows;

suppression pool 

shell, unbraced 

downcomers 

(3.5.1-12)

Cracking due to 

cyclic loading

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

supplemented to 

detect fine cracks

Yes, 

detection of 

aging is to 

be 

evaluated

Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.1)
Aging Management Review Results

3-445

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel, stainless steel 

elements, dissimilar

metal welds—torus; 

vent line; vent 

header; vent line 

bellows; 

downcomers 

(3.5.1.13)

Cracking due to 

cyclic loading

ISI (IWE) and 

10 CFR Part 50, 

Appendix J 

supplemented to 

detect fine cracks

Yes, 

detection of 

aging is to 

be 

evaluated

Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.2.1)

Concrete 

elements—dome, 

wall, basemat ring 

girder, buttresses, 

containment (as 

applicable)

(3.5.1-14)

Loss of material 

(scaling, 

cracking, and 

spalling) due to 

freeze-thaw

ISI (IWL)—

Evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering 

index > 100 dayinch/yr) (NUREG1557).

Yes, for 

inaccessible 

areas of 

plants 

located in 

moderate to 

severe 

weathering 

conditions.

ASME Code

Subsection 

IWL 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.2.1)

Concrete 

elements—walls, 

dome, basemat, ring 

girder, buttresses, 

containment, 

concrete fill-in 

annulus (as 

applicable).

(3.5.1-15)

Cracking due to 

expansion and 

reaction with 

aggregate and 

increase in 

porosity, 

permeability 

due to leaching 

of calcium 

hydroxide

ISI (IWL) for 

accessible areas. 

None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R.

Yes, if 

concrete 

was not 

constructed 

as stated in 

inaccessible 

areas.

ASME Code

Subsection 

IWL 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.1)

Seals, gaskets, and 

moisture barriers 

(3.5.1-16)

Loss of sealing 

and leakage 

through 

containment 

due to 

deterioration of 

joint seals,

gaskets, and 

moisture 

barriers

(caulking, 

flashing, and 

other sealants)

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No ISI (IWE), and 

10 CFR

Part 50, 

Appendix J 

Consistent with 

GALL Report

Personnel airlock, 

equipment hatch 

and CRD hatch 

locks, hinges, and 

closure mechanisms 

(3.5.1-17)

Loss of leak 

tightness in 

closed position 

due to 

mechanical 

wear of locks, 

hinges, and 

closure 

mechanisms

10 CFR Part 50, 

Appendix J and 

Plant TS

No 10 CFR Part 

50, Appendix J 

and Plant TSs

surveillance 

testing 

requirements

Consistent with 

GALL Report. 
Aging Management Review Results

3-446

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Steel penetration 

sleeves and 

dissimilar metal 

welds; personnel 

airlock, equipment 

hatch and CRD 

hatch 

(3.5.1-18)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No ISI (IWE), and 

10 CFR Part 

50, Appendix J 

Consistent with 

GALL Report. 

Steel elements—

stainless steel 

suppression 

chamber shell (inner 

surface) 

(3.5.1-19)

Cracking due to 

SCC

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.1.1)

Steel elements—

suppression 

chamber liner (Inner 

surface) 

(3.5.1-20)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.1.1)

Steel elements—

drywell head and 

downcomer pipes 

(3.5.1-21)

Fretting or lock 

up due to 

mechanical 

wear

ISI (IWE) No Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.1.1)

Prestressed 

containment—

tendons and 

anchorage 

components

(3.5.1-22)

Loss of material 

due to corrosion

ISI (IWL) No Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.1.1)

Safety-related and other structures and component supports

All groups except 

Group 6—interior 

and above grade 

exterior concrete

(3.5.1-23)

Cracking, loss 

of bond, and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel

Structures 

Monitoring Program

Yes, if not 

within scope 

of the 

applicant’s 

Structures 

Monitoring 

Program

Structures 

Monitoring 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.2)

All groups except 

Group 6—interior 

and above grade 

exterior concrete

(3.5.1-24)

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack

Structures 

Monitoring Program

Yes, if not 

within scope 

of the 

applicant’s 

Structures 

Monitoring 

Program

Structures 

Monitoring 

Program and 

Fire Protection 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.1.6 and 

3.5.2.2.2)
Aging Management Review Results

3-447

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

All groups except 

Group 6—steel 

components: all 

structural steel 

(3.5.1-25)

Loss of material 

due to corrosion

Structures 

Monitoring Program 

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

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program

Structures 

Monitoring 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.2)

All groups except 

Group 6—

accessible and 

inaccessible 

concrete: 

foundation

(3.5.1-26)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Structures 

Monitoring 

Program—

Evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

> 100 day-inch/yr)

(NUREG-1557)

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program or 

for 

inaccessible 

areas of 

plants 

located in 

moderate to 

severe 

weathering 

conditions

Structures 

Monitoring

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.2.2)

All groups except 

Group 6—

accessible and 

inaccessible 

interior/exterior 

concrete

(3.5.1-27)

Cracking due to 

expansion due 

to reaction with 

aggregates

Structures 

Monitoring 

Program. None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program or 

concrete 

was not 

constructed 

as stated for 

inaccessible

areas

Structures 

Monitoring 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.2)
Aging Management Review Results

3-448

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Groups 1–3, 5–9—

All

(3.5.1-28)

Cracks and 

distortion due to 

increased 

stress levels 

from settlement

Structures 

Monitoring 

Program—If a 

dewatering system 

is relied upon for 

control of 

settlement, then the 

applicant is to 

ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program or 

a 

dewatering

system is 

relied upon

Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.2)

Groups 1–3, 5–9—

foundation

(3.5.1-29)

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement due 

to erosion of 

porous concrete 

subfoundation

Structures 

Monitoring 

Program—If a 

dewatering system 

is relied upon for 

control of 

settlement, then the 

applicant is to 

ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program

Structures 

Monitoring 

Program 

Not applicable to 

Seabrook (See 

SER Section

3.5.2.2.2)

Group 4—Radial 

beam seats in BWR 

drywell; RPV 

support shoes for

PWR with nozzle

supports; steam 

generator supports 

(3.5.1-30)

Lock-up due to 

wear

ISI (IWF) or 

Structures 

Monitoring Program

Yes, if not 

within the 

scope of the 

ISI or 

Structures 

Monitoring 

Programs

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.2.2)

Groups 1–3, 5, 

7–9—below-grade 

concrete 

components, such 

as exterior walls 

below grade and 

foundation

(3.5.1-31)

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling), 

aggressive 

chemical attack; 

cracking, loss of 

bond, and loss 

of material 

(spalling, 

scaling), 

corrosion of 

embedded steel

Structures 

Monitoring 

Program.

Examination of 

representative 

samples of belowgrade concrete, and 

periodic monitoring 

of groundwater, if 

the environment is 

non-aggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive.

Yes, plantspecific, If 

environment 

is 

aggressive

Structures 

Monitoring

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.2)
Aging Management Review Results

3-449

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Groups 1–3, 5, 

7–9—exterior above 

and below grade 

reinforced concrete 

foundations

(3.5.1-32)

Increase in 

porosity and 

permeability, 

and loss of 

strength due to 

leaching of 

calcium 

hydroxide

Structures 

Monitoring Program 

for accessible 

areas. None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77

Yes, if 

concrete 

was not 

constructed 

as stated for 

inaccessible 

areas

Structures 

Monitoring

Program for 

accessible 

areas

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.2)

Groups 1–5—

concrete

(3.5.1-33)

Reduction of 

strength and 

modulus due to 

elevated 

temperature

Plant-specific Yes, plantspecific if 

temperature 

limits are 

exceeded

A plant-specific 

AMP is to be 

evaluated

Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.2)

Group 6—concrete; 

all

(3.5.1-34)

Increase in 

porosity and 

permeability, 

cracking, loss of 

material due to 

aggressive 

chemical attack; 

cracking, loss of 

bond, loss of 

material due to 

corrosion of 

embedded steel

Inspection of WaterControl Structures 

or Federal Energy 

Regulatory 

Commission 

(FERC)/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs and for 

inaccessible 

concrete, an 

examination of 

representative 

samples of belowgrade concrete, and 

periodic monitoring 

of groundwater, if 

the environment is 

non-aggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive.

Yes. Plantspecific if 

environment 

is 

aggressive

Inspection of 

water-control 

structures 

associated with 

nuclear plants 

is integrated 

into the 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.5 and 

3.5.2.2.2)
Aging Management Review Results

3-450

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Group 6—exterior 

above- and belowgrade concrete 

foundation

(3.5.1-35)

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Inspection of WaterControl Structures 

or FERC/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs. 

Evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

> 100 day-inch/yr) 

(NUREG-1557).

Yes, for 

inaccessible 

areas of 

plants 

located in 

moderate to 

severe 

weathering 

conditions

Inspection of 

water-control 

structures 

associated with 

nuclear plants 

is integrated 

into the 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.2 and 

3.5.2.2.2)

Group 6—all 

accessible and 

inaccessible 

reinforced concrete

(3.5.1-36)

Cracking due to 

expansion/reaction with 

aggregates

Accessible areas—

Inspection of WaterControl Structures 

or FERC/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs. None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77.

Yes, if 

concrete 

was not 

constructed 

as stated for 

inaccessible 

areas

Inspection of 

Water-control 

structures 

associated with 

nuclear plants 

is integrated 

into the 

Structures 

Monitoring 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.1.7 and 

3.5.2.2.2)

Group 6: exterior 

above and belowgrade reinforced 

concrete foundation 

interior slab

(3.5.1-37)

Increase in 

porosity and 

permeability, 

loss of strength 

due to leaching 

of calcium 

hydroxide

For accessible 

areas, Inspection of 

Water-Control 

Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs. None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77

Yes, if 

concrete 

was not 

constructed 

as stated for 

inaccessible 

areas

Inspection of 

water-control 

structures 

associated with 

nuclear plants 

is integrated 

into the 

Structures 

Monitoring 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.1.6 and 

3.5.2.2.2)

Groups 7, 8: Tank 

Liners (3.5.1-38)

Cracking due to 

SCC; loss of 

material due to 

pitting and 

crevice 

corrosion

Plant-specific Yes Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.2)
Aging Management Review Results

3-451

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Support members;

welds; bolted

connections; 

support anchorage 

to building structure 

(3.5.1-39)

Loss of material 

due to general 

and pitting 

corrosion

Structures 

Monitoring Program

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.2.2)

Building concrete at 

locations of 

expansion and 

grouted anchors; 

grout pads for 

support base plates

(3.5.1-40)

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service induced 

cracking or 

other concrete 

aging 

mechanisms 

Structures 

Monitoring Program

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program

Structures 

Monitoring 

Program 

Cannot complete 

review until 

OI 3.0.3.2.18-1 is 

resolved (See 

SER Section 

3.5.2.2.2)

Vibration isolation 

elements

(3.5.1-41)

Reduction or 

loss of isolation

function/ 

radiation 

hardening,

temperature, 

humidity,

sustained 

vibratory 

loading

Structures 

Monitoring Program

Yes, if not 

within the 

scope of the 

applicant’s 

Structures 

Monitoring 

Program

Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.2)

Groups B1.1, B1.2,

and B1.3—support

members: anchor

bolts, welds

(3.5.1-42)

Cumulative 

fatigue damage 

(CLB fatigue 

analysis exists)

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes, TLAA Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.2.2)

Groups 1–3, 5, 6—

all masonry block 

walls 

(3.5.1-43)

Cracking due to 

restraint 

shrinkage, 

creep, and 

aggressive 

environment

Masonry Wall 

Program

No Masonry Wall 

Program is 

integrated into 

the Structures 

Monitoring 

Program and 

Fire Protection 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.8)

Group 6 elastomer 

seals, gaskets, and 

moisture barriers 

(3.5.1-44)

Loss of sealing 

due to 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Structures 

Monitoring Program

No Structures 

Monitoring 

Program 

Consistent with 

GALL Report
Aging Management Review Results

3-452

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Group 6—exterior 

above and belowgrade concrete 

foundation; interior 

slab 

(3.5.1-45)

Loss of material 

due to abrasion

and cavitation

Inspection of WaterControl Structures 

or FERC/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance

No Inspection of 

water-control 

structures 

associated with 

nuclear plants 

is integrated 

into the 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.3)

Group 5—fuel pool

liners 

(3.5.1-46)

Cracking due to 

SCC; loss of 

material due to 

pitting and 

crevice 

corrosion

Water chemistry 

and monitoring of 

spent fuel pool 

water level and 

level of fluid in the 

leak chase channel

No Water 

Chemistry 

Program 

Consistent with 

GALL Report

Group 6—all metal

structural members 

(3.5.1-47)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice

corrosion

Inspection of water 

control structures 

associated with 

nuclear power 

plants. If protective 

coatings are relied 

upon to manage 

aging, protective 

coating monitoring 

and maintenance

provisions should 

be included.

No Inspection of 

water-control 

structures 

associated with 

nuclear plants 

is integrated 

into the 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.3)

Group 6—earthen 

water control 

structures—dams, 

embankments,

reservoirs, 

channels, canals, 

and ponds 

(3.5.1-48)

Loss of 

material, loss of 

form due to 

erosion, 

settlement, 

sedimentation, 

frost action, 

waves, 

currents, 

surface runoff, 

Seepage

Inspection of watercontrol structures 

associated with 

nuclear power 

plants

No Inspection of 

water-control 

structures 

associated with 

nuclear plants 

is integrated 

into the 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.4)

Support members—

welds; bolted 

connections; 

support anchorage 

to building 

structures 

(3.5.1-49)

Loss of 

material/ 

general, pitting, 

and crevice 

corrosion

Water chemistry 

and ISI (IWF)

No Not applicable Not applicable to 

PWRs (See SER 

Section 3.5.2.1.1)
Aging Management Review Results

3-453

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Groups B2 and 

B4—galvanized 

steel, aluminum, 

stainless steel 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure

(3.5.1-50)

Loss of material 

due to pitting 

and crevice 

corrosion

Structures 

Monitoring Program

No Structures 

Monitoring 

Program 

Consistent with 

GALL Report

Group B1.1—high 

strength low-alloy 

bolts 

(3.5.1-51)

Cracking due to 

SCC and loss 

of material due 

to general 

corrosion

Bolting Integrity 

Program (XI.M18)

No Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.1.1)

Groups B2 and 

B4—sliding support 

bearings and sliding 

support surfaces

(3.5.1-52)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, 

fatigue due to

vibratory and 

cyclic thermal

loads

Structures 

Monitoring Program

No Structures 

Monitoring or 

IWF

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.1)

Groups B1.1, B1.2, 

and B1.3—support 

members: welds; 

bolted connections; 

support anchorage 

to building structure 

(3.5.1-53)

Loss of material 

due to general

and pitting 

corrosion

ISI (IWF) No ASME Code

Section XI, 

Subsection 

IWF Program 

Consistent with 

GALL Report

Groups B1.1, B1.2, 

and B1.3—Constant 

and variable load 

spring hangers; 

guides; stops 

(3.5.1-54)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, and 

fatigue due to 

vibratory and 

cyclic thermal

loads

ISI (IWF) No ASME Code

Section XI, 

Subsection 

IWF Program 

Consistent with 

GALL Report

Steel, galvanized 

steel, and aluminum 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-55)

Loss of material 

due to boric 

acid corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion 

Program 

Consistent with 

GALL Report
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Groups B1.1, B1.2, 

and B1.3—Sliding 

surfaces 

(3.5.1-56)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, and 

fatigue due to 

vibratory and 

cyclic thermal 

loads

ISI (IWF) No Structures 

Monitoring or 

IWF

Consistent with 

GALL Report (See 

SER Section 

3.5.2.1.1)

Groups B1.1, B1.2,

and B1.3—vibration 

isolation elements

(3.5.1-57)

Reduction or 

loss of isolation 

function/ 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory 

loading

ISI (IWF) No Not applicable Not applicable to 

Seabrook (See 

SER Section 

3.5.2.1.1)

Galvanized steel 

and aluminum 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

exposed to airindoor uncontrolled

(3.5.1-58)

None None No None Consistent with 

GALL Report

Stainless steel 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure

(3.5.1-59)

None None No None Consistent with 

GALL Report

The staff’s review of the structures and component supports 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 component groups 

is documented in SER Section 3.0.3.
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3.5.2.1 Aging Management Review Results Consistent with the GALL Report 

LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the structures and structural components and their commodity 

groups:

• ASME Code Section XI, Subsection IWE Program (B.2.1.27)

• ASME Code Section XI, Subsection IWL Program (B.2.1.28) 

• ASME Code Section XI, Subsection IWF Program (B.2.1.29) 

• Boral Monitoring Program (B.2.2.2) 

• Boric Acid Corrosion Program (B.2.1.4)

• Fire Protection Program (B.2.1.15) 

• Inspection of Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program (B.2.1.13)

• Structures Monitoring Program (B.2.1.31)

• Water Chemistry Program (B.2.1.2)

Although not identified directly in LRA Section 3.5.2.1, LRA Table 3.5.1 identifies the following 

additional programs under the discussion column that manage aging effects for the structures 

and structural components and their commodity groups for specified conditions:

• 10 CFR Part 50, Appendix J Program (B.2.1.30)

• TLAA Program (4.6)

LRA Tables 3.5.2-1 through 3.5.2-8 summarize AMRs for the structures and component 

supports component groups and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which it does not recommend further evaluation, the staff’s 

audit and review determined if 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–E, indicating how 

the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP.

The staff reviewed these items to verify consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff reviewed these items to verify consistency with the GALL Report and confirmed

that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. 

The staff also determined whether the applicant’s AMP was consistent with the GALL Report 

AMP and whether the AMR was valid for the site-specific conditions.
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Note C 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 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 reviewed 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 reviewed 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 the 

GALL Report AMPs have been reviewed and accepted. The staff also determined whether the 

applicant’s AMP was consistent with the GALL Report AMP and whether the AMR was valid for 

the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff reviewed 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.

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.

3.5.2.1.1 Aging Management Review Results Identified as Not Applicable

In Table 3.5.1, for items 3.5.1-5, 3.5.1-7, 3.5.1-8, 3.5.1-11, 3.5.1-13, 3.5.1-19, 3.5.1-20, 

3.5.1-21, and 3.5.1-22, the applicant states that the corresponding AMR items in the GALL 

Report are not applicable because Seabrook is a PWR design that incorporates a reinforced 

concrete containment structure that is enclosed by a reinforced concrete containment enclosure 

structure. The AMR items in the GALL Report are only applicable to particular components of 

BWR designs that use a steel containment or containment systems that use a post-tensioning 

system. The staff confirmed that the stated AMR items in the GALL Report are only applicable 

to BWR designs or post-tensioned concrete containments and are not applicable to the 

Seabrook LRA.

LRA Table 3.5.1, item 3.5.1-49, is associated with SRP-LR Table 3.5-1, ID 49, which addresses 

steel and stainless steel support members exposed to treated water. The GALL Report 

recommends the Water Chemistry and ASME Code Section XI, Subsection IWF Programs to 

manage loss of material. The applicant stated that this item applies only to BWR designs; 

however, the staff noted that two items in LRA Table 3.5.2-6 reference item 3.5.1-49 for ASME 

Code Class 2 and Class 3 stainless steel supports in raw water. One of these items includes 

plant-specific note 514, which says that aging will be managed through the Structures 

Monitoring Program. It is unclear to the staff how aging of these components will be managed 

during the period of extended operation. Therefore, by letter dated January 5, 2011, the staff 
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issued RAI 3.5.2.3.6-1 requesting that the applicant explain how aging of ASME Code Class 2

and Class 3 stainless steel supports will be managed.

By letter dated February 3, 2011, the applicant stated that the items were inadvertently 

addressed as “ASME Class 2/3 stainless steel supports” and should have been “Miscellaneous 

Mechanical Equipment stainless steel supports.” Accordingly, the applicant revised the 

associated LRA items to reference LRA Table 3.2.1, item 3.2.1-37, the Structures Monitoring 

Program, and generic note E.

The staff reviewed the applicant’s response and noted that based on the LRA revisions, the 

“BWR Only” comment associated with LRA item 3.5.1-49 is now accurate. The staff finds the 

applicant’s not applicable identification acceptable.

The staff also reviewed the applicant’s response to determine the acceptability of the updated 

reference to LRA Table 3.2.1, item 3.2.1-37, and associated Note E, as well as the use of the 

Structures Monitoring Program. The staff noted that for those items associated with 

item 3.2.1-37, the GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling 

Water System,” which recommends periodic visual inspections to manage loss of material. The 

staff noted that the applicant’s Structures Monitoring Program includes periodic visual 

inspections. The staff’s evaluation of the applicant’s Structures Monitoring Program is 

documented in SER Section 3.0.3.2.18. The staff finds the applicant’s RAI response and 

proposal to manage aging using the Structures Monitoring Program acceptable because 

monitoring for this aging effect is done through periodic visual inspections by individuals that 

conduct the inspections and review the results in accordance with ANSI/ASCE 11-90, 

“Guideline for Structural Condition Assessment of Existing Buildings.” The staff confirmed that 

ASME Code Class 2 and Class 3 stainless steel supports are included in the scope of the 

Structures Monitoring Program.

LRA Table 3.5.1, item 3.5.1-51 addresses high-strength, low-alloy steel bolts exposed to 

indoor-uncontrolled air. The GALL Report recommends the Bolting Integrity Program to 

manage cracking due to SCC and loss of material due to general corrosion for this component 

group. The applicant stated that this item is not applicable because there are no high-strength 

bolts that are subject to this aging effect. The staff evaluated the applicant’s claim and found 

that in the Bolting Integrity Program description, the applicant indicated that it did have 

high-strength bolts (greater than or equal to150 ksi) that are used in ASME Code Section XI

component support applications. The staff noted that three parameters must exist for SCC to 

occur in high-strength bolting. These parameters include a corrosive environment, a 

susceptible material, and high-sustained tensile stresses. Elimination or reduction in any of 

these three factors will decrease the likelihood of SCC occurring. The applicant stated that 

high-strength steel bolts used in ASME Code Section XI component support applications use 

slotted holes and double nuts in lieu of prestressing and are not subject to high-sustained 

preload stress. Additionally, the applicant stated that lubricants containing molybdenum 

disulfide or unacceptable levels of contaminants are not approved for use on these bolts. 

Therefore, the applicant concluded that SCC is not considered an applicable aging mechanism 

requiring management. The applicant is using the ASME Code Section XI, Subsection IWF 

Program to manage aging of these components. The staff finds the applicant’s use of the 

ASME Code Section XI, Subsection IWF Program acceptable because these bolts are not 

susceptible to SCC, and this program uses visual inspection that is capable of detecting loss of 

material.
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LRA Table 3.5.1, items 3.5.1-52 and 3.5.1-56, address Lubrite® sliding surfaces exposed to an 

uncontrolled air environment. The GALL Report recommends the Structures Monitoring 

Program and ASME Code Section XI, Subsection IWF Program, respectively, to manage these 

components for loss of mechanical function. The applicant stated that these items are not 

applicable because there are no sliding support bearings of surfaces at Seabrook that are 

subject to this aging effect. However, the staff noted that items in LRA Tables 3.5.2-1, 3.5.2-5, 

and 3.5.2-6 reference item 3.5.1-52 or 3.5.1-56. Because of this apparent contradictory 

information, it is unclear to the staff how aging of these components will be managed during the 

period of extended operation. Therefore, by letter dated January 5, 2011, the staff issued 

RAI 3.5.2.3.6-2 requesting that the applicant explain if there are any sliding support surfaces in 

the scope of license renewal and, if so, how aging of the supports will be managed.

By letter dated February 3, 2011, the applicant explained that sliding support surfaces were 

inadvertently omitted from LRA Table 3.5.1. Therefore, the applicant revised the discussion 

column of items 3.5.1-52 and 3.5.1-56 to note that the items were consistent with NUREG-1801,

and aging is managed by the Structures Monitoring Program or the IWF Program, as

recommended by the GALL Report.

The staff reviewed the applicant’s response and finds it acceptable because it aligns LRA 

Table 3.5.1 with the associated items in LRA Tables 3.5.2-1, 3.5.2-5, and 3.5.2-6. It also aligns 

the LRA with the recommendations in the GALL Report. The staff’s concern described in 

RAI 3.5.2.3.6-2 is resolved.

For item 3.5.1-57, the applicant claimed that it was 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 this item.

The remaining items identified as not applicable in LRA Table 3.5.1 require further evaluation 

and are discussed in the corresponding subsections of SER Section 3.5.2.2.

3.5.2.1.2 Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw

LRA Table 3.5.1, item 3.5.1-35, addresses discharge transition structure and revetment 

concrete exposed to outdoor air that is being managed for loss of material (spalling, scaling)

and cracking due to freeze-thaw. The LRA credits the Structures Monitoring Program to 

manage these aging effects. The GALL Report recommends GALL Report AMP XI.S7, 

“Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants,” to ensure that these aging effects are adequately managed for accessible areas. 

Several associated AMR items cite generic note E and plant-specific note 511, which states that 

the RG 1.127 AMP is incorporated into the applicant’s Structures Monitoring Program.

GALL Report AMP XI.S7 recommends monitoring and visual inspection at intervals not to 

exceed 5 years for indications of cracking, movements (e.g., settlement, heaving, deflection), 

conditions at junctions with abutments and embankments, erosion, cavitation, seepage, and 

leakage to manage the aging of these items. In its review of components associated with 

item 3.5.1-35, for which the applicant cited generic note E, the staff noted that the Structures 

Monitoring Program proposes to manage aging of concrete exposed to outdoor air-outdoor

through the use of periodic visual inspections at an interval not to exceed 5 years.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with item 3.5.1-35, the staff finds the 

applicant’s proposal to manage aging using the Structures Monitoring Program acceptable 
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because monitoring for aging effects is done through periodic visual inspections. The staff 

noted that deficiencies are identified in accordance with ACI 201.1R and that periodic 

inspections are conducted on a 5-year basis. The staff also noted that the applicant’s 

Structures Monitoring Program incorporates the guidance of the RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program,” and is consistent 

with GALL Report AMP XI.S7, which is identified as the appropriate AMP in the GALL Report.

The staff concludes that the applicant 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).

3.5.2.1.3 Loss of Material Due to Abrasion, Cavitation and Loss of Material Due to General 

(steel only), Pitting and Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-45, addresses concrete exposed to a raw water (external) 

environment being managed for loss of material due to abrasion and cavitation. The LRA 

credits the Structures Monitoring Program to manage this aging effect. The GALL Report 

recommends GALL Report AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants,” to ensure that this aging effect is adequately 

managed. Several associated AMR items cite generic note E, and plant-specific note 511,

which states that the RG 1.127 AMP is incorporated into the applicant’s Structures Monitoring 

Program.

GALL Report AMP XI.S7 recommends monitoring and inspection at intervals not to exceed 

5 years for indications of cracking, movements (e.g., settlement, heaving, deflection), conditions 

at junctions with abutments and embankments, erosion, cavitation, seepage, and leakage to 

manage the aging of these items. In its review of components associated with item 3.5.1-45, for 

which the applicant cited generic note E, the staff noted that the Structures Monitoring Program 

proposes to manage aging of concrete exposed to raw water (external) through the use of 

periodic visual inspections at an interval not to exceed 5 years.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with item 3.5.1-45, the staff finds the 

applicant’s proposal to manage concrete aging using the Structures Monitoring Program 

acceptable because monitoring for aging effects is done through periodic visual inspections. 

The staff noted that deficiencies are identified in accordance with ACI 201.1R and that the 

periodic inspections are conducted on a 5-year basis. The staff also noted that the applicant’s 

Structures Monitoring Program incorporates the guidance of the RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program,” and is consistent 

with GALL Report AMP XI.S7, which is identified as the appropriate AMP in the GALL Report.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

LRA Table 3.5.1, item 3.5.1-47, addresses carbon steel exposed to air-outdoor or raw water and 

stainless steel exposed to an air-outdoor environment, being managed for loss of material due 

to general (steel only), pitting, and crevice corrosion. The LRA credits the Structures Monitoring 

Program to manage this aging effect. The GALL Report recommends GALL Report AMP XI.S7, 
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“Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants,” to ensure that this aging effect is adequately managed. Several associated AMR items 

cite generic note E and plant-specific note 511, which state that the RG 1.127 AMP is 

incorporated into the applicant’s Structures Monitoring Program, often in tandem with plantspecific note 503 or plant-specific note 509. Plant-specific note 503 states that aging effects 

include crevice and pitting corrosion along with loss of material corrosion due to a saltwater 

atmosphere environment. Plant-specific note 509 states that the referenced item(s) are buried, 

below grade, soil, and groundwater, where raw and treated water environments are treated the 

same.

GALL Report AMP XI.S7 recommends monitoring and visual inspection at intervals not to 

exceed 5 years to determine structural integrity. In its review of components associated with

item 3.5.1-47, for which the applicant cited generic note E, the staff noted that the Structures 

Monitoring Program proposes to manage aging of carbon steel exposed to air-outdoor or raw 

water and stainless steel exposed to an air-outdoor environment through the use of periodic 

visual inspections at an interval not to exceed 5 years.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with item 3.5.1-47, the staff finds the 

applicant’s proposal to manage aging using the Structures Monitoring Program acceptable 

because monitoring for aging effects is done through periodic visual inspections. The staff 

noted that the applicant’s Structures Monitoring Program incorporates the guidance of 

RG 1.127, and is consistent with GALL Report AMP XI.S7, which is identified as the appropriate 

AMP in the GALL Report.

The staff concludes that the applicant 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).

3.5.2.1.4 Loss of Material and Loss of Form Due to Erosion, Settlement, Sedimentation, Frost 

Action, Waves, Currents, Surface Runoff, and Seepage

LRA Table 3.5.1, item 3.5.1-48, addresses a rock (riprap) revetment exposed to an air-outdoor 

environment that is being managed for loss of material and loss of form. The LRA credits the 

Structures Monitoring Program to manage these aging effects. The GALL Report recommends 

GALL Report AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” to ensure that these aging effects are adequately 

managed. The associated AMR items cite generic note E and plant-specific note 511, which 

state that the RG 1.127 AMP is incorporated into the applicant’s Structures Monitoring Program.

GALL Report AMP XI.S7 recommends monitoring and inspection at intervals not to exceed 

5 years for indications of cracking, movements (e.g., settlement, heaving, deflection), conditions 

at junctions with abutments and embankments, erosion, cavitation, seepage, and leakage to 

manage the aging of these items. In its review of components associated with item 3.5.1-48, for 

which the applicant cited generic note E, the staff noted that the Structures Monitoring Program 

proposes to manage aging of the rock (riprap) revetment exposed to air-outdoor through the use 

of periodic visual inspections at an interval not to exceed 5 years.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with item 3.5.1-48, the staff finds the 
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applicant’s proposal to manage aging using the Structures Monitoring Program acceptable 

because monitoring for aging effects is done through periodic visual inspections. The staff 

noted that the applicant’s Structures Monitoring Program incorporates the guidance of 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program,” and is consistent with GALL Report AMP XI.S7, which is identified as the appropriate 

AMP in the GALL Report.

The staff concludes that the applicant 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).

3.5.2.1.5 Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Aggressive 

Chemical Attack

LRA Table 3.5.1, item 3.5.1-34, addresses concrete exposed to an air-indoor or air-outdoor 

environment that is being managed for cracking, loss of bond, and loss of material (spalling, 

scaling) due to aggressive chemical attack. The LRA credits the Structures Monitoring Program 

to manage these aging effects. The GALL Report recommends GALL Report AMP XI.S7, 

“Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants,” to ensure that these aging effects are adequately managed. The associated AMR 

items cite generic note E and plant-specific note 511, which state that the RG 1.127 AMP is 

incorporated into the applicant’s Structures Monitoring Program.

GALL Report AMP XI.S7 recommends monitoring and inspection at intervals not to exceed 

5 years for indications of cracking, movements (e.g., settlement, heaving, deflection), conditions 

at junctions with abutments and embankments, erosion, cavitation, seepage, and leakage to 

manage the aging of these items. In its review of components associated with item 3.5.1-34, for 

which the applicant cited generic note E, the staff noted that the Structures Monitoring Program 

proposes to manage aging of concrete exposed to an air-indoor or air-outdoor environment 

through the use of periodic visual inspections at an interval not to exceed 5 years.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with item 3.5.1-34, the staff finds the 

applicant’s proposal to manage aging using the Structures Monitoring Program acceptable 

because monitoring for aging effects is done through periodic visual inspections. The staff 

noted that the deficiencies are identified in accordance with ACI 201.1R. The staff also noted 

that the applicant’s Structures Monitoring Program incorporates the guidance of RG 1.127, 

“Inspection of Water-Control Structures Associated with Nuclear Power Plants Program,” and is 

consistent with GALL Report AMP XI.S7, which is identified as the appropriate AMP in the 

GALL Report.

The staff concludes that the applicant 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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3.5.2.1.6 Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling)

Due to Aggressive Chemical Attack, and Loss of Strength Due to Leaching of 

Calcium Hydroxide

LRA Table 3.5.1, item 3.5.1-24, addresses concrete exposed to an air-indoor or air-outdoor 

environment that is being managed for increase in porosity and permeability, cracking, and loss 

of material (scaling, spalling) due to aggressive chemical attack. For two items, the LRA credits 

the Fire Protection Program to manage these aging effects. The GALL Report recommends 

GALL Report AMP XI.S6, “Structural Monitoring Program,” to ensure that these aging effects 

are adequately managed. The associated AMR items cite generic note E.

GALL Report AMP XI.S6 selects parameters to be monitored or inspected for each structure

and aging effect combination to ensure that aging degradation leading to loss of intended 

function will be detected and the extent of degradation detected. Inspection methods, 

inspection schedule, and inspector qualifications are to be commensurate with industry codes, 

standards, and guidelines. For concrete structures, this usually consists of visual inspections on 

a 5- or 10-year interval. In its review of components associated with item 3.5.1-24, for which the 

applicant cited generic note E, the staff noted that the Fire Protection Program proposes to 

manage increase in porosity and permeability, cracking, and loss of material (scaling, spalling) 

of concrete exposed to an air environment through the use of periodic visual inspections.

The staff’s evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.7. 

In its review of components associated with item 3.5.1-24, the staff finds the applicant’s 

proposal to manage aging acceptable because exposed surfaces are inspected at 18-month 

intervals for indications of increase in porosity and permeability, cracking, and loss of material 

(spalling, scaling). The staff noted that the inspection results are acceptable if there are no 

visual indications of cracking, spalling, and loss of material. In addition, the staff noted that the 

components are also being inspected by the Structures Monitoring Program, which is the GALL 

Report recommended program.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

LRA Table 3.5.1, item 3.5.1-34, addresses below-grade concrete exposed to soil that is being 

managed for increase in porosity and permeability, cracking, and loss of material (scaling, 

spalling) due to aggressive chemical attack. The LRA credits the Structures Monitoring 

Program to manage these aging effects. The GALL Report recommends GALL Report 

AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants,” to ensure that these aging effects are adequately managed. The 

associated AMR items cite generic note E and plant-specific note 511, which states that the 

RG 1.127 AMP is incorporated into the applicant’s Structures Monitoring Program.

GALL Report AMP XI.S7 recommends monitoring and inspection at intervals not to exceed 

5 years for indications of cracking, movements (e.g., settlement, heaving, deflection), conditions 

at junctions with abutments and embankments, erosion, cavitation, seepage, and leakage to 

manage the aging of these items. In its review of components associated with item 3.5.1-34, for 

which the applicant cited generic note E, the staff noted that the Structures Monitoring Program 

proposes to manage aging of below-grade concrete exposed to soil through the use of periodic 

visual inspections and monitoring of the aggressiveness of the groundwater.
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The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. In its review of components associated with item 3.5.1-34, the staff finds the 

applicant’s proposal to manage aging using the Structures Monitoring Program acceptable 

because monitoring for aging effects is done through periodic inspections. The staff also noted 

that examinations of inaccessible areas will be completed during inspections of opportunity or, if 

no opportunistic inspections are performed during a 5-year period, a focused inspection is 

required. Additionally, groundwater is tested at 5-year intervals, and testing of concrete to 

determine the effects of aggressive groundwater is scheduled during the second and third 

quarter of 2010. The staff further noted that the applicant’s Structures Monitoring Program 

incorporates the guidance of the RG 1.127, “Inspection of Water-Control Structures Associated 

with Nuclear Power Plants Program,” and is consistent with GALL Report AMP XI.S7, which is 

identified as the appropriate AMP in the GALL Report.

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

LRA Table 3.5.1, item 3.5.1-37, addresses concrete exposed to a raw water or soil environment 

being managed for increase in porosity and permeability and loss of strength due to leaching of 

calcium hydroxide. The LRA credits the Structures Monitoring Program to manage these aging 

effects. The GALL Report recommends GALL Report AMP XI.S7, “Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants,” to ensure that 

these aging effects are adequately managed. The associated AMR items cite generic note E 

and plant-specific note 511, which states that the RG 1.127 AMP is incorporated into the 

applicant’s Structures Monitoring Program. Below grade concrete revetment items under this 

LRA table number also list generic note 509, which states that buried, below grade, soil, and 

groundwater, raw and treated water environments for these items are considered the same.

GALL Report AMP XI.S7 recommends monitoring and inspection at intervals not to exceed 

5 years for indications of cracking, movements (e.g., settlement, heaving, deflection), conditions 

at junctions with abutments and embankments, erosion, cavitation, seepage, and leakage to 

manage the aging of these items. In its review of components associated with item 3.5.1-37, for 

which the applicant cited generic note E, the staff noted that the Structures Monitoring Program 

proposes to manage aging of concrete exposed to raw water or soil through the use of periodic 

visual inspections.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. Pending the resolution of OI 3.0.3.2.18-1, the staff can not complete its 

evaluation of this AMR item.

The staff finds that for LRA Item 3.5.1-37, OI 3.0.3.2.18-1 must be resolved before the staff can 

conclude 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.
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3.5.2.1.7 Cracking Due to Expansion and Reaction with Aggregates3

LRA Table 3.5.1, item 3.5.1-36, addresses concrete exposed to air-indoor or air-outdoor, raw 

water, or soil environments being managed for expansion and cracking. The LRA credits the 

Structures Monitoring Program to manage these aging effects. The GALL Report recommends 

GALL Report AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” to ensure that these aging effects are adequately 

managed. The associated AMR items cite generic note E and plant-specific note 511, which 

states that the RG 1.127 AMP is incorporated into the applicant’s Structures Monitoring 

Program.

GALL Report AMP XI.S7 recommends monitoring and inspection at intervals not to exceed 

5 years for indications of cracking, movements (e.g., settlement, heaving, deflection), conditions 

at junctions with abutments and embankments, erosion, cavitation, seepage, and leakage to 

manage the aging of these items. In its review of components associated with item 3.5.1-36, for 

which the applicant cited generic note E, the staff noted that the Structures Monitoring Program 

proposes to manage aging of concrete exposed to air-indoor or air-outdoor, raw water, or soil 

environments through the use of periodic visual inspections at an interval not to exceed 5 years.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. Pending the resolution of OI 3.0.3.2.18-1, the staff can not complete its 

evaluation of this AMR item.

The staff finds that for LRA Item 3.5.1-36, OI 3.0.3.2.18-1 must be resolved before the staff can 

conclude 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.

3.5.2.1.8 Cracking Due to Restraint Shrinkage, Creep, and Aggressive Environment

LRA Table 3.5.1, item 3.5.1-43, addresses concrete masonry block walls exposed to air-indoor 

uncontrolled and air-outdoor environments that are being managed for cracking. Several items 

in the LRA credit the Fire Protection Program to manage this aging effect. The GALL Report 

recommends GALL Report AMP XI.S5, “Masonry Wall Program,” to ensure that these aging 

effects are adequately managed. The associated AMR items cite generic note E supplemented 

for fire pump house fire barriers and SBO structures supports with plant-specific note 513, which 

identifies the Fire Protection Program to manage the aging effects for cracking. The 

non-essential switch gear building supports are supplemented with plant-specific note 511, 

which states that the XI.S7, “RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants,” and the XI.S5, “Masonry Wall Program,” guidance are incorporated into 

the applicant’s Structures Monitoring Program.

GALL Report AMP XI.S5 performs visual examination of the masonry walls by qualified 

inspection personnel for cracking of the masonry and degradation of steel edge supports and 

bracing at a frequency to ensure that there is no loss of intended function between inspections. 

In its review of components associated with item 3.5.1-43, for which the applicant cited generic 

note E, the staff noted the Fire Protection Program proposes to manage aging of concrete 

masonry unit structures through the use of periodic visual inspections.

 3 The applicant submitted a supplement to the LRA dated May 16, 2012, which addresses a plant-specific aging management 

program entitled "Alkali-Silica Reaction Monitoring Program." The staff is currently reviewing this supplement, and therefore, its 

evaluation is not included in this SER with open items. 
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The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.7. In its review of components associated with item 3.5.1-43, the staff finds the 

applicant’s proposal to manage aging using the Fire Protection Program acceptable because 

monitoring of exposed surfaces is done through inspections at 18-month intervals for indications 

of increase in porosity and permeability, cracking, loss of material (spalling, scaling), and loss of 

strength. The staff noted that inspection results are acceptable if there are no visual indications 

of cracking, spalling, and loss of material caused by freeze-thaw, chemical attack, and 

aggregate reactions. In addition, the staff noted that the additional non-essential switch gear 

building supports are also being inspected by the Structures Monitoring Program, which 

incorporates the recommendations of the GALL recommended program, AMP XI.S5, “Masonry 

Wall Program.”

The staff concludes that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.2 Aging Management Review Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended 

In LRA Section 3.5.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the containments, structures, and component supports and provides 

information concerning how it will manage aging effects in the following areas:

• PWR and BWR Containments

– aging of inaccessible concrete areas

– cracks and distortion due to increased stress levels from settlement; reduction of

foundation strength, cracking, and differential settlement due to erosion of porous 

concrete subfoundations if not covered by the Structures Monitoring Program

– reduction of strength and modulus of concrete structures due to elevated 

temperature

– loss of material due to general, pitting, and crevice corrosion

– loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

– cumulative fatigue damage

– cracking due to SCC

– cracking due to cyclic loading

– loss of material (scaling, cracking, and spalling) due to freeze-thaw

– cracking due to expansion and reaction with aggregate and increase in porosity 

and permeability due to leaching of calcium hydroxide

• Safety-related and other structures and component supports:

– aging of structures not covered by the Structures Monitoring Program

– aging management of inaccessible areas (below-grade inaccessible concrete 

areas of Groups 1–5 and 7–9 structures) 
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– reduction of strength and modulus of concrete structures due to elevated 

temperature for Group 1–5 structures

– aging management of inaccessible areas for Group 6 structures (below-grade 

inaccessible concrete areas)

– cracking due to SCC and loss of material due to 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 due to cyclic loading

• 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 if 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 Pressurized-Water Reactor and Boiling-Water Reactor Containments

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1, which 

addresses several areas, as described below.

Aging of Inaccessible Concrete Areas

The staff’s evaluation of the applicant’s ASME Code Section XI, Subsection IWL Program is 

documented in SER Section 3.0.3.2.17. The staff noted that aging management of all 

accessible areas of the concrete containment building for cracking, loss of material, and 

increase in porosity and permeability is managed by the ASME Code Section XI, 

Subsection IWL Program. The staff also notes that since the below-grade environment is 

aggressive, the applicant will continue to monitor it for aggressiveness during the period of 

extended operation, as well as conduct focused or opportunistic inspections of inaccessible 

foundations during a 5-year interval, and concrete testing and rebar inspections will be 

. LRA Section 3.5.2.2.1.1 associated with LRA 

Table 3.5.1, item 3.5.1-1, addresses aging of inaccessible concrete areas, which are being 

managed for aggressive chemical attack and corrosion of embedded steel by the ASME Code

Section XI, Subsection IWL Program. The criteria in SRP-LR Section 3.5.2.2.1.1 states that 

increases in porosity and permeability, cracking, loss of material (spalling, scaling) due to 

aggressive chemical attack, and cracking, loss of bond, and loss of material (spalling, scaling) 

due to corrosion of embedded steel could occur in inaccessible areas of PWR and BWR 

concrete and steel containments. The GALL Report identifies ASME Code Section XI, 

Subsection IWL to manage these aging effects and recommends further evaluation of 

plant-specific programs to manage these aging effects for inaccessible areas if the environment 

is aggressive. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that the groundwater at Seabrook is aggressive in that chloride levels between 19–3,900 ppm 

were obtained during testing from November 2008 to September 2009. The LRA states that,

under the Structures Monitoring Program, examinations of inaccessible areas will be completed 

during inspections of opportunity or, if no opportunistic inspections are performed during a 

5-year period, a focused inspection is required. Additionally, groundwater will be tested at 

5-year intervals, and testing of concrete and inspections of rebar are scheduled to determine the 

effects of aggressive groundwater.
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performed to indicate the condition of below-grade concrete. In addition, the staff issued 

RAIs B.2.1.28-3 and B.2.1.31-1 under the IWL and Structures Monitoring Programs (SER 

Sections 3.0.3.2.17 and 3.0.3.2.18, respectively) requesting information on how the applicant 

will continue to verify the adequacy of concrete exposed to aggressive groundwater during the 

period of extended operation. This issue, including the applicant’s response to the RAIs and the 

staff’s review, is discussed in detail in those sections. 

The staff is concerned that the inaccessible areas of the concrete containment may be exposed 

to the ASR since recent plant specific operating experience indicate presence of ASR in 

accessible portions of other concrete structures located close to the containment. Presence of 

ASR in the inaccessible portion of the concrete containment may result in an increase in rate of 

degradation of concrete due to porosity and permeability, cracking, and loss of material 

(spalling, scaling) due to aggressive chemical attack. The Structures Monitoring Program has to 

be enhanced to account for this phenomenon. This is being tracked as Open Item OI 

3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff can 

not complete its evaluation of components associated with item 3.5.1-1.

Cracks and Distortion due to Increased Stress Levels from Settlement; Reduction of Foundation 

Strength, Cracking, and Differential Settlement due to Erosion of Porous Concrete 

Subfoundations, if Not Covered by the Structures Monitoring Program

In its review of components associated with items 3.5.1-2 and 3.5.1-3, the staff noted that the 

applicant did not state that the Structures Monitoring Program will continue to inspect for 

possible signs of settlement. In addition, although a dewatering system is not used to control 

settlement, a dewatering system has been installed in an attempt to control groundwater 

leakage. Therefore, by letter dated January 5, 2011, the staff issued RAI 3.5.2.2.1.2-1 

requesting that the applicant justify not including degradation due to settlement within the scope 

of the Structures Monitoring Program and explain whether or not the dewatering program has 

had any effect on settlement.

. LRA Section 3.5.2.2.1.2, 

associated with LRA Table 3.5.1, items 3.5.1-2 and 3.5.1-3, addresses concrete components 

being managed for cracks and distortion due to increased stress levels from settlement and 

reduction of foundation strength, cracking, and differential settlement due to erosion of porous 

concrete subfoundations by the Structures Monitoring Program. The criteria in SRP-LR 

Section 3.5.2.2.1.2 states that cracks and distortion due to increased stress levels from 

settlement and reduction in foundation strength, cracking, and differential settlement due to 

erosion of porous concrete subfoundations could occur. The GALL Report identifies the 

Structures Monitoring Program to manage these aging effects, and no further evaluation is 

recommended if this activity is within scope of the Structures Monitoring Program. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that Seabrook 

structures are founded on sound bedrock, fill concrete, or consolidated backfill; there are no 

porous concrete subfoundations; the foundations are not subject to flowing water; and a 

dewatering system is not relied upon for control of settlement.

In its response dated February 3, 2011, the applicant stated that, historically, no indications of 

building settlements, such as cracking or warping of structural elements, have been identified 

with the exception of an isolated incident in the fuel storage building where deck plate seating 

alignment has been an issue. The applicant is actively monitoring this through laser targets to 

establish a baseline. Moreover, the applicant stated that the Structures Monitoring Program will 

continue to inspect for signs of settlement during the period of extended operation.
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The staff finds the applicant’s response acceptable because the applicant has no experience 

with settlement, and it monitors unusual occurrences. Additionally, the Structures Monitoring 

Program will continue to inspect for signs of settlement during the period of extended operation. 

The staff’s concern described in RAI 3.5.2.2.1.2-1 is resolved.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff noted that structures and structural components are monitored 

under the applicant’s Structures Monitoring Program for aging effects related to settlement. The 

staff also noted that the applicant does not have porous concrete subfoundations or a 

dewatering system to control settlement, and all of its Seismic Category I structures are founded 

on solid, non-compressible material. In its review of components associated with items 3.5.1-2 

and 3.5.1-3, the staff finds the applicant’s proposal to manage aging using the Structures 

Monitoring Program acceptable because this is the GALL Report recommended program, and 

all necessary components are within the program’s scope.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1.2 criteria. For those items that apply to LRA Section 3.5.2.2.1.2, the 

staff determined that the LRA is consistent with the GALL Report, and the applicant 

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).

Reduction of Strength and Modulus of Concrete Structures due to Elevated Temperature. LRA 

Section 3.5.2.2.1.3, associated with LRA Table 3.5.1, item 3.5.1-4, addresses reduction of 

strength and modulus of concrete structures exposed to elevated temperatures. The applicant 

stated that this item is not applicable because concrete is not exposed to temperatures above 

the limits. The applicant also stated that the containment structure cooling subsystem is 

designed to maintain the normal ambient air temperature in the containment structure at or 

below 120  ̊F and functions to prevent the concrete temperature in the area of the reactor 

supports from exceeding 135  ̊F during normal operation. The applicant further stated that if a 

pipe carries a hot fluid, the space between the pipe and sleeve is insulated to maintain the 

concrete temperature adjoining the sleeve at or below 200  ̊F during normal plant operation. 

The GALL Report recommends further evaluation for any concrete elements that exceed the 

specified temperature limits of 150  ̊F general and 200  ̊F local. The staff reviewed LRA 

Sections 2.3.3.4 and 3.5, and reviewed the UFSAR, and confirmed that the containment cooling 

system is within the scope of license renewal and that no in-scope containment concrete is 

exposed to temperatures exceeding the GALL Report limits; therefore, it finds the applicant’s 

determination acceptable.

Loss of Material due to General, Pitting and Crevice Corrosion. LRA Section 3.5.2.2.1.4, 

associated with LRA Table 3.5.1, items 3.5.1-5 (not applicable; applies only to BWRs) and 

3.5.1-6, addresses steel elements of accessible and inaccessible areas of containments, which 

are being managed for loss of material due to 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 the ASME 

Code Section XI, Subsection IWE and 10 CFR Part 50, Appendix J Programs will be used to 

manage aging of accessible and inaccessible areas of the containment structure steel elements 

due to general, pitting, and crevice corrosion. The applicant also stated that the seismic 

isolation material between the fill mat and the containment liner is sealed at the mat surface with 

caulk, and the caulked joint is examined for signs of degradation under the ASME Code

Section XI, Subsection IWL Program inspections. The applicant further stated that the ASME 
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Code Section XI, Subsection IWL Program is used to manage concrete aging effects. LRA 

Section 3.5 states that the concrete structures were designed in accordance with ACI 318 and 

constructed in accordance with ACI 301, ASTM standards, and recommendations equivalent to 

ACI 201.2R.

The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4,

which states that loss of material due to general, pitting, and crevice corrosion could occur in 

steel elements of accessible and inaccessible areas for all types of PWR and BWR 

containments. The existing program relies on ASME Code Section XI Subsection IWE, and 

10 CFR Part 50, Appendix J Programs to manage this aging effect. The GALL Report 

recommends further evaluation of plant-specific programs to manage this aging effect for 

inaccessible areas if corrosion is significant. GALL Report item II.A1-11 states that for 

inaccessible areas (embedded steel shell or liner), loss of material due to corrosion is not 

significant if the following four conditions are satisfied: 

(1) Concrete meeting the specifications of ACI 318 or 349 and the guidance of ACI 201.2R 

was used for the containment concrete in contact with the embedded containment shell 

or liner.

(2) The concrete is monitored to ensure that it is free of penetrating cracks that provide a 

path for water seepage to the surface of the containment shell or liner.

(3) The moisture barrier, at the junction where the shell or liner becomes embedded, is 

subject to aging management activities in accordance with ASME Code Section XI, 

Subsection IWE requirements.

(4) Water ponding on the containment concrete floor is not common and, when detected, is 

cleaned up in a timely manner.

During its review, the staff noted that although the applicant adequately addressed three of the 

four conditions discussed in the GALL Report, the LRA did not discuss the fourth condition. By 

letter dated January 5, 2011, the staff issued RAI 3.5.2.2.1.4-1 requesting that the applicant 

discuss Seabrook experience with water ponding on the containment floor.

In its response dated February 3, 2011, the applicant stated that the plant has no operating 

experience related to water ponding on the containment floor. The applicant explained that the 

design of the containment incorporates floors sloped towards the trench and sump system to 

prevent water ponding.

The staff reviewed the applicant’s response and finds it acceptable because the applicant 

explained that there is no plant-specific operating experience regarding water ponding on the 

containment floor. The staff’s concern described in RAI 3.5.2.2.1.4-1 is resolved.

The staff’s reviews of the applicant’s ASME Code Section XI, Subsection IWL Program, ASME 

Code Section XI, Subsection IWE Program, and 10 CFR Part 50, Appendix J Program are 

documented in SER Sections 3.0.3.2.17, 3.0.3.1.9, and 3.0.3.1.11, respectively. The staff noted 

that the concrete structures were designed in accordance with ACI 318 and constructed in 

accordance with ACI 301, ASTM standards, and recommendations equivalent to ACI 201.2R. 

The concrete and the moisture barrier where the liner becomes embedded are monitored under 

the ASME Code Section XI, Subsection IWL Program. The staff also confirmed that the 

containment internal concrete structures are within the scope of the Structures Monitoring 

Program and are visually inspected for penetrating cracks under that program. In addition, the 

staff reviewed the UFSAR and confirmed that the applicant has measures in place to alleviate 
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accumulation of water in the containment. The staff finds that the applicant met the further 

evaluation criteria, and the applicant’s proposal to manage aging is acceptable because the 

applicant satisfied the four conditions listed above, and the applicant is using the GALL Report 

recommended inspection programs.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1.4 criteria. For those items that apply to LRA Section 3.5.2.2.1.4, the 

staff determined that the LRA is consistent with the GALL Report, and the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA 

Section 3.5.2.2.1.5, associated with LRA Table 3.5.1, item 3.5.1-7, addresses loss of prestress 

due to relaxation, shrinkage, creep, and elevated temperature in prestressed containment 

tendons. In the LRA, the applicant stated that this item is not applicable because the 

containment structure does not use a prestressed concrete containment design so there are no 

prestressing tendons. The staff finds the applicant’s determination acceptable on the basis that 

the containment is a reinforced concrete containment with no prestressing tendons.

Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 associated with LRA Table 3.5.1, 

items 3.5.1-8 (not applicable; applies only to BWRs) and 3.5.1-9, states that TLAAs are 

evaluated in accordance with 10 CFR54.21(c) and that the evaluation of this TLAA is addressed 

in Section 4.6.2. This is consistent with SRP-LR Section 3.5.2.2.1.6 and is, therefore, 

acceptable.

Cracking due to Stress Corrosion Cracking. LRA Section 3.5.2.2.1.7, associated with LRA 

Table 3.5.1, items 3.5.1-10 and 3.5.1-11 (not applicable; applies only to BWRs), addresses 

cracking due to SCC in stainless steel penetration sleeves, penetration bellows, and dissimilar 

metal welds exposed to an air environment. The GALL Report recommends ASME Code

Section XI, Subsection IWE and 10 CFR Part 50, Appendix J Programs, as well as additional 

examinations as appropriate to manage SCC for this component group. In the LRA, the 

applicant stated that these items are not applicable because no in-scope stainless steel 

penetration sleeves, penetration bellows, or dissimilar metal welds are subject to SCC. The 

staff evaluated the applicant’s claim and found it acceptable because the Seabrook penetration 

sleeves, bellows, and dissimilar metal welds are not subject to a combination of high 

temperature (greater than 140  ̊F) and exposure to an aggressive environment, and 

plant-specific operating experience did not identify any SCC in these components.

Cracking Due to Cyclic Loading. LRA Section 3.5.2.2.1.8, associated with LRA Table 3.5.1, 

items 3.5.1-12 and 3.5.1-13, addresses cracking due to cyclic loading in penetration sleeves 

and bellows exposed to an air environment. In the LRA, the applicant stated that item 3.5.1-12 

is not an aging effect requiring management, and analyses of the containment penetrations are 

not considered TLAAs. The applicant also stated that these components were designed to 

withstand operating stress levels and, as such, cracking due to cyclic loading is unlikely to 

occur, the plant will continue to operate within the design envelope in the period of extended 

operation, and plant operating experience has not identified any events related to cyclic 

loading-induced cracking of containment components. The applicant further stated that 

item 3.5.1-13 is not applicable because it applies only to BWR plants. The staff confirmed that 

fatigue of containment penetrations is not applicable because it applies only to BWR plants. 
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The lack of a TLAA is addressed in LRA Section 4.6.2, and the staff’s review is documented in 

the corresponding SER section.

Loss of Material (Scaling, Cracking, and Spalling) due to Freeze-Thaw. LRA 

Section 3.5.2.2.1.9, associated with LRA Table 3.5.1, item 3.5.1-14, addresses loss of material 

(scaling, cracking, and spalling) in concrete elements due to freeze-thaw. The GALL Report 

recommends further evaluation of inaccessible areas for plants located in moderate to severe 

weathering conditions. In the LRA, the applicant stated that this item is not applicable because 

the Seabrook containment is enclosed by a concrete containment enclosure building and,

therefore, is not exposed to severe weathering conditions. The staff confirmed that the 

containment is located in a concrete containment enclosure building and, therefore, is not 

subject to this AERM. Management of the enclosure building and other exterior concrete in the 

scope of license renewal is discussed in SER Section 3.5.2.2.2.

Cracking due to Expansion, and Reaction with Aggregate, and Increase in Porosity and 

Permeability due to Leaching of Calcium Hydroxide4

The staff’s reviews of the applicant’s ASME Code Section XI, Subsection IWL and Structures 

Monitoring Programs are documented in SER Sections 3.0.3.2.17 and 3.0.3.2.18, respectively. 

In its review of components associated with item 3.5.1-15, the staff noted that the applicant 

used the appropriate ASTM standards to test for aggregate reactivity; however, recent 

plant-specific operating experience has indicated that alkali-aggregate reactions are occurring 

onsite. To address this operating experience, the staff issued RAIs B.2.1.28-3 and B.2.1.31-1 

under the IWL and Structures Monitoring Programs, respectively, requesting information on how 

the applicant will manage aging effects due to aggregate reactions. This issue, including the 

applicant’s response to RAIs and the staff’s review, is documented in detail in SER Sections 

3.0.3.2.17 and 3.0.3.2.18, and Open Item OI 3.0.3.2.18-1..

. LRA Section 3.5.2.2.1.10, associated with 

LRA Table 3.5.1, item 3.5.1-15, addresses cracking due to expansion and reaction with 

aggregate and increase in porosity and permeability due to leaching of calcium hydroxide of 

concrete elements exposed to any environment, which are being managed for aging by the 

ASME Code Section XI, Subsection IWL Program. The criteria in SRP-LR Section 3.5.2.2.1.10 

states that cracking due to expansion and reaction with aggregate and increase in porosity and 

permeability due to leaching of calcium hydroxide could occur in concrete elements of concrete 

and steel containments. For accessible areas, the GALL Report recommends managing aging 

using the ASME Code Section XI, Subsection IWL AMP. For inaccessible areas, the GALL 

Report recommends further evaluation if the concrete was not constructed in accordance with 

the recommendations of ACI 201.2R. The applicant stated that the concrete structures were 

designed in accordance with ACI 318, constructed in accordance with ACI 301 and ASTM 

Standards, and met recommendations equivalent to those in ACI 201.2R. Aggregates identified 

as potentially reactive by petrographic examination in accordance with ASTM C295 were not 

used. The applicant further stated that there are indications of leaching of calcium hydroxide in 

below-grade structures other than the containment building and that the ASME Code Section XI, 

Subsection IWL and Structures Monitoring Program will be used to manage these aging effects.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff can 

not complete its evaluation of components associated with item 3.5.1-15.

 4 The applicant submitted a supplement to the LRA dated May 16, 2012, which addresses a plant-specific aging management 

program entitled "Alkali-Silica Reaction Monitoring Program." The staff is currently reviewing this supplement, and therefore, its 

evaluation is not included in this SER with open items. 
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3.5.2.2.2 Safety-Related and Other Structures and Component Supports

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2, which 

addresses several areas, as discussed below.

Aging of Structures Not Covered by Structures Monitoring Program

(1) Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) due to Corrosion of 

Embedded Steel for Groups 1–5, 7, and 9 Structures

. LRA Section 3.5.2.2.2.1 

addresses aging of structures not covered by the Structures Monitoring Program.

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-23, addresses 

cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of 

embedded steel for concrete elements of Groups 1–5, 7, and 9 structures. The GALL 

Report recommends further evaluation of this structure and aging effect combination 

only if it is not covered by the Structures Monitoring Program. In the LRA, the applicant 

stated that this item is covered by the Structures Monitoring Program and does not 

require further evaluation. 

The staff is concerned that the recent plant specific operating experience that indicate 

presence of ASR in the below-grade concrete structures may affect the scope and rate 

of degradation due to cracking, loss of bond, and loss of material (spalling, scaling) due 

to corrosion of embedded steel. The Structures Monitoring Program has to be enhanced 

to account for this phenomenon. This is being tracked as Open Item OI 3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff

can not complete its evaluation of components associated with item 3.5.1-23.

(2) Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) due 

to Aggressive Chemical Attack for Groups 1–5, 7, and 9 Structures

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-24, addresses 

increase in porosity and permeability, cracking, and loss of material (spalling, scaling) 

due to aggressive chemical attack for concrete elements of Groups 1–5, 7, and 9 

structures. The GALL Report recommends further evaluation of this structure and aging 

effect combination only if it is not covered by the Structures Monitoring Program. In the 

LRA, the applicant stated that this item is covered by the Structures Monitoring Program 

and does not require further evaluation. 

The staff is concerned that the recent plant operating experience indicating the presence 

of ASR in the below-grade concrete structures may affect the scope and rate of 

degradation due to increase in porosity and permeability, cracking, and loss of material 

(spalling, scaling) due to aggressive chemical attack. The Structures Monitoring 

Program has to be enhanced to account for this phenomenon. This is being tracked as 

Open Item OI 3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff

can not complete its evaluation of components associated with item 3.5.1-24.
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(3) Loss of Material due to Corrosion for Groups 1–5, 7, and 8 Structures

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-25, addresses loss 

of material due to corrosion for Groups 1–5, 7, and 8 structures. The GALL Report 

recommends further evaluation of this structure and aging effect combination only if it is 

not covered by the Structures Monitoring Program. In the LRA, the applicant stated that 

this item is covered by the Structures Monitoring Program and does not require further 

evaluation. 

The staff is concerned that the recent plant operating experience indicating the presence 

of ASR in the below-grade concrete structures may affect the scope and rate of 

degradation due to loss of material due to corrosion. The Structures Monitoring Program 

has to be enhanced to account for this phenomenon. This is being tracked as Open 

Item OI 3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff

can not complete its evaluation of components associated with item 3.5.1-25.

(4) Loss of Material (Spalling, Scaling) and Cracking due to Freeze-Thaw for Groups 1–5 

and 7–9 Structures

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-26, addresses loss 

of material (scaling, cracking, and spalling) in concrete elements due to freeze-thaw. 

The GALL Report recommends further evaluation of this structure and aging effect 

combination only if it is not covered by the Structures Monitoring Program. In the LRA,

the applicant stated that this item is covered by the Structures Monitoring Program and 

does not require further evaluation. The staff confirmed that the structure and aging 

effect combination is covered by the Structures Monitoring Program and, therefore, finds 

the applicant’s determination acceptable. The staff’s review of the applicant’s Structures 

Monitoring Program is documented in SER Section 3.0.3.2.18.

(5) Cracking due to Expansion and Reaction with Aggregates for Groups 1–5 and 7–9 

Structures

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-27, addresses 

cracking due to reaction with aggregates for Groups 1–5, and 7–9 structures. The GALL 

Report recommends further evaluation of this structure and aging effect combination 

only if it is not covered by the Structures Monitoring Program. In the LRA, the applicant 

stated that this item is covered by the Structures Monitoring Program. 

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in 

SER Section 3.0.3.2.18. Pending the resolution of OI 3.0.3.2.18-1, the staff can not 

complete its evaluation of this AMR item.

The staff finds that for LRA Item 3.5.1-27, OI 3.0.3.2.18-1 must be resolved before the 

staff can conclude 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.
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(6) Cracks and Distortion due to Increased Stress Levels from Settlement for Groups 1–3 

and 5–9 Structures

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-28, addresses 

cracks and distortion due to increased stress levels from settlement for Groups 1–3 and 

5–9 structures. The GALL Report recommends further evaluation of this structure and 

aging effect combination only if it is not covered by the Structures Monitoring Program. 

The applicant stated in the LRA that this item does not require further evaluation 

because Seabrook structures are founded on sound bedrock, fill concrete, or engineered 

backfill, and a dewatering system is not relied upon for control of settlement. The staff 

reviewed the UFSAR and confirmed that Seabrook structures are founded on bedrock, 

fill concrete, or engineered backfill, and a dewatering system is not relied upon for 

control of settlement and, therefore, finds the applicant’s determination acceptable. 

(7) Reduction in Foundation Strength, Cracking, and Differential Settlement due to Erosion 

of Porous Concrete Subfoundation for Groups 1–3 and 5–9 Structures

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-29, addresses 

reduction in foundation strength, cracking, and differential settlement due to erosion of 

porous concrete subfoundations for Groups 1–3 and 5–9 structures. The GALL Report 

recommends further evaluation of this structure and aging effect combination only if it is 

not covered by the Structures Monitoring Program. The applicant stated that this item is 

not applicable because porous concrete subfoundations were not used at Seabrook. 

The staff reviewed the UFSAR and confirmed that no porous concrete subfoundations 

are present at Seabrook and, therefore, finds the applicant’s determination acceptable.

(8) Lockup due to Wear for Lubrite® Radial Beam Seats in BWR Drywell and Other Sliding 

Support Surfaces

LRA Section 3.5.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-30, addresses 

lock-up due to wear in Lubrite® supports exposed to an air-indoor environment. The 

GALL Report recommends further evaluation of this structure and aging effect 

combination only if it is not covered by the Structures Monitoring Program or the IWF 

Program. In the LRA, the applicant stated that this item is covered by the Structures 

Monitoring and the ASME Code Section XI, Subsection IWF Programs. The staff 

confirmed that the structure and aging effect combination is covered by the Structures 

Monitoring and the ASME Code Section XI, Subsection IWF Programs and, therefore,

finds the applicant’s determination acceptable. Aging management of sliding supports is 

also discussed in SER Section 3.5.2.3.6, in the review of the applicant’s response to 

RAI 3.5.2.3.6-2. The staff’s reviews of the applicant’s Structures Monitoring and ASME 

Code Section XI, Subsection IWF Programs are documented in SER Sections 3.0.3.2.18 

and 3.0.3.1.10, respectively.

Aging Management of Inaccessible Areas

(1) Loss of Material (Spalling, Scaling) and Cracking due to Freeze-Thaw Could Occur in 

Below-Grade Inaccessible Concrete Areas of Groups 1–3, 5, and 7–9 Structures.

. LRA Section 3.5.2.2.2.2 addresses aging 

management of inaccessible areas (Below-grade inaccessible concrete areas of Groups 1–3, 5, 

and 7–9 Structures).

LRA Section 3.5.2.2.2.2.1, associated with LRA Table 3.5.1, item 3.5.1-26, addresses 

loss of material (scaling, cracking, and spalling) due to freeze-thaw of inaccessible 
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concrete elements exposed to soil and outdoor air. The criteria in SRP-LR 

Section 3.5.2.2.2.2, item 1, recommends further evaluation for plants located in areas 

having moderate to severe weathering conditions. The SRP-LR also notes that existing 

concrete with an air content of 3–6 percent and a water-to-cement ratio between 0.35–

0.45 did not exhibit degradation related to freeze-thaw. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that the concrete structures were 

designed in accordance with ACI 318 and constructed in accordance with ACI 301, 

ASTM standards, and recommendations equivalent to ACI 201.2R. The air content of 

the concrete is higher than 6 percent but within the acceptable guidelines of ACI 201 and 

ACI 318. In addition, the LRA states that, under the Structures Monitoring Program,

examinations of inaccessible areas will be completed during inspections of opportunity 

or, if no opportunistic inspections are performed during a 5-year period, a focused 

inspection is required. The LRA also states that the condition of accessible areas may 

be used to evaluate the condition of inaccessible areas.

The staff noted that the applicant’s air content is above the 6 percent recommendation in 

the GALL Report. The staff also noted that the applicant will inspect for freeze-thaw 

degradation in accessible areas and use the results to evaluate the condition of 

inaccessible areas, and examinations of opportunity will be conducted on inaccessible 

areas. In addition, the staff noted that although the applicant’s external structures are 

exposed to freeze-thaw cycles, a review of plant operating experience did not reveal 

concrete degradation attributed to freeze-thaw. The staff further noted that the GALL 

Report suggests existing concrete exposed to potential freeze-thaw have a 

water-to-cement ratio between 0.35–0.45. The staff noted that a water-to-cement ratio 

was not provided as recommended in GALL Report item III.A3-6 for concrete located in 

moderate to severe weathering conditions. By letter dated January 5, 2011, the staff 

issued RAI 3.5.2.2.2.2-1 requesting that the applicant provide justification to address 

compliance of the Seabrook concrete to recommendations provided in the GALL Report.

In its response dated February 3, 2011, the applicant stated that the water-to-cement 

ratio varies from 0.45–0.53. The applicant further stated that although the ratio exceeds 

the recommendations of the GALL Report, it was selected on the basis of strength 

requirements per specification “Standard Concrete Mixes.”

The staff finds the applicant’s response acceptable because the applicant will manage 

this aging effect with the Structures Monitoring Program. Any indications of degradation 

in accessible areas will be used to evaluate inaccessible areas. In addition, a review of

plant operating experience did not reveal concrete degradation attributed to freeze-thaw. 

The staff’s concern described in RAI 3.5.2.2.2.2-1 is resolved.

The staff finds the applicant’s further evaluation acceptable because the concrete air 

content limit was increased to 8 percent (including tolerance) in GALL Report, Rev. 2, 

Section 3.5.3.2.1.7. In addition, the Seabrook concrete air content is acceptable per 

ACI 201 and ACI 318 guidelines, and the staff did not identify any plant-specific

operating experience related to freeze-thaw in either the accessible or inaccessible 

concrete surfaces. The applicant will continue to inspect the accessible concrete 

surfaces in accordance with the Structures Monitoring Program during the current 

licensing period as well as during the period of extended operation. Additionally, the 

applicant will conduct opportunistic inspections of inaccessible areas, and results of 

inspections of accessible areas will be used to evaluate the condition of inaccessible 

areas. The accessible concrete exposed to atmosphere is more susceptible to freeze-
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thaw because it is more likely to be subjected to alternate freeze-thaw cycles. The 

inaccessible concrete located below grade is not normally subjected to such freeze-thaw 

conditions. 

Based on the evaluation provided, the staff concludes that the applicant met SRP-LR 

Section 3.5.2.2.2.2, item 1, criteria. For those items that apply to LRA 

Section 3.5.2.2.2.2.1, the staff determined that the LRA is consistent with the GALL 

Report, and the applicant 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) Cracking due to Expansion and Reaction with Aggregates Could Occur in Below-Grade 

Inaccessible Concrete Areas for Groups 1–5 and 7–9 Structures5

LRA Section 3.5.2.2.2.2.2, associated with LRA Table 3.5.1, item 3.5.1-27, addresses 

cracking due to reaction with aggregates for inaccessible areas of Groups 1–5 and 7–9 

structures. The SRP-LR Section 3.5.2.2.2.2, item 2, states that further evaluation of this 

structure and aging effect combination for inaccessible areas is not necessary if 

examinations, performed in accordance with ASTM standards C227 or C295,

demonstrate that the aggregates are non-reactive or the concrete was constructed in 

accordance with ACI 201.2R. In the LRA, the applicant stated that this item does not 

require further evaluation because tests and petrographic examinations, performed in 

accordance with ASTM C227-50 or ASTM C295-54, confirmed that the aggregate 

materials were not reactive, and the concrete was constructed using recommendations 

equivalent to ACI 201.2R. The applicant also stated that the aging effect would be 

managed in accessible areas by the Structures Monitoring Program.

.

The staff reviewed the UFSAR and confirmed that aggregates were tested for reactivity 

in accordance with ASTM C227 or C295, and the concrete was constructed in 

accordance with recommendations in ACI 201.2R; however, recent plant-specific 

operating experience has indicated that alkali-aggregate reactions are occurring onsite. 

To address this operating experience, the staff issued RAIs B.2.1.28-3 and B.2.1.31-1 

under the IWL and Structures Monitoring Programs, respectively, requesting information 

on how the applicant will manage aging effects due to aggregate reactions. This issue, 

including the applicant’s response to the RAIs and the staff’s review, is discussed in 

detail in SER sections 3.0.3.2.17 and 3.0.3.2.18, and Open Item OI 3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff 

can not complete its evaluation of components associated with item 3.5.1-27.

(3) Cracks and Distortion due to Increased Stress Levels from Settlement and Reduction of 

Foundation Strength, Cracking, and Differential Settlement due to Erosion of Porous 

Concrete Subfoundations Could Occur in Below-Grade Inaccessible Concrete Areas of 

Groups 1–3, 5, and 7–9 structures.

LRA Section 3.5.2.2.2.2.3, associated with LRA Table 3.5.1, items 3.5.1-28 and 

3.5.1-29, addresses cracks and distortion due to increased stress levels from settlement 

and reduction of foundation strength, cracking, and differential settlement due to erosion 

 5 The applicant submitted a supplement to the LRA dated May 16, 2012, which addresses a plant-specific aging management 

program entitled "Alkali-Silica Reaction Monitoring Program." The staff is currently reviewing this supplement, and therefore, its 

evaluation is not included in this SER with open items. 
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of porous concrete subfoundations for inaccessible areas of Groups 1–3 and 5–9 

structures. The SRP-LR Section 3.5.2.2.2.2, item 3, recommends no further evaluation 

if this activity is included in the scope of the applicant's Structures Monitoring Program. 

These aging effects are included in the scope of the applicant’s Structures Monitoring 

Program, and no dewatering system is used. In the LRA, the applicant stated that these 

items do not require further evaluation because Seabrook structures are founded on 

sound bedrock, fill concrete, or consolidated backfill; there are no porous concrete 

subfoundations and the foundations are not subject to flowing water; and a dewatering 

system is not relied upon for control of settlement. The staff reviewed the UFSAR and 

confirmed that the structures are founded on sound bedrock, fill concrete, or 

consolidated backfill; a dewatering system is not used; and there are no porous 

subfoundations on the site. In addition, the staff noted that the applicant’s Structures 

Monitoring Program inspects for cracking, regardless of aging mechanism. Therefore, 

the staff finds acceptable the applicant’s determination that further evaluation is not 

required. The staff’s review of the applicant’s Structures Monitoring Program is 

documented in SER Section 3.0.3.2.18.

(4) Increase in Porosity and Permeability, Cracking and Loss of Material (Spalling, Scaling) 

due to Aggressive Chemical Attack, and Cracking, Loss of Bond, and Loss of Material 

(Spalling, Scaling) due to Corrosion of Embedded Steel Could Occur in Below-Grade 

Inaccessible Concrete Areas of Groups 1–3, 5, and 7–9 Structures.

LRA Section 3.5.2.2.2.2.4 associated with LRA Table 3.5.1, item 3.5.1-31, addresses 

below-grade concrete components exposed to a groundwater or soil environment, which 

are being managed for cracking, loss of material, and loss of bond due to aggressive 

chemical attack and corrosion of embedded steel. The criteria in SRP-LR 

Section 3.5.2.2.2.2, item 4, state that the GALL Report recommends further evaluation of 

plant-specific programs to manage these aging effects in inaccessible areas if the 

environment is aggressive. In the GALL Report, it is noted that for inaccessible areas of 

plants with non-aggressive groundwater or soil (i.e., pH greater than 5.5, chlorides less 

than 500 ppm, or sulfates less than 1,500 ppm), the following, as a minimum, should be 

considered: 

• examinations of the exposed portions of the below-grade concrete when 

excavated for any reason

• periodic monitoring of below-grade water chemistry, including 

consideration of potential seasonal variations

The applicant stated that the concrete structures were designed in accordance with 

ACI 318 and constructed in accordance with ACI 301 and ASTM standards, and the 

concrete complied with recommendations equivalent to those in ACI 201.2R. The 

applicant further stated that there are indications of leaching of calcium hydroxide in 

below-grade concrete structures. The groundwater at Seabrook is aggressive in that 

chloride levels between 19–3,900 ppm were obtained during testing from 

November 2008–September 2009, and plant operating experience notes that 

groundwater infiltration through cracks, capillaries, pore spaces, seismic isolation joints,

and construction joints in concrete walls and floor slabs or below-grade concrete 

structures has occurred. The LRA also states that concrete testing and rebar inspection 

will be conducted to determine the effects of aggressive groundwater on the concrete. 

The testing will represent all below-grade concrete. The LRA also states that these 
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aging effects and mechanisms are covered by the Structures Monitoring Program and 

that, under the Structures Monitoring Program, examinations of inaccessible areas will 

be completed during inspections of opportunity.

The staff noted that the applicant will inspect exposed portions of below-grade concrete 

when exposed for any reason and will monitor the groundwater for aggressiveness as 

defined in the GALL Report. The staff also noted that this aging effect will be managed 

in accessible areas through visual inspections under the Structures Monitoring Program. 

In addition, the applicant has plans in place to determine the effects of aggressive 

groundwater through concrete testing and rebar inspection. The adequacy of this testing 

program is addressed in the staff’s evaluation of the applicant’s Structures Monitoring 

Program, which is documented in SER Section 3.0.3.2.18. 

The staff is concerned that the recent plant specific operating experience indicating 

presence of ASR in below-grade concrete structures may affect the scope and rate of 

degradation due to increase in porosity and permeability, cracking, loss of material 

(spalling, scaling) due to aggressive chemical attack; and cracking loss of bond, and loss 

of material due to corrosion of embedded steel. The Structures Monitoring Program has 

to be enhanced to account for this phenomenon. This is being tracked as Open Item OI 

3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff

can not complete its evaluation of components associated with item 3.5.1-31.

(5) Increase in Porosity and Permeability, and Loss of Strength due to Leaching of Calcium 

Hydroxide Could Occur in below-Grade Inaccessible Concrete Areas of Groups 1–3, 5, 

and 7–9 Structures

LRA Section 3.5.2.2.2.2.5 associated with LRA Table 3.5.1, item 3.5.1-32, addresses 

below-grade concrete components exposed to a flowing water or soil environment,

which are being managed for increase in porosity and permeability, and loss of strength 

due to leaching of calcium hydroxide. The criteria in SRP-LR Section 3.5.2.2.2.2, item 5,

states that further evaluation is not necessary if concrete was constructed in accordance 

with the recommendations in ACI 201.2R. 

The staff is concerned that the recent plant specific operating experience indicating the 

presence of ASR in the below-grade concrete structures may affect the scope and rate 

of degradation due to increase in porosity and permeability, cracking, loss of material 

(spalling, scaling) due to aggressive chemical attack; and cracking loss of bond, and loss 

of material due to corrosion of embedded steel. The Structures Monitoring Program has 

to be enhanced to account for this phenomenon. This is being tracked as Open Item OI 

3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff

can not complete its evaluation of components associated with item 3.5.1-32.

Reduction of Strength and Modulus of Concrete Structures due to Elevated Temperature. LRA 

Section 3.5.2.2.2.3, associated with LRA Table 3.5.1, item 3.5.1-33, addresses reduction of 

strength and modulus of concrete structures exposed to elevated temperatures. The GALL 

Report recommends further evaluation for any concrete elements that exceed the specified 

temperature limits of 150  ̊F general and 200  ̊F local. The applicant stated that this item is not 

applicable because no Group 1–5 concrete structures are exposed to temperatures above the 
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GALL Report limits. The staff reviewed the UFSAR and confirmed that no in-scope concrete is 

exposed to temperatures exceeding the GALL Report limits; therefore, it finds the applicant’s 

determination acceptable.

Aging Management of Inaccessible Areas for Group 6 Structures

(1) Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) due 

to Aggressive Chemical Attack; and Cracking, Loss of Bond, and Loss of Material 

(Spalling, Scaling) due to Corrosion of Embedded Steel Could Occur in Below-Grade 

Inaccessible Concrete Areas of Group 6 Structures.

. LRA Section 3.5.2.2.2.4 

addresses aging management of inaccessible areas for Group 6 structures (below-grade 

inaccessible concrete areas).

LRA Section 3.5.2.2.2.4.1 associated with LRA Table 3.5.1, item 3.5.1-34, addresses 

below-grade concrete components exposed to a groundwater or soil environment, which 

are being managed for increase in porosity and permeability, cracking, loss of material, 

and loss of bond due to aggressive chemical attack and corrosion of embedded steel. 

The criteria in SRP-LR Section 3.5.2.2.2.4, item 1, state that the GALL Report 

recommends further evaluation of plant-specific programs to manage these aging effects 

in inaccessible areas if the environment is aggressive. In the GALL Report, it is noted 

that for inaccessible areas of plants with non-aggressive groundwater or soil (i.e., pH 

greater than 5.5, chlorides less than 500 ppm, or sulfates less than 1,500 ppm), the 

following, as a minimum, should be considered: 

• examinations of the exposed portions of the below-grade concrete when 

excavated for any reason

• periodic monitoring of below-grade water chemistry, including 

consideration of potential seasonal variations

The applicant stated that the concrete structures were designed in accordance with 

ACI 318 and constructed in accordance with ACI 301 and ASTM standards. The 

groundwater at Seabrook is aggressive in that chloride levels between 19–3,900 ppm 

were obtained during testing from November 2008–September 2009. The LRA states 

that, under the Structures Monitoring Program (B.2.1.31), examinations of inaccessible 

areas will be completed during inspections of opportunity or, if no opportunistic

inspections are performed during a 5-year period, a focused inspection is required. 

Additionally, groundwater will be tested at 5-year intervals, and testing of concrete and 

inspections of rebar representative of the below-grade concrete are scheduled to

determine the effects of aggressive groundwater.

The staff is concerned that the recent plant operating experience indicating the presence 

of ASR in the below-grade concrete structures may affect the scope and rate of 

degradation due to increase in porosity and permeability, cracking, loss of material 

(spalling, scaling) due to aggressive chemical attack; and cracking loss of bond, and loss 

of material due to corrosion of embedded steel. The Structures Monitoring Program has 

to be enhanced to account for this phenomenon. This is being tracked as Open Item OI 

3.0.3.2.18-1.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff

can not complete its evaluation of components associated with item 3.5.1-34.
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(2) Loss of Material (Spalling, Scaling) and Cracking due to Freeze-Thaw that Could Occur 

in Below-Grade Inaccessible Concrete Areas of Group 6 Structures.

LRA Section 3.5.2.2.2.4.2, associated with LRA Table 3.5.1, item 3.5.1-35, addresses 

loss of material (scaling, cracking, and spalling) of inaccessible concrete elements due 

to freeze-thaw in Group 6 structures. The criteria in SRP-LR Section 3.5.2.2.2.4, item 2,

states that the GALL Report recommends further evaluation for plants located in areas 

having moderate to severe weathering conditions if the concrete does not have an air 

content of 3–6 percent and a water-to-cement ratio between 0.35–0.45. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the concrete was 

a dense, durable mixture of sound coarse aggregate, cement, and water, and that it had 

an air content higher than 6 percent but within the acceptable guidelines of ACI 201 and 

ACI 318. The applicant further stated that the Structures Monitoring Program will 

manage loss of material due to freeze-thaw during the period of extended operation.

The staff’s review of the adequacy of the applicant’s aging management approach for 

these aging effects on inaccessible elements of reinforced concrete structures is 

documented in SER Section 3.5.2.2.2, “Aging Management of Inaccessible Areas, 

Item 1.” That review addresses the applicant’s aging management approach for all 

concrete structures within the scope of license renewal, including Group 6 structures.

(3) Cracking due to Expansion and Reaction with Aggregates and Increase in Porosity and 

Permeability, and Loss of Strength due to Leaching of Calcium Hydroxide Could Occur 

in Below-Grade Inaccessible Reinforced Concrete Areas of Group 6 Structures6

LRA Section 3.5.2.2.2.4.3, associated with LRA Table 3.5.1, item 3.5.1-36, addresses 

cracking due to reaction with aggregates for Group 6 structures. The applicant stated 

that tests and petrographic examinations, performed in accordance with ASTM C227-50 

or ASTM C295-54, confirmed that the aggregate materials are not reactive; however, the 

Structures Monitoring Program is used to manage this structure and aging effect.

.

The staff’s review of the adequacy of the applicant’s further evaluation for these aging 

effects on inaccessible elements of reinforced concrete structures is documented in SER 

Section 3.5.2.2.2, “Aging Management of Inaccessible Areas, Item 2.” That review 

addresses the applicant’s aging management approach for all concrete structures within 

the scope of license renewal, including Group 6 structures.

LRA Section 3.5.2.2.2.4.3 associated with LRA Table 3.5.1, item 3.5.1-37, addresses 

below-grade concrete components exposed to a flowing water or soil environment,

which are being managed for increase in porosity and permeability and loss of strength 

due to leaching of calcium hydroxide. The criteria in SRP-LR Section 3.5.2.2.2.4, item 3,

states that further evaluation is not necessary if concrete was constructed in accordance 

with the recommendations in ACI 201.2R. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the Structures Monitoring Program is 

used to manage this structure and aging effect.

The staff’s review of the adequacy of the applicant’s aging management approach for 

these aging effects on inaccessible elements of reinforced concrete structures is 

 6 The applicant submitted a supplement to the LRA dated May 16, 2012, which addresses a plant-specific aging management 

program entitled "Alkali-Silica Reaction Monitoring Program." The staff is currently reviewing this supplement, and therefore, its 

evaluation is not included in this SER with open items. 
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documented in SER Section 3.5.2.2.2, “Aging Management of Inaccessible Areas, 

Item 5.” That review addresses the applicant’s aging management approach for all 

concrete structures within the scope of license renewal, including Group 6 structures.

Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff 

can not complete its evaluation of components associated with item 3.5.1-36 and 

3.5.1-37. 

Cracking Due to Stress Corrosion Cracking and Loss of Material due to Pitting and Crevice 

Corrosion. LRA Section 3.5.2.2.2.5, associated with LRA Table 3.5.1, item 3.5.1-38, addresses 

cracking due to SCC and loss of material due to pitting and crevice corrosion for Group 7 and 8 

stainless steel tank liners. The applicant stated that SCC is not applicable because the tank 

liners are not subjected to a standing water environment or temperatures above 140  ̊F. The 

applicant further stated that loss of material is an applicable aging effect, which is managed by 

appropriate AMPs. The staff reviewed the LRA and the UFSAR and confirmed that the 

stainless steel tank liners are not subjected to a corrosive environment or temperatures above 

140  ̊F, and tank liners are managed for loss of material; therefore, the staff finds acceptable the 

applicant’s determination that further evaluation is not required.

Aging of Supports Not Covered by the Structures Monitoring Program

(1) Loss of Material due to General and Pitting Corrosion for Groups B2–B5 Supports

. LRA Section 3.5.2.2.2.6 

addresses aging of supports not covered by the Structures Monitoring Program.

LRA Section 3.5.2.2.2.6, associated with LRA Table 3.5.1, item 3.5.1-39, addresses loss 

of material due to general and pitting corrosion of Groups B2–B5 steel supports exposed 

to an air environment. The GALL Report recommends further evaluation of this structure

and aging effect combination only if it is not covered by the Structures Monitoring 

Program. In the LRA, the applicant stated that this item does not require further 

evaluation because it is covered by the Structures Monitoring Program. The staff 

confirmed that the structure and aging effect combination is covered by the applicant’s 

Structures Monitoring Program and, therefore, finds the applicant’s determination 

acceptable. The staff’s review of the applicant’s Structures Monitoring Program is 

documented in SER Section 3.0.3.2.18.

(2) Reduction in Concrete Anchor Capacity due to Degradation of the Surrounding Concrete 

for Groups B1–B5 Supports

LRA Section 3.5.2.2.2.6, associated with LRA Table 3.5.1, item 3.5.1-40, addresses 

reduction in anchor capacity due to degradation of surrounding concrete for Groups B1–

B5 supports exposed to an air environment. The GALL Report recommends further 

evaluation of this structure and aging effect combination only if it is not covered by the 

Structures Monitoring Program. In the LRA, the applicant stated that this item does not 

require further evaluation because it is covered by the Structures Monitoring Program. 

The staff is concerned that the presence of ASR in the below-grade concrete may have 

impacted concrete anchor capacity. The reduction in concrete mechanical properties 

indicates that the anchor capacity would also be reduced. The Structures Monitoring 

Program has to be enhanced to account for this phenomenon. This is being tracked as 

Open Item OI 3.0.3.2.18-1.
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Based on the information provided to date, and until OI 3.0.3.2.18-1 is resolved, the staff

can not complete its evaluation of components associated with item 3.5.1-40.

(3) Reduction and Loss of Isolation Function due to Degradation of Vibration Isolation 

Elements for Group B4 Supports

LRA Section 3.5.2.2.2.6, associated with LRA Table 3.5.1, item 3.5.1-41, addresses 

reduction of isolation function of non-metallic vibration isolation elements in an air 

environment. In the LRA, the applicant stated that this item is not applicable because 

there are no vibration isolation elements within the scope of license renewal. The staff 

reviewed LRA Chapters 2 and 3 and confirmed that there are no in-scope vibration 

isolation elements; therefore, it finds the applicant’s determination acceptable.

Cumulative Fatigue Damage due to Cyclic Loading

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

. LRA Section 3.5.2.2.2.7 associated with 

LRA Table 3.5.1, item 3.5.1-42, states that analyses of fatigue of component support members, 

anchor bolts, and welds for Group B1.1, Group B1.2, and Group B1.3 component supports (for 

ASME Code Classes 1, 2, and 3 piping and components and for Class metal containment BWR 

containment supports) are TLAAs, as defined in 10 CFR 54.3, only if a CLB fatigue analysis 

exists. The staff confirmed that fatigue analyses for these components were not included as 

part of the CLB. This is consistent with SRP-LR Section 3.5.2.2.2.7 and is, therefore, 

acceptable.

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA Program.

3.5.2.3 Aging Management Review Results Not Consistent with or Not Addressed in 

the GALL Report

In LRA Tables 3.5.2-1 through 3.5.2-8, 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 3.5.2-1 through 3.5.2-8, the applicant indicated, via Notes F–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 if the applicant 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.
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3.5.2.3.1 Buildings, Structures within License Renewal—Summary of Aging Management

Evaluation—LRA Table 3.5.2-1

In LRA Tables 3.5.2-1, 3.5.2-2, 3.5.2-5, 3.5.2-7, and 3.5.2-8, the applicant stated that roofing 

exposed to air-outdoor (external) is being managed for separation, environmental degradation, 

and water in-leakage by the Structures Monitoring Program. The AMR item cites generic note H 

and plant-specific note 505, which states that built-up roofing is not in the GALL Report; 

however, similar elastomeric materials, aging effects, and environments are identified under 

item III.A6-12, which recommends the Structures Monitoring Program.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

similar elastomeric materials are listed in the GALL Report in various environments, and the 

aging effects are loss of sealing and degradation of seals. The aging effects listed by the 

applicant for roofing exposed to an air-outdoor environment—separation, degradation, and 

in-leakage—are similar to the GALL Report identified aging effects.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because monitoring for this aging effect is done 

through periodic visual inspections, and the Structures Monitoring Program is the GALL Report 

recommended program for equivalent materials exposed to similar environments. The staff 

confirmed that roofing associated with this item is included in the scope of the Structures 

Monitoring Program.

In LRA Tables 3.5.2-1 and 3.5.2-8, the applicant stated that carbon steel revetment and carbon 

steel service water pumphouse components exposed to raw water are being managed for loss 

of material due to general (steel only), pitting, and crevice corrosion by the Structures 

Monitoring Program. The AMR item cites generic note H and plant-specific Notes 511 or 514. 

Plant-specific note 511 states that RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants (XI.S7),” is included under the Structures Monitoring 

Program (XI.S6). Plant-specific note 514 states that this condition will be managed through the 

Structures Monitoring Program.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

this is the aging effect listed in the GALL Report (item III.A6-11) for steel components exposed 

to raw water.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff noted that the GALL Report, under item III.A6-11, identifies 

“RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants,” as 

the recommended AMP for this material aging effect combination. The staff finds the applicant’s 

proposal to manage aging using the Structures Monitoring Program acceptable because it 

integrates the GALL Report recommended “RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” AMP. Additionally, monitoring for this aging effect is 

done through periodic visual inspections in accordance with ANSI/ASCE 11-90, “Guideline for 

Structural Condition Assessment of Existing Buildings.” The staff confirmed that steel 

components associated with this item are included in the scope of the Structures Monitoring 

Program.
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On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.2 Containment Structures—Summary of Aging Management Evaluation—LRA 

Table 3.5.2-2

The staff’s evaluation for built-up roofing exposed to air-outdoor environment, being managed 

for separation and degradation by the Structures Monitoring Program and citing generic note H 

and plant-specific note 505, is documented in SER Section 3.5.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.3 Fuel Handling and Overhead Cranes—Summary of Aging Management 

Evaluation—LRA Table 3.5.2-3

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the 

fuel handling and overhead cranes.

The staff’s review did not find any items indicating plant-specific notes F–J, whereby the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report.

The staff’s evaluation of the items with notes A–E is documented in SER Section 3.5.2.1.

3.5.2.3.4 Miscellaneous Yard Structures—Summary of Aging Management Evaluation—LRA 

Table 3.5.2-4

In LRA Table 3.5.2-4, the applicant stated that aluminum SBO structures exposed to air-outdoor 

(external) are being managed for crack initiation and crack growth by the Structures Monitoring 

Program. The AMR item cites generic note H and plant-specific note 514.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

aluminum components that are exposed to outdoor air can experience crack initiation and 

growth. Aluminum components exposed to outdoor air can also experience loss of material; 

however, this aging effect has been addressed by the applicant and is being managed by the 

GALL Report recommended Structures Monitoring Program.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff finds the applicant’s proposal to manage cracking using the 

Structures Monitoring Program acceptable because monitoring for this aging effect is done 

through periodic visual inspections, which would detect this aging mechanism. In addition, the 

Structures Monitoring Program is the GALL Report recommended program for managing loss of 
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material for aluminum components exposed to similar environments. The staff confirmed that 

aluminum components associated with this item are included in the scope of the Structures 

Monitoring Program.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.5 Primary Structures—Summary of Aging Management Evaluation—LRA 

Table 3.5.2-5

The staff’s evaluation for built-up roofing exposed to air-outdoor environment, being managed 

for separation and degradation by the Structures Monitoring Program and citing generic note H 

and plant-specific note 505, is documented in SER Section 3.5.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.6 Supports—Summary of Aging Management Evaluation—LRA Table 3.5.2-6

In LRA Table 3.5.2-6, the applicant stated that ASME Class 2 and Class 3 stainless steel 

exposed to raw water (external) environment, are being managed for loss of material by the 

ASME Code Section XI, Subsection IWF Program. The AMR item cites generic note H and 

plant-specific note 514, which states that this condition will be managed through the Structures 

Monitoring Program. 

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

ASME Class 2 and Class 3 stainless steel exposed to raw water (external) environment can 

experience loss of material. This is the same aging effect discussed in GALL Report item T-24, 

which is associated with ASME Class 2 and Class 3 steel exposed air. Although that item is a 

different material and environment, the aging effects are similar.

The staff confirmed that the structure and aging effect combination are covered by the ASME 

Code Section XI, Subsection IWF and the Structures Monitoring Programs. The staff’s reviews 

of the applicant’s ASME Code Section XI, Subsection IWF and the Structures Monitoring 

Programs are documented in SER Sections 3.0.3.1.10 and 3.0.3.2.18, respectively. The staff 

finds the applicant’s proposal to manage aging using the ASME Code Section XI, 

Subsection IWF Structures Monitoring Programs acceptable because both programs use visual 

inspection that is capable of detecting loss of material.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 
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components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

In LRA Table 3.5.2-6, the applicant stated that non-ASME constant and variable load spring 

hangers exposed to uncontrolled indoor air are being managed for loss of mechanical function 

by the Structures Monitoring Program. The AMR item cites generic note H and plant-specific 

note 514, which states that this condition will be managed through the Structures Monitoring 

Program.

The staff reviewed the associated items in the LRA and confirmed that the applicant identified 

the correct aging effects for this component, material, and environment combination because 

non-ASME constant and variable load spring hangers exposed to uncontrolled indoor air can 

experience loss of mechanical function. This is the same aging effect discussed in GALL 

Report item T-28, which is associated with ASME constant and variable load spring hangers. 

Although that item is associated with ASME components, the aging effects would be similar for 

non-ASME supports.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff noted that, for ASME supports, the GALL Report recommends 

visual inspections under the IWF AMP to manage this aging effect. Since these are non-ASME 

supports, they are not within the scope of the IWF Program; however, the Structures Monitoring 

Program will use similar visual inspections to detect degradation. The staff finds the applicant’s 

proposal to manage aging using the Structures Monitoring Program acceptable because 

monitoring for this aging effect is done through periodic visual inspections in accordance with 

ANSI/ASCE 11-90, “Guideline for Structural Condition Assessment of Existing Buildings.” The 

staff confirmed that non-ASME constant and variable load spring hangers associated with this 

item are included in the scope of the Structures Monitoring Program.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.7 Turbine Building—Summary of Aging Management Evaluation—LRA Table 3.5.2-7

The staff’s evaluation for built-up roofing exposed to air-outdoor environment, being managed 

for separation and degradation by the Structures Monitoring Program and citing generic note H, 

is documented in SER Section 3.5.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function 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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3.5.2.3.8 Water Control Structures—Summary of Aging Management Evaluation—LRA 

Table 3.5.2-8

The staff’s evaluation for built-up roofing exposed to air-outdoor environment, being managed 

for separation and degradation by the Structures Monitoring Program and citing generic note H, 

is documented in SER Section 3.5.2.3.1.

The staff’s evaluation for steel components exposed to a raw water environment, being 

managed for loss of material by the Structures Monitoring Program and citing generic note H, is 

documented in SER Section 3.5.2.3.1.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.3 Conclusion

Until Open Item OI 3.0.3.2.18-1 is resolved, the staff can not conclude that the applicant 

provided sufficient information to demonstrate that the effects of aging for the containments, 

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

The following information documents the staff’s review of the applicant’s AMR results for the 

following electrical and instrumentation and control (I&C) components and commodity groups:

Aging Management of Electrical and Instrumentation and Controls

• non-EQ electrical cables and connections

• MEB

• fuse holders (not part of a larger assembly) metallic clamps

• cable connections (metallic parts)

• SF6 insulated bus, connections, and insulators

3.6.1 Summary of Technical Information in the Application 

LRA Section 3.6 provides AMR results for the electrical and I&C components and commodity 

groups. LRA Table 3.6.1, “Summary of Aging Management Evaluations for the Electrical/I&C 

Components/Commodities,” is a summary comparison of the applicant’s AMRs with those 

evaluated in the GALL Report for the electrical components, I&C components, and commodity 

groups.

3.6.2 Staff Evaluation 

The staff reviewed LRA Section 3.6 to determine if the applicant 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 
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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 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 has identified the appropriate GALL Report AMPs. The staff’s evaluations of 

the AMPs are documented in SER Section 3.0.3. Details of the staff’s AMR evaluation are 

documented in SER Section 3.6.2.1.

The staff also reviewed AMRs consistent with the GALL Report and for which further evaluation 

is recommended. The staff confirmed that the applicant’s further evaluations were consistent 

with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff’s evaluations are documented in 

SER Section 3.6.2.2.

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.

Table 3.6-1. Staff evaluation for electrical and instrumentation and controls in the GALL 

Report

Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Electrical equipment 

subject to 

10 CFR 50.49 EQ 

requirements

(3.6.1-1)

Degradation 

due to various 

aging 

mechanisms

EQ of Electric 

Components

Yes TLAA EQ of 

Electric 

Components 

EQ is a TLAA (See 

SER Section 

3.6.2.2.1)

Electrical cables, 

connections, and 

fuse holders 

(insulation) not 

subject to 

10 CFR 50.49 

EQ requirements

(3.6.1-2)

Reduced 

insulation 

resistance and 

electrical failure 

due to various 

physical, 

thermal, 

radiolytic, 

photolytic, and 

chemical 

mechanisms

Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

EQ Requirements

No Electrical 

Cables and 

Connections 

not Subject to 

10 CFR 50.49 

EQ 

Requirements

Consistent with 

GALL 

Conductor insulation 

for electrical cables 

and connections 

used in 

instrumentation 

circuits not subject 

to 10 CFR 50.49 

EQ requirements 

that are sensitive to 

reduction in 

conductor insulation 

resistance (3.6.1-3)

Reduced 

insulation 

resistance and 

electrical failure 

due to various 

physical, 

thermal, 

radiolytic, 

photolytic, and 

chemical 

mechanisms

Electrical Cables 

And Connections 

Not Subject to 

10 CFR 50.49 

EQ Requirements 

Used In 

Instrumentation 

Circuits

No Electrical 

Cables and 

Connections 

Not Subject to 

10 CFR 50.49 

EQ 

Requirements 

Used in 

Instrumentation 

Circuits 

Consistent with 

GALL 
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

Conductor insulation 

for inaccessible 

medium voltage 

(2 kV to 35 kV) 

cables 

(e.g., installed in 

conduit or direct 

buried) not subject 

to 10 CFR 50.49 

EQ requirements

(3.6.1-4)

Localized 

damage and 

breakdown of 

insulation 

leading to 

electrical failure 

due to moisture 

intrusion and 

water trees

Inaccessible 

Medium Voltage 

Cables Not Subject 

to 10 CFR 50.49 

EQ Requirements

No Inaccessible 

MediumVoltage Cables 

Not Subject to 

10 CFR 50.49 

EQ

Requirements 

Consistent with 

GALL 

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage 

(3.6.1-5)

Corrosion of 

connector 

contact 

surfaces due to 

intrusion of 

borated water

Boric Acid 

Corrosion

No Boric Acid 

Corrosion 

Consistent with 

GALL 

Fuse holders (not 

part of a larger 

assembly) and fuse 

holders—metallic 

clamp

(3.6.1-6)

Fatigue due to 

ohmic heating, 

thermal cycling, 

electrical 

transients, 

frequent 

manipulation, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation

Fuse Holders Yes Fuse Holders Consistent with 

GALL (See SER 

Section 3.6.2.3)

MEB—

bus/connections

(3.6.1-7)

Loosening of 

bolted 

connections 

due to thermal 

cycling and 

ohmic heating

Metal Enclosed Bus No Metal Enclosed 

Bus 

Consistent with 

GALL 

MEB—

insulation/insulators

(3.6.1-8)

Reduced 

insulation 

resistance and 

electrical failure 

due to various 

physical, 

thermal, 

radiolytic, 

photolytic, and 

chemical 

mechanisms

MEB No MEB Consistent with 

GALL 

MEB—enclosure 

assemblies

(3.6.1-9)

Loss of material 

due to general 

corrosion

Structures 

Monitoring Program

No Structures 

Monitoring 

Program 

Consistent with 

GALL 
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

MEB—enclosure 

assemblies

(3.6.1-10)

Hardening and 

loss of strength 

due to 

elastomers 

degradation

Structures 

Monitoring Program

No Structures 

Monitoring 

Program 

Consistent with 

GALL 

High-voltage 

insulators

(3.6.1-11)

Degradation of 

insulation 

quality due to 

presence of any 

salt deposits 

and surface 

contamination

and loss of 

material caused 

by mechanical 

wear due to 

wind blowing on 

transmission 

conductors

A plant-specific 

AMP is to be 

evaluated

Yes Not applicable Not applicable to 

Seabrook (See 

SER Section

3.6.2.2.2)

Transmission 

conductors and 

connections and 

switchyard bus and 

connections

(3.6.1-12)

Loss of material 

due to 

wind-induced 

abrasion and 

fatigue; loss of 

conductor 

strength due to 

corrosion; 

increased 

resistance of 

connection due 

to oxidation or 

loss of preload

A plant-specific 

AMP is to be 

evaluated

Yes Not applicable Not applicable to 

Seabrook (See 

SER Section

3.6.2.2.3)

Cable 

Connections—

metallic parts

(3.6.1-13)

Loosening of 

bolted 

connections 

due to thermal 

cycling, ohmic 

heating, 

electrical 

transients, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation

Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 EQ

Requirements

No Electrical Cable 

Connections 

Not Subject to 

10 CFR 50.49 

EQ

Requirements 

Consistent with 

GALL 

Fuse holders (not 

part of a larger 

assembly)—

insulation material

(3.6.1-14)

None None No No AERM or 

AMP

Consistent with 

GALL 
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Component group 

(GALL Report 

Item No.)

Aging effect/ 

mechanism

AMP in GALL 

Report

Further 

evaluation 

in GALL 

Report

AMP in LRA, 

supplements, 

or 

amendments

Staff evaluation

SF6 insulated bus, 

connections and 

insulators—

(insulation 

/insulators); 

(enclosure 

assemblies)

Loss of 

dielectric 

strength, loss of 

material, and 

hardening and 

loss of strength

None Yes 345 kV SF6 Bus Consistent with 

GALL (See SER 

Section 3.6.2.3)

The staff’s review of the electrical and I&C 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 components is documented in SER 

Section 3.0.3.

3.6.2.1 Aging Management Review Results Consistent with the GALL Report 

LRA Section 3.6.2.1 identifies the materials, environments, and aging effects requiring 

management, and the following programs that manage aging effects for the electrical and I&C 

components:

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements

Program

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used 

in Instrumentation Circuits Program

• Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements 

Program

• MEB Program

• Structures Monitoring Program

• Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements

Program

In LRA Table 3.6.1, the applicant summarizes AMRs for the electrical and I&C components and 

claimed that these AMRs are consistent with the GALL Report.

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which it does not recommend further evaluation, the staff’s 

audit and review determined if the plant-specific components of these GALL Report component 

groups were bounded by the GALL Report evaluation.
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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–E, indicating how 

the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these items to verify consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff reviewed these items to verify consistency with the GALL Report and confirmed

that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. 

The staff also determined whether the applicant’s AMP was consistent with the GALL Report 

AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from, 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 reviewed 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 reviewed 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 the 

GALL Report AMPs have been reviewed and accepted. The staff also determined whether the 

applicant’s AMP was consistent with the GALL Report AMP and whether the AMR was valid for 

the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff reviewed 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.

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.

3.6.2.2 Aging Management Review 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 components not subject to EQ, and provides 

information concerning how it will manage the following aging effects: 
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• degradation of insulator quality due to salt deposits or surface contamination

• loss of material due to mechanical wear

• loss of material due to wind-induced abrasion and fatigue

• loss of conductor strength due to corrosion

• increased resistance of connection due to oxidation or loss of pre-load

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the GALL Report recommends further evaluation, the 

staff reviewed the corresponding AMR items 3.6.1-11 and 3.6.1-12 in Table 3.6.1 of the LRA. 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 

In LRA Section 3.6.2.2.1, associated with LRA Table 3.4.1, items 3.6.1-1, the applicant provides 

an evaluation of the EQ TLAA. SER Section 4.4 documents the staff’s review of the applicant’s 

evaluation of this TLAA.

3.6.2.2.2 Degradation of Insulator Quality due to Presence of Any Salt Deposit and Surface 

Contamination and Loss of Material due to Mechanical Wear

In LRA Section 3.6.2.2.2, associated with LRA Table 3.4.1, items 3.6.1-11, the applicant stated 

that the SF6 switchyard connects Seabrook to the offsite transmission grid. The applicant also 

stated that the SF6 bus is included as part of the recovery path in the event of an SBO event. 

The design of the SF6 switchyard does not include high-voltage insulators that are commonly 

associated with an open-air switchyard design.

The staff reviewed LRA Section 3.6.2.2.2 against SRP-LR Section 3.6.2.2.2, which states that 

degradation of insulator quality due to salt deposits or surface contamination may occur in 

high-voltage insulators. The GALL Report 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 due to 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.

During the LRA site audit, the staff performed a walk-down inspection to the switchyard and 

discussed the Seabrook switchyard design with the applicant’s engineering staff. The staff 

noted that the Seabrook onsite distribution is connected to the offsite transmission grid via SF6

buses. These buses provide the offsite recovery paths in an SBO event. The staff confirmed 

that there are no high-voltage insulators within the scope of license renewal. Therefore, the 

staff determined that degradation of insulator quality due to presence of salt deposits or surface 

contamination and loss of material due to mechanical wear is not applicable to Seabrook.

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 Pre-Load

In LRA Section 3.6.2.2.3, is associated with LRA Table 3.4.1, items 3.6.1-12, the applicant 

stated that the SF6 switchyard connects Seabrook to the offsite transmission grid. The applicant 

also stated that the in-scope portion of the SF6 switchyard does not include transmission 
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conductors and connections or switchyard bus and connections that are commonly associated 

with an open-air switchyard design.

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 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 pre-load 

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.

During the LRA site audit, the staff performed a walk-down inspection to the switchyard and 

discussed the Seabrook switchyard design with the applicant’s engineering staff. The staff 

noted that the SF6 buses are used to connect the Seabrook onsite distribution to the offsite 

transmission grid. The enclosed SF6 buses provide the offsite recovery paths in an SBO event. 

The staff confirmed that there are no transmission conductors and switchyard bus within the 

scope of license renewal. Therefore, the staff determined that 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 pre-load is not applicable to transmission 

conductors and connections and switchyard bus and connections at Seabrook.

3.6.2.3 Aging Management Review 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 indicated, via Notes F–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.

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine if the applicant demonstrated 

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

maintained consistent with the CLB for the period of extended operation. The staff’s evaluation 

is documented in the following section.

3.6.2.3.1 Electrical and I&C Components and Commodities—Summary of Aging Management 

Review—LRA Table 3.6.2-1

In LRA Section 3.6.2.3, the applicant stated that the 345 kV SF6 switchyard connects Seabrook 

to the offsite transmission grid. The SF6 bus is included as part of the recovery path in the event 

of an SBO event. The applicant also stated that, as discussed in LRA Sections 3.6.2.2.2 and 

3.6.2.2.3, the design of the SF6 switchyard does not include high-voltage insulators and 

transmission lines that are normally associated with an open-air switchyard. The SF6 bus is a 

phase isolated and independent bus in which each phase conductor is enclosed by an individual 

metal housing separated from adjacent conductor housings by an air space. The conductor is 

centered in the housing by insulators. The insulating parameters are accomplished by 

maintaining the space achieved by the insulators and the insulating properties of the SF6 gas. 

The applicant further stated that the critical conditions, which are essential to the bus operation,

are maintaining the pressure boundary and the air, moisture and SO2 content. The applicant 
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stated that presence of moisture could lead to electrical failure, and the presence of SO2 is an 

indication of partial discharge in the system. The external surface of the SF6 bus is managed for 

loss of material. The pressure boundary and the quality of the SF6 gas are managed by the 

345 kV SF6 Bus AMP.

The staff noted that the potential aging effects on the 345 kV SF6 bus are the loss of pressure 

boundary due to elastomer degradation; loss of material due to pitting, crevice, and galvanic 

corrosion; and loss of bus intended function due to unacceptable air, moisture, or SO2 levels. 

The SF6 is an inert gas used to insulate the bus conductor. The applicant will inspect for 

corrosion on the exterior of the bus duct housing, test for leaks at elastomers, and periodically 

test gas samples to determine air, moisture, and SO2 level. The staff determined that these 

inspections are acceptable because they will maintain the insulating properties of the SF6 gas 

by maintaining the pressure boundary and monitoring the SF6 air, moisture, and SO2 content. 

The staff evaluation of this program is provided in SER Section 3.0.3.3.2.

In the Seabrook LRA, Table 3.6.1, item 3.6.1-6, “Fuse Holders (Not Part of a Larger Assembly; 

Fuse holders—Metallic Clamp)” and AMP B.2.1.36, “Fuse Holders,” the applicant states that the 

thermal fatigue in the form of high resistance caused by ohmic heating, thermal cycling or 

electrical transients, and mechanical fatigue caused by frequent removal of the fuse or vibration 

are not aging mechanisms requiring aging management based on the Seabrook analysis. 

Although the applicant concludes in LRA Table 3.6.1, item 3.6.1-6, and LRA Section B.2.1.36 

that the aging effects and mechanisms due to thermal fatigue and mechanical fatigue identified 

by GALL are not applicable to the fuse holders at Seabrook, the applicant does not provide 

information to substantiate its conclusion. GALL Report, Volume 2, Revision 1, item VI.A-8, 

“Fuse Holders (Not Part of a Larger Assembly—Metallic Clamp),” identifies the aging effect and 

mechanism as fatigue and ohmic heating, thermal cycling, electrical transients, frequent 

manipulation, vibration, chemical contamination, corrosion, and oxidation.

During the Seabrook LRA audit, the week of October 21, 2010, the staff requested the applicant 

provide an analysis of why the aging effects and mechanism due to thermal fatigue in form of 

high resistance caused by ohmic heating, thermal cycling or electrical transients, and 

mechanical fatigue caused by frequent removal or replacement of the fuse or vibration, 

identified in GALL Report, Volume 2, Revision 1, item VI.A-8, are not applicable to the fuse 

holders at Seabrook. In a letter dated November 15, 2010, the applicant provided the following 

Seabrook analysis to justify why the aging effects due to thermal fatigue in the form of high 

resistance caused by ohmic heating, and thermal cycling, electrical transients, mechanical 

fatigue caused by frequent manipulation, vibration, and chemical contamination do not require 

aging management:

• Ohmic Heating and Thermal Cycling—Seabrook power circuits are sized so that the 

ohmic heating is approximately 60 percent of the cable rated temperature. Therefore,

ohmic heating of the fuse clamps is minimized.

• Electrical Transient—Seabrook electrical design ensures that stress due to forces 

associated with electrical faults and transients are mitigated by the fast action of circuit 

protective devices at high fault currents. Mechanical stress due to electrical faults is not 

considered a credible aging mechanical since such faults are infrequent and random in 

nature. Electrical transients are not considered an aging mechanism that requires 

management.

• Frequent Manipulation—In review of the Seabrook operation database, of all in-scope 

fuses that are held in place by metallic (non-bolted) fuse clips, only seven have been 
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pulled during the life of the plant. Therefore, frequent manipulation of in-scope fuses is 

not considered an aging mechanism that requires management.

• Vibration—Seabrook design drawings and documentation determined the exact location 

and mounting of the fuse holders within the scope of this evaluation. This 

documentation verifies that there are no direct sources of vibration in proximity to the 

fuse holder junction boxes. The fuse holder junction boxes are mounted to a support 

attached directly to either a concrete wall or a column. Therefore, vibration is not 

considered an aging mechanism that requires management.

• Chemical Contamination—The location and mounting of the fuse holders within scope 

have no potential sources of chemical contamination in the area, and the fuse holders 

are housed in a protective enclosure to preclude this aging mechanism even if chemical 

contamination were possible. Therefore, based on their installed location and design 

configuration, chemical contamination is not considered an aging mechanism that 

requires management.

Based on its analysis, the Fuse Holder Program description, in LRA Section B.2.1.36, was 

revised by the applicant to clarify the exclusion of the above aging mechanisms from the Fuse 

Holder Program. Based on the staff’s review of the applicant’s analysis and revised LRA 

Section B.2.1.36 program description and staff confirmatory walkdown of the in-scope fuse 

holders, the staff finds the applicant’s response acceptable because the applicant provided 

adequate justification to exclude the above aging mechanisms from the Fuse Holder Program.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.6.3 Conclusion 

The staff concludes that the applicant 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

The staff reviewed the information in LRA Section 3, “Aging Management Review Results,” and 

Appendix B, “Aging Management Programs.” On the basis of its review of the AMR results and 

AMPs, the staff concludes that the applicant demonstrated that the aging effects 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 applicable UFSAR supplement program summaries and concludes that the 

UFSAR supplement adequately describes the AMPs credited for managing aging, as required 

by 10 CFR 54.21(d).

Conclusion for AMR Results
Time-Limited Aging Analyses

1

SECTION 4

TIME-LIMITED AGING ANALYSES

4.1

Certain plant-specific safety analyses involve time-limited assumptions defined by the current 

operating term. Pursuant to Section 54.21(c)(1) of Title 10 of the Code of Federal Regulations

(10 CFR 54.21(c)(1)), applicants must list those analyses in the current licensing basis (CLB) 

that meet the definition of a time-limited aging analysis (TLAA), as defined in 10 CFR 54.3.

Identification of Time-Limited Aging Analyses

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list plant-specific exemptions,

granted under 10 CFR 50.12, that are based on TLAAs. For any such exemption, the applicant 

must evaluate and justify the continuation of the exemption for the period of extended operation.

This section of the safety evaluation report (SER) provides the staff’s evaluation of the 

applicant’s basis for identifying those plant-specific or generic analyses that need to be 

identified as TLAAs for the license renewal application (LRA). This section of the SER also 

provides the staff’s evaluation of the applicant’s basis for concluding that the applicant’s LRA 

includes all exemptions that are based on a TLAA.

The U.S. Nuclear Regulatory Commission’s (NRC’s) guidance on matters related to the 

identification of TLAAs and TLAA-related exemptions is given in NUREG-1800, Revision 1, 

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

(SRP-LR) Section 4.1. The staff’s recommended “acceptance criteria” guidance is given in 

SRP-LR Section 4.1.2, and the staff’s recommended “review procedure” guidance is given in 

SRP-LR Section 4.1.3.

4.1.1 Summary of Technical Information in the Application

LRA Section 4.1 provides the basis for identifying the applicant’s analyses as TLAAs in 

accordance with 10 CFR 54.21(c)(1). The applicant stated that it evaluated those calculations 

that complied with the six criteria for defining an analysis as a TLAA, as specified in 

10 CFR 54.3. The list of TLAAs provided in LRA Table 4.1-1 meet the six criteria of a TLAA. 

The applicant stated that it reviewed the list of common TLAAs in the SRP-LR, dated 

September 2005. The applicant also stated that its review of the CLB included a review of the 

updated final safety analysis report (UFSAR), docketed licensing correspondence, design bases 

documents, applicant engineering calculations, applicable Westinghouse Owner’s Group 

(WOG) reports, technical specifications (TS) and TS bases documents, and previous applicants’ 

LRAs.

Pursuant to 10 CFR 54.21(c)(2), the applicant stated that it did not identify any exemptions that 

were granted under 10 CFR 50.12 and are based on a TLAA, as defined in 10 CFR 54.3.

4.1.2 Staff Evaluation

For each analysis identified as a TLAA in accordance with the requirements of 

10 CFR 54.21(c)(1), the applicant shall demonstrate that the TLAA is acceptable in accordance 

with one of following TLAA acceptance criteria:
Time-Limited Aging Analyses

2

(i) The analysis remains valid for the period of extended operation.

(ii) The analysis has been projected to the end of the period of extended operation.

(iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

LRA Section 4.1.2 provides the applicant’s methodology for determining which analyses in the 

CLB need to be identified as TLAAs. LRA Table 4.1-1 identifies those TLAAs that are 

applicable and provides the applicable sections that discuss these TLAAs. LRA Section 4.1-2 

identifies if the generic analyses in SRP-LR Tables 4.1-2 and 4.1-3 are applicable to the 

applicant’s CLB and if they need to be identified as TLAAs. LRA Section 4.1.3 discusses the 

exemptions that need to be identified in accordance with the exemption identification 

requirement in 10 CFR 54.21(c)(2). The staff reviewed this information against the NRC 

guidance in SRP-LR Section 4.1 to determine if the applicant provided sufficient information 

pursuant to TLAA identification requirements in 10 CFR 54.21(c)(1) and exemption identification 

requirements in 10 CFR 54.21(c)(2).

4.1.2.1 Evaluation of the Applicant’s Identification of TLAAs

As defined in 10 CFR 54.3, an analysis in the CLB meets the definition of a TLAA if it meets the 

following criteria:

(1) involves systems, structures, and components (SSCs) within the scope of license 

renewal as described in 10 CFR 54.4(a)

(2) considers the effects of aging

(3) involves time-limited assumptions defined by the current operating term (for example, 

40 years)

(4) is determined to be relevant by the applicant in making a safety determination

(5) involves conclusions, or provides the basis for conclusions, related to the capability of 

the SSC to perform its intended functions, as described in 10 CFR 54.4(b)

(6) is contained or incorporated by reference in the CLB

The staff’s Statement of Consideration (SOC) for 10 CFR Part 54, in Section III.g.(i) of Nuclear 

Power Plant License Renewal; Final Rule 60 FR 22461, 22479-22481 (May 8, 1995), provides

additional clarification on when an analysis in the CLB needs to be identified as a TLAA.

The staff noted that LRA Table 4.1-1 identifies those analyses in the applicant’s CLB that meet 

the definition of a TLAA in 10 CFR 54.3. The staff’s evaluation of the applicant’s disposition for 

these TLAAs, in accordance with 10 CFR 54.21(c)(1), are documented in the applicable 

subsections of SER Section 4. The staff also noted that, in LRA Tables 4.1-1 and 4.1-2, the 

applicant identified the following analyses in the CLB that do not meet the definition of a TLAA:

• 4.3 Metal Fatigue Analysis

– 4.3.2.1 Thermal Stresses in Piping Connected to RCS: NRC Bulletin 88-08

– 4.3.6 Fatigue Crack Growth, Fracture Mechanics Stability, or Corrosion 

Analyses Supporting Repair of Alloy 600 Materials

• 4.5 Concrete Containment Tendon Prestress
Time-Limited Aging Analyses

3

• 4.7 Plant-Specific Time-Limited Aging Analyses

– 4.7.1 Reactor Pressure Vessel (RPV) Underclad Cracking Analyses

– 4.7.8 Reactor Coolant Pump: Code Case N-481

– 4.7.12 Metal Corrosion Allowance

– 4.7.13 Inservice Flaw Growth Analyses that Demonstrate Structural Stability for 

40 years

For each of these analyses, the applicant’s conclusion that the analysis is not a TLAA was 

reviewed against the applicant’s CLB and the criteria of a TLAA. The staff’s review was 

performed in accordance with the review procedures in SRP-LR Section 4.1.3 and the 

acceptance criteria in SRP-LR Section 4.1.2, considering the clarification in Section III.g.(i) of 

the SOC for 10 CFR Part 54 (60 FR 22, 479-81). The staff's review and findings for each item 

are provided in the SER section indicated.

4.1.2.2 Evaluation of the Applicant’s Identification of those Exemptions in the CLB that 

are based on TLAAs

As required by 10 CFR 54.21(c)(2), the applicant must list all exemptions granted under 

10 CFR 50.12 that are based on TLAAs and then provide an evaluation that justifies the 

continuation of these exemptions through the period of extended operation. LRA Section 4.1.3 

states that the UFSAR, the facility operating license, the SER and associated supplements, and 

all docketed correspondence were reviewed for active exemptions granted under 10 CFR 50.12 

to determine if these exemptions were based on TLAAs. The applicant stated that no active 

exemptions, granted pursuant to 10 CFR 50.12 and based on a TLAA, have been identified.

The staff reviewed the following documents to verify if there were exemptions in the CLB, 

granted in accordance with 10 CFR 50.12, that were based on a TLAA:

• Seabrook Station (Seabrook), Unit No. 1, Facility Operating License No. NPF-86

• applicable exemptions on neutron irradiation embrittlement analyses, requested 

pursuant to requirements in 10 CFR 50.60(b) and granted under the requirements in 

10 CFR 50.12

The staff noted that, on November 12, 2002, the applicant requested an exemption from 

compliance with the pressure-temperature (P-T) limit generation requirements of 

10 CFR Part 50, Appendix G. The applicant requested this exemption in accordance with 

10 CFR 50.60(b) for NRC approval to use ASME Code Case N-641 as the basis for generating 

its P-T limit curves. The staff granted this exemption in accordance with 10 CFR 50.12 by its 

safety evaluation (SE) and exemption approval letter to the applicant dated August 1, 2003. 

The staff noted that this exemption allows the applicant to generate the P-T limit curves using 

the adjusted reference temperature (ART) equation for a KIc linear elastic fracture toughness 

criterion. The staff also noted that this exemption has a specific relationship to the applicant’s 

generation of its P-T limit curves, which is identified as a TLAA and is documented in LRA 

Section 4.2.4. Therefore, the staff noted that this exemption may need to be identified in 

accordance with 10 CFR 54.21(c)(2).

By letter dated January 5, 2011, the staff issued RAI 4.1-3, requesting the applicant to clarify 

and justify whether this exemption needs to be identified in accordance with 10 CFR 54.21(c)(2) 

and if continuation of the exemption will be needed for the period of extended operation. In its 
Time-Limited Aging Analyses

4

response dated February 3, 2011, the applicant stated that a discussion of this exemption 

should have been included in LRA Section 4.1.3; however, the conclusion stated in LRA 

Section 4.1.3 remains unchanged. In response to RAI 4.1-3, the applicant added the following 

to the “Analysis” section of LRA Section 4.1.3:

On November 12, 2002, Seabrook Station requested an exemption from 

compliance with the pressure-temperature (P-T) limit generation requirements of 

10 CFR Part 50, Appendix G. Seabrook Station requested this exemption in 

accordance with 10 CFR 50.60(b), specifically, requesting NRC approval to use 

ASME Code Case N-641 as the basis for generating its P-T limit curves. The 

NRC staff granted this exemption in accordance with 10 CFR 50.12 by its safety 

evaluation and exemption approval letter dated August 1, 2003.

The applicant also stated in its response to RAI 4.1-3 that the exemption for use of the KIC curve 

is not based on a TLAA because the reference toughness curve will not change with time. The 

applicant added that the effects of neutron fluence on the RPV beltline materials must be 

monitored, and the aging effects due to neutron irradiation are managed as a TLAA under LRA 

Section 4.2.4 by the Reactor Vessel Surveillance Program. However, the applicant stated that 

any changes in the fracture toughness properties of the limiting vessel materials would not 

affect the continuation of the exemption to use Code Case N-641 for the period of extended 

operation, which serves as the basis for generating the applicant’s P-T limit curves (refer to LRA 

Section 4.2.4 and SER Section 4.2.4). The applicant further added that Regulatory Issue 

Summary (RIS) 2004-04 indicates that the use of NRC-approved ASME Code Cases in 

conjunction with earlier versions of the ASME Code endorsed in 10 CFR 50.55a may also be 

used for development of P-T limit curves without the need for an exemption.

The staff reviewed the information in RIS 2004-04 and determined that it identifies that 

exemptions are no longer necessary for implementation of the methodology in ASME Code 

Case N-641. In addition, the staff confirmed that the methodology in ASME Code Case N-641 

is currently endorsed for use in RG 1.147; thus, 10 CFR 50.55a(b)(5) and RG 1.147 no longer 

require an exemption for implementation of the Code Case methodology.

Based on the review, the staff finds the applicant’s response to RAI 4.1-3, and the applicant’s 

conclusion that this exemption does not need to be included in the LRA, acceptable because an 

exemption is no longer required for application of the Code Case methodology to the P-T limits. 

The staff’s evaluation of the P-T limits is documented in SER Section 4.2.4. The staff’s concern 

described in RAI 4.1-3 is resolved.

Based on the information provided by the applicant regarding the process used to identify these 

exemptions and its results, the staff concludes that, in accordance with 10 CFR 54.21(c)(2), 

there are no TLAA-based exemptions that need to be justified for continuation through the 

period of extended operation.

4.1.3 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable list of 

TLAAs, as required by 10 CFR 54.21(c)(1). The staff confirmed, as required by 

10 CFR 54.21(c)(2), that no exemptions exist in the CLB that have been granted pursuant to 

10 CFR 50.12 and have been based on a TLAA.
Time-Limited Aging Analyses

5

4.2

The regulations governing RPV integrity are in 10 CFR Part 50, which requires that all 

light-water reactors must comply with the fracture toughness requirements for the reactor 

coolant pressure boundary (RCPB), including those for upper-shelf energy (USE) analyses and 

P-T limit analyses, as set forth in 10 CFR Part 50, Appendix G. Light-water reactors must also 

comply with the Reactor Vessel Surveillance Program requirements for the RCPB, as set forth 

in 10 CFR Part 50, Appendix H. In addition, licensees of pressurized-water reactor 

(PWR)-plants are required to perform analyses for prevention of pressurized thermal shock 

(PTS) events, consistent with the PTS requirements of 10 CFR 50.61 or the alternative PTS 

requirements of 10 CFR 50.61a. The Seabrook CLB analyses of RPV fracture toughness 

reduction due to neutron embrittlement for 40 years are TLAAs. 

Reactor Pressure Vessel Neutron Embrittlement

The NRC’s recommended “acceptance criteria” and “review procedure” guidance related to the 

acceptance of TLAAs on RPV neutron embrittlement are given in SRP-LR Section 4.2 and its 

subsections. For USE analyses, the recommended “acceptance criteria” guidance is given in 

SRP-LR Section 4.2.2.1.1, and the recommended “review procedure” guidance is given in 

SPR-LR Section 4.2.3.1.1. For PWR PTS analyses or alternative PTS analyses, the 

recommended “acceptance criteria” guidance is given in SRP-LR Section 4.2.2.1.2 and the 

recommended “review procedures” are given in SPR-LR Section 4.2.3.1.2. For P-T limit 

analyses, the recommended “acceptance criteria” guidance is given in SRP-LR 

Section 4.2.2.1.3, and the recommended “review procedure” guidance is given in SPR-LR 

Section 4.2.3.1.3. These SRP-LR “acceptance criteria and “review procedures” sections are 

subdivided into sections that provide the staff’s guidance for dispositioning these TLAAs in 

accordance with 10 CFR 54.21(c)(1)(i), 10 CFR 54.21(c)(1)(ii), or 10 CFR 54.21(c)(1)(iii).

4.2.1 Reactor Pressure Vessel Fluence

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 summarizes the evaluation of reactor vessel fluence for the period of 

extended operation, projecting neutron exposure levels for the RPVs for an operating period 

extending to 55 effective full-power years (EFPY). 

The applicant states that the current license period reactor vessel embrittlement analyses, 

which evaluate the reduction of fracture toughness properties for the Seabrook reactor vessel 

beltline materials, are based on predicted 40-year EOL fluence values. The applicant states 

that the neutron fluence analysis and the neutron embrittlement analyses, which are based 

upon the fluence analysis, are TLAAs, as defined by 10 CFR 54.21(c)(1). The applicant states 

that these TLAAs must be evaluated for the increased neutron fluence associated with 60 years 

of operation. The applicant states that the TLAAs impacted by the neutron fluence analysis 

include the analyses for evaluating the ductile fracture toughness of the reactor vessel beltline 

components (i.e., USE analysis), protecting the reactor vessel against PTS events (PTS 

assessment), and the P-T limits analysis and low temperature overpressure protection (LTOP) 

analysis that is dependent on the P-T limits analysis. The applicant states that these fracture 

toughness property-related analyses are discussed in LRA Sections 4.2.2, 4.2.3, and 4.2.4.

The applicant stated that the end-of-life fluence is based on a predicted value of EFPY over the 

life of the plant. As of October 30, 2009, Seabrook Station has been operated for approximately 

17 EFPY. If Seabrook Station is operated at the maximum licensed power level at a 100% 

capacity factor between outages until the end of period of extended operation on 
Time-Limited Aging Analyses

6

March 15, 2050, Seabrook Station will reach approximately 55 EFPY. This capacity factor is 

based on assumed outage durations of twenty (20) days during refueling outages and 100 

percent power levels at all times other than during these outages. For license renewal, 

Seabrook Station updated fluence projections based upon 55 EFPY as input, to the neutron 

embrittlement analyses prepared for 60 years of operation.

The applicant also stated that the fluence values were calculated using the RAMA 

Fluence Methodology (RAMA). The RAMA Fluence Methodology was developed for the 

Electric Power Research Institute, Inc. (EPRI) for the purpose of calculating fast neutron 

fluence in reactor pressure vessels and vessel internal components. As prescribed in 

NRC Regulatory Guide 1.190, RAMA has been benchmarked against industry standard 

benchmarks for both pressurized water reactor (PWR) and boiling water reactor designs.

In addition, RAMA has been compared with several plant-specific dosimetry 

measurements and reported fluence from several commercial operating reactors. The 

results of the benchmarks and comparisons to measurements show that RAMA 

accurately predicts specimen activities, RPV fluence, and vessel component fluence in 

all light water reactor types. Under funding from EPRI and the Boiling Water Reactor 

Vessel and Internals Project, the RAMA methodology has been reviewed by the NRC 

and subsequently given generic approval for determining fast neutron fluence in boiling 

water reactor pressure vessels and vessel internal components that include the core 

shroud and top guide. This prior work has been extended in the Seabrook Station 

analysis to additional PWR benchmarks and plant-specific dosimetry comparisons, 

further validating the use of RAMA for all light water reactor designs.

The applicant provided its updated 60-year (55 EFPY) reactor vessel inside surface fluences for 

the reactor vessel beltine materials in LRA Table 4.2.1-1. In this TLAA, the applicant states that 

the 55 EFPY neutron fluence values for the Seabrook reactor vessel have been projected to the 

end of the period of extended operation and that the 55 EFPY neutron fluences are, therefore,

acceptable in accordance with the criterion in 10 CFR 54.21(c)(1)(ii).

4.2.1.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.1 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

neutron fluence analyses have been projected to the end of the period of extended operation.

The staff noted that the applicant stated that the methodology for calculating the Seabrook 

neutron fluence values complies with the staff recommendations that are provided in RG 1.190, 

“Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence.” The 

applicant is using the RAMA methodology to calculate the 55 EFPY neutron fluence values (in 

terms of n/cm2 (E > 1.0 MeV)) for the Seabrook reactor vessel beltline components. The RAMA 

methodology, while approved by the NRC to calculate fluence values for boiling-water reactor 

(BWR) vessel beltline components, has not explicitly been approved to calculate fluence values 

for PWR geometries.

The staff requested additional information in light of the following excerpt from the application: 

“This prior work has been extended in the Seabrook Station analysis to additional PWR 

benchmarks and plant-specific dosimetry comparison, further validating the use of RAMA for all 

light water reactor designs.”

Specifically, RAI 4.2.1-1 requested that the applicant provide documentation of the referenced 

additional PWR benchmarks and plant-specific dosimetry comparisons to demonstrate 
Time-Limited Aging Analyses

7

adherence to the regulatory positions contained in RG 1.190. In response, the applicant stated 

the following:

In accordance with the requirements of Regulatory Position 1.4 of Regulatory 

Guide 1.190, the RAMA Fluence Methodology has been previously qualified 

using accepted benchmarks prescribed in RG 1.190. Results from the 

qualification effort are presented in Reference 1, BWRVIP-115-A: BWR Vessel 

and Internals Project, RAMA Fluence Methodology Benchmark Manual -

Evaluation of Regulatory Guide 1.190 Benchmark Problems, EPRI, Palo Alto, 

CA: 2009. 1019050. [1019050NP (ADAMS Accession ML100540367)] and have 

been reviewed and accepted by the Staff for application of the RAMA Fluence 

Methodology to boiling water reactor fluence evaluations. The qualifications 

include comparisons to calculated results for the Pool Critical Assembly (PCA) 

and the VENUS-3 vessel simulation benchmarks, comparisons to the H. B. 

Robinson Unit 2 pressure vessel benchmark, and comparisons to the BWR 

calculational benchmark. In support of the Seabrook Station fluence evaluation, 

the qualifications for the RAMA Fluence Methodology are herein extended to 

include comparisons to the PWR calculational benchmark and comparisons to 

plant-specific activation measurements from three surveillance capsules 

irradiated in Seabrook Station. 

The applicant submitted SEA-FLU-001-R-003, Revision 0, “Licensing Version of Seabrook 

Station Reactor Pressure Vessel Fluence Evaluation at 55 EFPY,” which contains the results of 

plant-specific Seabrook surveillance capsule evaluations described above, and 

TWE-FLU-001-R-001, Revision 0, “RAMA Fluence Methodology—Evaluation of Regulatory 

Guide 1.190 PWR Calculational Benchmark,” which documents the comparisons to the PWR 

calculational benchmark.

The applicant’s response continues as follows:

Section 6 of SEA-FLU-00 1 R-003 provides an assessment of the uncertainty in 

the RPV fast neutron fluence predictions for Seabrook Station in accordance with 

RG 1.190, accounting for all experimental, benchmark and plant-specific 

evaluations. The following paragraphs provide a summary of the RAMA 

benchmark and plant-specific comparisons.

The PCA benchmark consists of 27 measurements spanning five different fast 

neutron reactions. The VENUS-3 benchmark consists of 385 measurements 

from three fast neutron reactions. The RAMA calculation-to-measurement (C/M) 

comparisons to the PCA and VENUS-3 vessel simulation benchmarks are 0.99 

with a standard deviation of ±0.05 and 1.03 with a standard deviation of ±0.05, 

respectively. Details of the RAMA models and comparisons for the two vessel 

simulation benchmarks are provided in BWRVIP-115-A.

The H. B. Robinson Unit 2 benchmark consists of activation measurements 

obtained from an in-vessel surveillance capsule and a cavity dosimeter after one 

cycle (cycle 9) of operation. The RAMA C/M comparisons to the H. B. Robinson 

Unit 2 pressure vessel benchmark for the surveillance capsule and cavity 

dosimeter are 0.95 with a standard deviation of ±0.04 and 1.04 ±0.04, 

respectively. Details of the RAMA model and comparisons for the H. B. 

Robinson benchmark are provided in BWRVIP-115-A.
Time-Limited Aging Analyses

8

The PWR calculational benchmark consists of fast neutron flux predictions and 

capsule reaction rate estimates obtained from a discrete ordinates model of a 

typical PWR reactor geometry. Three core loading configurations are included in 

the benchmark: a standard core loading, a low leakage core loading, and a 

partial length shield assembly loading. The average RAMA comparisons to the 

discrete ordinates results are 1.12 with a standard deviation of ±0.11 for the 

standard core loading and 1.02 with a standard deviation of ±0.12 for the low 

leakage core loading. The RAMA-predicted reduction in fast neutron flux for the 

partial length shield assembly loading is 1.01 with a standard deviation of ±0.03 

when compared to the corresponding reduction from the discrete ordinates 

solution. Details of the RAMA models and comparisons for the PWR 

calculational benchmark are provided in TWE-FLU-001-R-001.

Plant-specific activation measurements have been performed for three 

surveillance capsules removed from Seabrook Station after being irradiated for 

one cycle, five cycles, and ten cycles. The average comparisons of 

RAMA-predicted activation to measurements (C/M) for each of the three 

Seabrook Station capsules are 1.08 ± 0.08, 1.05 ± 0.06, and 1.07 ± 0.09. Details 

of the RAMA models and comparisons are provided in SEA-FLU-001-R-003, 

Rev. 0.

The staff notes that the applicant stated, in summary, the following:

• The RAMA methodology is qualified against industry-standard benchmarks, including 

the PCA, VENUS-3, and H. B. Robinson Unit 2 pressure vessel benchmark problems. 

This qualification is NRC staff-approved, as documented in BWRVIP-115A.

• The RAMA methodology was further qualified by comparison to the PWR benchmark 

problems. This qualification considers three different core loading patterns, and it is 

effectively a code-to-code comparison since it consists of discrete ordinates transport 

solutions.

• The RAMA methodology was also qualified against Seabrook-specific capsule 

dosimetry, which included three surveillance capsules removed at various points in the 

Seabrook operating lifetime.

RG 1.190 recommends that calculational methodology be qualified by comparisons to 

measurements and calculational benchmarks, that the calculational bias and uncertainty be 

determined by appropriate combination of both analytic and measurement uncertainty, and that 

the vessel fluence calculational uncertainty be demonstrated to be less than or equal to 

20 percent. While the staff previously reviewed the PCA, VENUS-3, and H. B. Robinson 

benchmarks, the staff presently considered the PWR benchmark problem solutions and the 

plant-specific dosimetry comparisons in its review of the LRA.

The PWR calculational benchmark problems are described in detail in NUREG/CR-6115, “PWR 

and BWR Pressure Vessel Fluence Calculation Benchmark Problems and Solutions.” The 

applicant demonstrated that the benchmark comparisons agreed with acceptable comparison 

ratios in that agreement was within the 20 percent specified in RG 1.190. The staff notes that, 

while standard deviations and comparison ratios, combined together, may have in cases 

exceeded a total of 20 percent (i.e., the ratio for the standard core loading was 1.12±0.11), the 

staff also notes that the comparison is based on two separate numerical techniques and that the 

applicant’s method relies on slightly more sophisticated techniques than those contained in the 

benchmark solutions. The comparison, therefore, incorporates the uncertainties and biases of 
Time-Limited Aging Analyses

9

two methods, not solely those associated with RAMA. Based on these considerations, the staff 

considers the comparison to demonstrate good agreement, and the staff finds the applicant’s 

comparisons to be in accordance with RG 1.190 guidance.

The staff notes that the Seabrook capsule dosimetry comparisons demonstrate good 

agreement, within the 20 percent specified in RG 1.190, and have no readily discernible bias.

Based on its review of the information provided by the applicant, the NRC staff finds that the 

RAMA method was suitably qualified to perform fluence calculations for the Seabrook reactor 

vessel beltline materials. The staff’s finding is based on the fact that the information provided by 

the applicant demonstrated that the RAMA method adheres to RG 1.190 guidance for 

comparison to benchmark problems and plant-specific dosimetry.

The staff also reviewed the reports referenced above by the applicant, including 

SEA-FLU-001-R-003. In addition to documenting the surveillance capsule dosimetry 

qualification, this report also describes the treatment of the Seabrook power history. The report 

states that reactor operating data inputs were developed from plant records and core simulator 

data that provided a historical accounting of how the reactor operated for cycles 1–12. The 

report also detailed how future cycles would be modeled. Based on its review of the information 

contained in the report, the staff finds that the applicant’s fluence calculations adequately 

account for past, present, and planned facility operation through the duration of the extended 

operation.

The NRC staff finds the applicant’s fluence calculations acceptable to support the requested 

renewed facility operating license based on the following:

• The RAMA methodology is generically approved by the NRC staff for BWRs and PWRs.

• RAMA has been adequately benchmarked for analysis of the Seabrook reactor vessel.

• The fluence calculations account for past, present and planned facility operation.

Pursuant to 10 CFR 54.21(c)(1)(ii), the applicant has projected the fluence values to 55 EFPY, 

which represents the end of the period of extended operation.

4.2.1.3 FSAR Supplement 

The applicant provided a final safety analysis report (FSAR) supplement summary description of 

its TLAA evaluation of reactor vessel neutron fluence in LRA Section A.1.2.1.1. On the basis of 

its review of the FSAR supplement, the staff concludes that the summary description of the 

applicant’s actions to address reactor vessel neutron fluence is adequate.

4.2.1.4 Conclusion 

On the basis of its review, the staff concludes that, pursuant to 10 CFR 54.21(c)(1)(ii), the 

applicant has demonstrated that the analyses for reactor vessel neutron fluence have been 

projected to the end of the period of extended operation. The staff also concludes that the 

FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).
Time-Limited Aging Analyses

10

4.2.2 Upper Shelf Energy Analyses

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 dispositions this TLAA in accordance with 

10 CFR 54.21(c)(1)(ii), having projected the Charpy USE using the 55 EFPY fluences described 

in Section 4.2.1 of the LRA, as attenuated to the one-quarter-thickness (1⁄4T) location in the RPV 

wall.

The application states that the Charpy USE for all of the beltline materials of the Seabrook RPV 

were determined according to RG 1.99, Revision 2, without the use of surveillance data 

(Position 1.2 of the RG). The application further states that this approach gave lower (more 

conservative) projections for the USE at the end of the 60-year period of extended operation 

than the alternative using surveillance data (Position 2.2 of the RG), and the projected USE 

values for the beltline and extended beltline materials remain above the 50 foot-pound (ft-lb) 

requirement of Appendix G of 10 CFR Part 50 through the period of extended operation, as 

indicated in LRA Table 4.2.2-1.

4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.2.2 to verify that the Charpy USE analyses have been 

acceptably projected to the end of the period of extended operation, pursuant to 

10 CFR 54.21(c)(1)(ii) and consistent 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 RPV materials after neutron irradiation exposure. The regulation requires the value 

of USE to 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 the licensee can 

demonstrate that these lower values will provide margins of safety against brittle fracture 

equivalent to those required by ASME Code, Section XI, Appendix G.

RG 1.99, Revision 2, provides two methods to determine the projected decrease in USE for an 

RPV material as a function of the neutron fluence for the material. RG Position 1.2 uses curves 

that characterize decrease in USE as a function of the material copper (Cu) content and neutron 

fluence, without specific consideration of the surveillance data for the material. RG Position 2.2 

uses reactor surveillance data to estimate decrease of USE. LRA Section 4.2.2.1 states that 

the applicant used RG Position 1.2 to determine the Charpy USE values at the end of the period 

of extended operation for the RPV materials because RG Position 1.2 projected lower (more 

conservative) USE values for each of these materials.

For the RPV beltline materials, the staff performed its evaluation using the NRC’s Reactor 

Vessel Integrity Database (RVID). The staff found that the Cu content and unirradiated USEs 

for Seabrook RPV beltline materials in LRA Table 4.2.2-1 are almost identical to those in the 

RVID. The discrepancies did not significantly impact the USE evaluations for the subject welds. 

However, because RVID does not contain information for the extended beltline materials, the 

staff requested (part of RAI 4.2.2-1) that the applicant describe the procedures used to 

determine the chemistry data, initial RTNDT, margins, and initial USE values for the extended 

beltline materials. The applicant was asked to demonstrate that it has applied consistent 

approaches for both the beltline and the extended beltline materials.
Time-Limited Aging Analyses

11

The applicant’s February 3, 2011, response provided additional information from certified 

material test records (CMTRs), original equipment manufacturer (OEM) certified letter reports, 

and the Seabrook UFSAR supporting the chemistry and unirradiated USE values in LRA 

Table 4.2.2-1. The staff considers these sources of the information for the extended beltline 

materials to be similar to those that are used for the beltline materials. Hence, consistent 

approaches have been used to determine the material information for both beltline and 

extended beltline materials, and the part of RAI 4.2.2-1 related to USE projections is resolved.

The staff confirmed the applicant’s projected USE values at the end of the period of extended 

operation for beltline and extended beltline materials by using Position 1.2 of RG 1.99, 

Revision 2. The staff’s analysis verified that the lower shell plate B1808-2 was the limiting 

material with a projected USE value of 59 ft-lbs after 56 EFPY.

To summarize, the staff determined that all of the Seabrook RPV extended beltline materials 

have projected USE values at 1⁄4T greater than 50 ft-lbs. Pursuant to 10 CFR 54.21(c)(1)(ii), 

these USE values meet the 10 CFR Part 50, Appendix G, USE requirement at the end of the 

period of extended operation (55 EFPY); therefore, the applicant’s USE analyses are 

acceptable.

4.2.2.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the USE values for RPV materials in LRA Section A.2.4.1.2. On the basis of its review of the 

UFSAR supplement and consistent with SRP-LR Section 4.2.3.1.1.2, the staff concludes that 

the summary description of the applicant’s actions to address USE is adequate.

4.2.2.4 Conclusion

On the basis of its review, consistent with SRP-LR Section 4.2.3.1.1.2, 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 and will meet the criteria defined 

in Appendix G to 10 CFR Part 50. 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 Pressurized Thermal Shock Analyses

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3 summarizes the PTS evaluation of the Seabrook RPV beltline and extended 

beltline materials for the period of extended operation against the screening criteria established 

in accordance with the PTS rule 10 CFR 50.61, “Fracture Toughness Requirements for 

Protection Against Pressurized Thermal Shock Events.” The applicant dispositions this TLAA in 

accordance with 10 CFR 54.21(c)(1)(ii).

For Seabrook, the applicant states that the limiting PTS reference temperature (RTPTS) for plate 

and axial weld material is found for the Lower Shell Plate R1808-1 with an RTPTS value after 

55 EFPY of 123.3 degrees Fahrenheit (°F). The limiting RTPTS value for Seabrook 

circumferentially-oriented welds at 55 EFPY is 8 °F, which corresponds to the intermediate-tolower shell circumferential weld seam (101-171). The applicant concludes that each material in 

the Seabrook RPV that has a surface fluence value exceeding 1.0x1017 n/cm2 (E > 1.0 MeV) at 
Time-Limited Aging Analyses

12

55 EFPY has been demonstrated to have an RTPTS value less than the applicable screening 

criterion; therefore, the RTPTS value analyses have been satisfactorily projected for 60 years of 

operation.

4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 4.2.3 to verify that the PTS 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 

SRP-LR Section 4.2.2.1.2.2.

Per the requirements of 10 CFR 50.61 (the PTS rule), license holders shall have projected 

RTPTS values for each RPV beltline material through the end of their operating license. The 

RTPTS value for each beltline material is evaluated from the following equation:

RTPTS = RTNDT(u) + ΔRTPTS + M

In this equation, RTNDT(u) is the unirradiated RTNDT, as defined in the ASME Boiler and Pressure 

Vessel Code, Section III, Paragraph NB-2331. ΔRTNDT is 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 ΔRTPTS and the margin term M are described in the PTS rule, 

including provisions for the use of surveillance data. The PTS rule also provides the NRCapproved screening criteria for plates, forging, and axial weld materials (270 °F), and for 

circumferential weld materials (300 °F).

In LRA Table 4.2.3-1, the applicant presented the RTPTS values after 55 EFPY for Seabrook. 

Also presented in these tables are the input parameters necessary for calculating the RTPTS

values.

For the RPV beltline materials, the staff performed its evaluation using the NRC’s Reactor 

Vessel Integrity Database (RVID). The staff found that the Cu and nickel (Ni) contents and 

unirradiated RTNDT for Seabrook RPV beltline materials in LRA Table 4.2.3-1 are almost 

identical to those in the RVID. The discrepancies did not significantly impact the RTPTS

evaluations for the subject welds. However, because RVID does not contain information for the 

extended beltline materials, the staff requested (part of RAI 4.2.2-1) that the applicant describe 

the procedures used to determine the chemistry data, initial RTNDT, and margins for the 

extended beltline materials to demonstrate that they have applied consistent approaches for 

both the beltline and the extended beltline materials.

The applicant’s February 3, 2011, response provided additional information from CMTRs, OEM 

certified letter reports, and the Seabrook UFSAR supporting the chemistry and unirradiated 

RTNDT values in LRA Table 4.2.3-1. The staff considers these sources of the information for the 

extended beltline materials to be similar to those that are used for the beltline materials. Hence, 

consistent approaches have been used to determine the material information for both beltline 

and extended beltline materials, and the section of RAI 4.2.2-1 related to RTPTS projections is 

resolved.

In summary, the staff performed a PTS evaluation for each of the extended beltline materials in 

Table 4.2.3-1. In all cases, the applicant’s projected RTPTS values from Table 4.2.3-1 were 

equal or more than that calculated by the staff, which confirms the validity (conservative nature) 

of the applicant’s evaluation. The staff’s analysis agrees with the applicant’s projected RTPTS

value of 123.3 °F for the limiting material for Seabrook (lower shell R1808-1).
Time-Limited Aging Analyses

13

Based on the above discussion the staff concludes that all Seabrook RPV beltline and extended 

beltline materials satisfy the PTS requirements of 10 CFR 50.61 through the period of extended 

operation. The applicant’s TLAA is acceptable because it meets the requirements of 

10 CFR 54.21(c)(1)(ii) and will ensure that the Seabrook RPV materials have adequate RTPTS

values and fracture toughness through the period of extended operation.

4.2.3.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

PTS in LRA Section A.2.4.1.3. On the basis of its review of the UFSAR supplement and 

consistent with SRP-LR Section 4.2.3.1.2.2, the staff concludes that the summary description of 

the applicant’s actions to address PTS is adequate.

4.2.3.4 Conclusion

On the basis of its review and consistent with SRP-LR Section 4.2.3.1.2.2, the staff concludes

that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the PTS analyses 

have been projected to the end of the period of extended operation and will continue to meet the 

requirements of the PTS rule (10 CFR 50.61). 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 Reactor Vessel Pressure-Temperature Limit and Low-Temperature Overpressure 

Protection Analyses

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 summarizes the evaluation of the RPV pressure-temperature (P-T) limit and 

low-temperature overpressure protection (LTOP_ analyses (collectively referred to as the P-T 

limit analyses) for the period of extended operation. The applicant developed the adjusted 

reference temperature (ART) values based on the material properties in LRA Table 4.2.3-1 and 

the 1⁄4 and 3⁄4 RPV wall thickness (1⁄4T and 3⁄4T) fluences for 55 EFPY. The resulting ART values 

for the limiting RPV materials at Seabrook were summarized in LRA Table 4.2.4-1 and were 

used to develop the P-T limits in accordance with the requirements of 10 CFR Part 50, 

Appendix G and Appendix G to Section XI of the ASME Code. Specifically, the LRA states that 

the Seabrook P-T limit curves for normal heatup and cooldown were developed using the 

1995 Edition through the 1996 Addenda of the ASME Code, Section Xl, Appendix G 

methodology and ASME Code Case N-641, “Alternative Pressure-Temperature Relationship 

and Low Temperature Overpressure Protection System Requirements.”

The LRA states that the P-T limits analyses have been projected to the end of the period of 

extended operation; however, they will not be submitted with the LRA. The LRA concludes that 

the effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. The application describes how the Reactor Vessel Surveillance Program 

(LRA B.2.1.19) monitors RPV embrittlement and provides data to update the P-T limits and, 

therefore, permits Seabrook to manage the P-T limits going forward, in accordance with 

10 CFR 54(c)(1)(iii). The LRA states that the applicant will submit updates to the P-T limits for 

Seabrook to the NRC at the appropriate time to comply with 10 CFR Part 50, Appendix G.
Time-Limited Aging Analyses

14

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) and consistent with SRP-LR Section 4.2.2.1.3.3.

LRA Section 4.2.4 states that updated P-T limits for the period of extended operation have been 

projected to the end of the period of extended operation; however, the applicant did not update 

the P-T limits in the LRA. The staff does not require the updated P-T limit curves for the period 

of extended operation to be submitted as part of this TLAA in the applicant’s LRA. Prior to the 

expiration of the facility’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, considering the increase of the limiting 

ART and plant-specific embrittlement information from additional surveillance data provided by 

the Reactor Vessel Surveillance Program. 

As a part of a separate licensing action on P-T limits submitted by letter dated 

November 17, 2011, the applicant requested approval of P-T limits that would, based on an 

updated neutron fluence evaluation, extend the operating time of the current curves from 

20 EFPY to 23.7 EFPY. The actual P-T limits and cold overprotection system setpoint curves 

do not change in the license amendment request (LAR). 

During its review of the LAR, the staff,requested by letter dated April 25, 2012, that the applicant

provide additional information related to whether the methodology used to develop the P-T limits 

is consistent with the requirements in 10 CFR 50, Appendix G. Because the methodology used 

to develop the P-T limits during the initial operating period is the same as that to be used during 

the period of extended operation, this additional information is also pertinent to the review of the 

LRA. Until the LAR questions are resolved, this item is identified as Open Item 4.2.4-1.

4.2.4.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

P-T limits in LRA Section A.2.4.1.4. On the basis of its review of the UFSAR supplement, 

consistent with SRP-LR Section 4.2.3.1.3.3 and pending resolution of Open Item 4.2.4-1, the 

staff concludes that the summary description of the applicant’s actions to address P-T limits is 

adequate.

4.2.4.4 Conclusion

On the basis of its review, pending resolution of Open Item 4.2.4-1, and consistent with SRP-LR 

Section 4.2.3.1.3.3, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the the P-T limits will be adequately 

managed by the applicant for the period of extended operation. The staff also concludes that 

the UFSAR supplement contains an appropriate summary description of the TLAA evaluation, 

as required by 10 CFR 54.21(d).

4.3

LRA Section 4.3 provides the assessment of the metal fatigue analyses for the applicant’s 

pressure boundary components, including the RPV, RCPs, steam generators, pressurizer, 

piping, valves, and components of primary, secondary, auxiliary, steam, and other systems. 

The applicant considered these metal fatigue analyses as TLAAs for license renewal. The 

Metal Fatigue Analysis of Piping and Components
Time-Limited Aging Analyses

15

applicant stated that its nuclear steam supply system (NSSS) components are designed to 

ASME Code Section III, Class 1 rules (1971 Edition with addenda through summer 1972).

The applicant further stated that the fatigue evaluations discussed in LRA Section 4.3 can be 

classified into the following categories:

• explicit fatigue analyses for NSSS pressure vessel (i.e., the RPV) and components 

prepared in accordance with ASME Code Section III, Class A or Class 1 rules, 

developed as part of the original design

• supplemental explicit fatigue analyses for piping and components that were prepared in 

accordance with ASME Code Section III rules to evaluate transients that were identified 

after the original design analyses were completed

• new fatigue analyses (also in accordance with ASME Code Section III, Class 1 rules) 

prepared for license renewal to evaluate the effects of the reactor water environment on 

the sample of high fatigue locations applicable to newer vintage Westinghouse plants

4.3.1 Nuclear Steam Supply System Pressure Vessel and Component Fatigue Analyses 

(RPV and RPV Component Fatigue Analyses)

4.3.1.1 Summary of Technical Information in the Application

LRA Section 4.3.1 describes the applicant’s TLAA for RPV and RPV component fatigue 

analyses. The applicant stated that the most limiting numbers of transients used in these NSSS 

component analyses are provided in LRA Table 4.3.1-2 and are considered design limits.

The applicant further stated that, since each Class 1 fatigue analysis is based upon the 40-year 

assumption for a set of design transients, these fatigue analyses have been identified as TLAAs 

that require evaluation for 60 years of plant operations. To determine if the fatigue analyses 

would remain valid for 60 years of service, a review of fatigue monitoring data was performed to 

determine the number of cumulative cycles for each transient that has occurred during past 

plant operations. For each transient, the applicant determined the average rate of occurrence 

based on past operation and then projected the number of future cycles using this average rate 

of occurrence. The applicant stated that the 60-year projection, provided in LRA Table 4.3.1-3, 

was determined by adding the cumulative number of occurrences as of April 1, 2009, and the 

projected number of future cycles. The applicant also stated that the methodology used to 

determine the 60-year projection is considered to produce a conservative estimate due to the 

declining trend of most of the transients since the beginning of plant operation. The applicant 

stated that the 40-year design transients bound the numbers of cycles projected to occur during 

60 years of plant operations. The applicant dispositioned the RPV and RPV component fatigue 

TLAAs in accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of 

extended operation.

4.3.1.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1 and the RPV and RPV components including Class 1 

valves fatigue analyses TLAAs to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses 

remain valid for the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with 

SRP-LR Section 4.3.3.1.1.1. This SRP section requires that the staff review include the 
Time-Limited Aging Analyses

16

operating transient experience and a list of the assumed transients used in the existing 

cumulative usage factor (CUF) calculations for the current operating term to ensure that the 

number of assumed transients would not be exceeded during the period of extended operation.

LRA Table 4.3.1-2 lists the most limiting numbers of transients that are used in the RPV and 

RPV component fatigue analyses and are considered the design limits. The staff confirmed that 

these transients are consistent with those listed in UFSAR Table 3.9(N)-1; however, LRA 

Table 4.3.1-2 lists more design transients than those identified in TS 5.7 and TS Table 5.7-1. It 

was not clear to the staff if the design fatigue analyses for the RPV and its components were 

based on the design transients in TS Table 5.7-1 or the non-TS transients that were included in 

LRA Table 4.3.1-2 and UFSAR Table 3.9(N)-1. The staff also noted that the transients were 

termed differently between the LRA, UFSAR, and applicant’s program basis documents. In 

addition, the UFSAR and the applicant’s program basis documents for the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program include auxiliary transients such as “charging and 

letdown flow shutoff and return” or “letdown flow step decrease and return,” which are not in 

LRA Table 4.3.1-2.

As described in SER Section 3.0.3.2.21, the staff issued RAIs B.2.3.1-1 and B.2.3.1-2 by letter 

dated December 14, 2010, asking the applicant to clarify if the fatigue analyses were based on 

transients from TS Table 5.7-1 or LRA Table 4.3.1-2 and to confirm that the plant-specific cycle 

counting procedure tracks and monitors the transients listed in LRA Table 4.3.1-2. The staff 

also asked the applicant to clarify and justify the difference of designations for the transients and 

to clarify the significance of the auxiliary transients used in fatigue CUF analyses. The staff’s 

evaluation of the applicant’s responses to these RAIs is documented in SER Section 3.0.3.2.21. 

The staff found the applicant's design transient cycle counting basis, as amended in response to 

RAI B.2.3.1-1, acceptable because the applicant provided an adequate explanation that the 

CUF analyses were based on the transients in LRA Table 4.3.2-1 and not only those transients 

in TS Table 5.7-1. Further, the applicant amended LRA Table 4.3.1-2 to provide an updated list 

of all transients that will be monitored by the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program during the period of extended operation. The staff also found the applicant's 

design transient cycle counting basis, as amended in responses to RAI B.2.3.1-2, acceptable 

because the applicant did the following: 

• provided an adequate explanation for the difference in the transient designations and 

categories that were listed in LRA Table 4.3.1-2

• provided an adequate summary on how the Metal Fatigue of RCPB would track and 

monitor the number of transients occurring at the facility

• provided an adequate explanation of the significance of those auxiliary system transients 

that were analyzed for in the fatigue calculations

LRA Section 4.3.1 discusses the 60-year transient projection methodology that was determined 

by adding the cumulative number of occurrences as of April 1, 2009, to the number of cycles 

predicted to occur in the 41 years of future operation. The staff noted that the 60-year projected 

cycles for the “Unit Loading Between 0% and 15% Power” and “Unit Unloading Between 0% 

and 15% Power” transients in LRA Table 4.3.1-3 are not consistent with the current count for 

these transients. In particular, the projected numbers (listed as 13 and 10) are less than the 

actual counts as of April 1, 2009, (listed as 27 and 26) for the “Unit Loading Between 0% and 

15% Power” and “Unit Unloading Between 15% and 0% Power” transients, respectively.
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17

By letter dated January 5, 2011, the staff issued RAI 4.3.1-1 asking the applicant to justify why 

the values of 60-year projected cycles are less than the values of the “Current Cycles” for these 

two transients.

In its response dated February 3, 2011, the applicant acknowledged that LRA Table 4.3.1-3 

incorrectly reflects the values of 60-year projected cycles as less than the values of current 

cycles for “Unit Loading and Unloading Between 0% and 15% Power” transients. The applicant 

stated that the current cycle counts and the 60-year projection “Unit Loading Between 0% and 

15% Power” should be 27 and 70, respectively. The applicant also indicated that the current 

cycle counts and the 60-year projection for “Unit Unloading Between 15% and 0% Power” 

should be 26 and 65, respectively.

LRA Section 4.3.1 states that the 60-year cycle projection for the “the transients were linearly 

extrapolated based on the rate of accumulation for the data available through April 1, 2009. 

Based on its review, the staff found that the applicant’s response was unacceptable because 

the revised values for the 60-year projected cycles for the two transients were not linearly 

extrapolated based on the rate of accumulation for the data available through April 1, 2009. The 

staff noted that, if these transients were linearly extrapolated, the resultant 60-year projected 

cycles would be approximately 87 and 83 cycles for the “Unit Loading Between 0% and 15% 

Power” and “Unit Unloading Between 15% and 0% Power” transients, respectively.

By letter dated March 30, 2011, the staff issued followup RAI 4.3.1-1b asking the applicant to 

provide the basis and justify the 60-year projected values for the unit loading and unit unloading 

transients. In its response dated April 22, 2011, the applicant stated that a revised manual 

count revealed that there have been 48 occurrences of each of the two events (“Unit Loading 

between 0% and 15% Power” and “Unit Unloading between 15% and 0% Power”) between the 

start of plant operation in August of 1990 and October 2009 (18.6 years of full power operation). 

The applicant stated that, using a linear projection, the 60-year projected count of 155 is less 

than the design basis of 500 cycles. The staff noted that, in LRA Section 4.3.1, the applicant 

discussed that the linear extrapolation is conservative due to the declining trend of most of the 

transients since the beginning of plant operation.

Based on its review, the staff finds the applicant’s response to RAI 4.3.1-1b acceptable because 

the applicant projected the occurrence of the two transients using a projection method that is 

consistent with that for other transients in the LRA and the projected counts of the two transients 

are less than the design basis for these transients. The staff’s concern described in 

RAI 4.3.1-1b is resolved.

The staff noted that, in LRA Table 4.3.1-3, the number of NSSS design cycles for the feedwater 

heaters out of service transient is “120” with footnote (5), which indicates that the original design 

cycles is assumed to be the anticipated number of cycles at the end of the period of extended 

operation. However, the staff noted that the number of 60-year projected cycles, in LRA 

Table 4.3.1-3, for this transient is 39 cycles. The staff also noted that LRA Table 4.3.1-2 

identifies three emergency transients that are RCS design transients. However, the applicant 

did not provide the number of current and 60-year projected cycles for these three emergency 

transients in LRA Table 4.3.1-3.

By letter dated March 30, 2011, the staff issued RAI 4.3.1-2 requesting the applicant to amend 

LRA Table 4.3.1-3 to reflect the proper 60-year projected cycles for the feedwater heaters out of 

service transient or justify why footnote (5) is not applicable to this transient. The staff also 

asked the applicant to provide the number of current and 60-year projected cycles for the three 

emergency transients in LRA Table 4.3.1-3 or justify why cycle projections are not needed. 
Time-Limited Aging Analyses

18

Furthermore, the staff asked the applicant to clarify if these emergency transients will be 

monitored under the Metal Fatigue of Reactor Coolant Pressure Boundary Program or to justify 

why the transients are not monitored. 

In its response dated April 22, 2011, the applicant stated that footnote (5) of LRA Table 4.3.1-3 

is not applicable to the feedwater heaters out of service transient. The staff noted the 60-year 

projected cycle for this transient is consistent with other transient projections in LRA 

Table 4.3.1-3 and the removal of footnote (5) indicates that the transient will be counted in the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. In addition, the applicant stated 

that, for the feedwater cycling at hot shutdown transient, the current cycle count is 192 through 

April 1, 2010, and it is based on the assumption that there are four occurrences of feedwater 

cycling at hot shutdown per each “unit loading between 0% and 15% power” transient. The 

applicant stated that, using a linear projection, the 60-year projected count of 620 is less than 

the design basis of 2,000 cycles. The applicant explained that the linear extrapolation is 

conservative due to the declining trend of most of the transients since the beginning of plant 

operation.

The applicant also stated that the three emergency transients (small break loss-of-coolant 

accident (small break LOCA), small main steam line break, and complete loss of flow), identified 

in LRA Table 4.3.1-2, are not part of its fatigue design basis, and they are not included in the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant stated that these 

three emergency transients have not occurred to date and are not expected to occur during the 

life of the plant. Thus, the applicant stated that the 60-year projected number of cycles for each 

of them is one. The staff noted that the applicant’s 60-year projection of one occurrence for 

each of the three transients is consistent with the projection, in LRA Section 4.3.1, for other 

transients that have not occurred. Based on its review, the staff finds the applicant’s response 

to RAI 4.3.1-2 acceptable for the following reasons:

• The applicant revised and justified the feedwater cycling at hot shutdown transient 

current cycle count and 60 year projection; and 

• The applicant clarified that certain transients have been appropriately included in the 

cycle projection to support its TLAA disposition basis.

The staff’s concern described in RAI 4.3.1-2 is resolved.

The staff finds the use of this linear extrapolation conservative because the applicant 

considered the time period when it experienced frequent transient occurrences in its 

extrapolation and did not only consider its recent improved operating history.

The staff noted that LRA did not provide the CUF values of record for the RPV and RPV 

components (LRA Section 4.3.1), the ASME Section III Class 1 piping and components (LRA 

Section 4.3.2), or the reactor vessel internals (RVIs) (LRA Section 4.3.3). Without these values, 

the staff could not ascertain whether the CUF for any location exceeded the allowable limit or 

evaluate the applicant’s dispositions for these TLAAs in accordance with 10 CFR 54.21(c). 

Furthermore, the staff noted that UFSAR Table 3.9(B)-21 provides a CUF value of 0.95 for the 

ASME Section III Class 1 piping of the RCS pressurizer safety and relief valve system. LRA 

Table 3.1.2-1 indicates that, for the component “Valve Body (Class 1),” a TLAA is used to 

manage cumulative fatigue damage; however, LRA Section 4.3 did not provide the details of a 

fatigue analysis for ASME Code Class 1 valves. It was not clear to the staff how the metal 

fatigue TLAA of all Class 1 valves were dispositioned in accordance with 10 CFR 54.21(c).
Time-Limited Aging Analyses

19

By letter dated January 5, 2011, the staff issued RAI 4.3-1 asking the applicant to do the 

following:

• provide the original design basis 40 year CUF values and projected 60 year CUF values 

for all components or critical locations or both that are applicable to the dispositions in 

LRA Sections 4.3.1, 4.3.2, and 4.3.3 

• clarify and justify the disposition of all Class 1 valves metal fatigue analyses that are 

TLAAs in accordance with 10 CFR 54.21(c) 

In its response dated February 3, 2011, the applicant provided the original design basis 40-year 

CUF values for all components that are applicable to the dispositions in LRA Sections 4.3.1, 

4.3.2, and 4.3.3. The applicant stated that, since the original 40-year design-basis number of 

transient cycles will not be exceeded during the period of extended operation, the fatigue 

analyses for these components will be dispositioned in accordance with 10 CFR 54.21(c)(1)(i).

Based on its review, the staff finds the applicant’s response to this portion of RAI 4.3-1 

acceptable because the staff confirmed that the projected CUF values will not exceed the 

allowable limit of 1.0, which supports the applicant's TLAA disposition basis.

The applicant also stated, in its response to RAI 4.3-1, that fatigue conformance of ASME 

Class 1 valves was demonstrated by performing an “umbrella” fatigue analysis of the piping 

system which contains the valves, in accordance with ASME Section III, Subsection NB-3650. 

The applicant stated that, for all transient loading combinations, allowable moment ranges were 

developed so that the requirements of Subsection NB-3650 are met and fatigue conformance of 

the analyzed valves was demonstrated when CUF value of the umbrella fatigue analysis is less 

than 1.0. The applicant stated that design-basis plant transients listed in LRA Table 4.3.1-2 

were considered in these “umbrella” fatigue analyses in terms of severity and number of 

occurrences. The applicant also indicated that the “umbrella” fatigue analyses is dispositioned 

in accordance with 10 CFR 54.21(c)(1)(i) because the design-basis number of the occurrences 

of the transients will not be exceeded during the 60-year period.

During its review, the staff noted that UFSAR Section 3.9(N).1.4(e), “Analysis of Primary 

Component,” states that the pressure boundary portions of Class 1 valves in the RCS were 

designed and analyzed according to the requirements of ASME Code Section III, NB-3500 

(1971 Edition including 1972 Addenda). It was not clear to the staff why a fatigue evaluation of 

Class 1 valves was performed in accordance with ASME Code Section III Subsection NB-3650, 

“Analysis of Piping Products,” instead of the design requirements of Subsection NB-3500 as 

indicated in UFSAR Section 3.9(N).1.4(e). Furthermore, the applicant did not provide adequate

information for the staff to verify whether the “umbrella” NB-3650 analysis is equivalent or more 

conservative than a NB-3500 analysis.

By letter dated March 30, 2011, the staff issued followup RAI 4.3-1b asking the applicant to 

clarify and explain why Class 1 valve fatigue conformance was demonstrated by an “umbrella” 

fatigue analysis using ASME Code Section III Subsection NB-3650 instead of 

Subsection NB-3500. In addition, the staff asked the applicant to justify that the “umbrella” 

fatigue analysis using Subsection NB-3650 is equivalent to or more conservative than an 

analysis in accordance with NB-3500.

In its response to RAI 4.3-1b dated April 22, 2011, the applicant clarified that the ASME Class 1 

valves in the RCS were designed, analyzed, and qualified for service in accordance with the 

rules of ASME Section III Subsection NB-3500, as stated in the UFSAR Section 3.9(N).1.4(e). 
Time-Limited Aging Analyses

20

The applicant explained that the piping design rules from ASME Section III Subsection NB-3650 

were used to analyze and qualify the piping system, including piping components such as 

installed Class 1 valves. The applicant noted that part of this piping analysis is an umbrella 

fatigue analysis that was discussed in its response to RAI 4.3-1 dated February 3, 2011.

However, the staff noted that the 1971 and later editions of the ASME Code Section III required 

fatigue analyses for valves with an inlet piping connection larger than 4 inches (in.) nominal pipe 

size unless exemption requirements were met. It was not clear to the staff if the fatigue 

analyses for all Class 1 valves performed in accordance with the requirements of the applicable 

ASME codes have been dispositioned in accordance with 10 CFR 54.21(c)(1). By letter dated 

October 7, 2011, the staff issued followup RAI 4.3-1c asking the applicant to provide and justify 

the TLAA disposition for fatigue analysis that were performed for Class 1 valves or justify that 

the fatigue analyses for these Class 1 valves need not to be identified as a TLAA in accordance 

with 10 CFR 54.3.

In its response to RAI 4.3-1c dated November 2, 2011, the applicant stated that a fatigue 

analysis was performed for Class 1 valves that have an inlet piping connection larger than 4 in.

nominal pipe size as part of the original design in accordance with ASME Code Section III 

Subsection NB-3500. The applicant stated that the 40-year design numbers of transient

occurrences that are used in the Class 1 valves fatigue analysis bound the number of cycles 

projected to occur during 60 years of plant operations. Therefore, the applicant concluded the 

fatigue analysis that was based upon the 40-year design transients remain valid for the period of 

extended operation and the TLAA is dispositioned, along with the fatigue analyses of NSSS 

components, in accordance with 10 CFR 54.21(c)(1)(i). The applicant also revised LRA 

Section 4.3.1 specifying that TLAA for Class 1 valves and piping are also included. The staff 

noted that the 60-year projections for the design transients are included in LRA Table 4.3.1-3. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-1c acceptable because 

the applicant dispositioned the Class 1 valves fatigue TLAA in accordance with 

10 CFR54.21(c)(1), and the number of assumed design transients in the Class 1 valves fatigue 

analysis would not be exceeded by the projected number of cycles during the period of 

extended operation. The staff’s concern described in RAI 4.3-1c is resolved.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the RPV 

and RPV components, including Class 1 valves fatigue analyses, remain valid for the period of 

extended operation. Additionally, the analyses meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.1.1, because the number of assumed design transients would not be exceeded 

during the period of extended operation.

4.3.1.3 UFSAR Supplement

LRA Section A.2.4.2.1 provides the UFSAR supplement summarizing RPV and RPV 

components including Class 1 valves fatigue analyses. The staff reviewed LRA 

Section A.2.4.2.1 consistent with SRP-LR Section 4.3.3.3, which states that the summary 

description should contain information associated with the evaluation of the RPV and RPV 

component including Class 1 valves fatigue analyses.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP LR Section 4.3.2.3. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address the RPV and RPV components 

including Class 1 valves fatigue analyses, as required by 10 CFR 54.21(d).
Time-Limited Aging Analyses

21

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)(i), that the fatigue analyses for the RPV and 

RPV components, including Class 1 valves, will 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).

4.3.2 Supplementary ASME Section III, Class 1 Piping and Component Fatigue Analysis

LRA Subsection 4.3.2 provides a summary of the applicant’s fatigue analysis for components 

affected by the considerations in NRC Bulletins 88-08 and 88-11. The applicant divided the 

summary into the following subsections:

• NRC Bulletin 88-08: Absence of a TLAA for Thermal Stresses in Piping Connected to 

Reactor Coolant Systems

• NRC Bulletin 88-11: Pressurizer Surge Line Thermal Stratification

Both fatigue analyses address modified or additional transients postulated in response to the 

NRC Bulletins for these ASME Section III Class 1 components, in addition to the original design 

basis transients. LRA Subsection 4.3.2 states that these piping and components were originally 

designed in accordance with the ASME Section III, 1971 Edition including addenda through 

winter 1972. In addition, the related fatigue analyses were updated to address the potential 

valve leakage transients, identified in NRC Bulletin 88-08, for the auxiliary spray line, charging 

lines, and safety injection lines. These analyses were also updated to address the thermal 

stratification transient in pressurizer surge line (PSL), identified in NRC Bulletin 88-11. The 

applicant also stated that both the original and updated analyses do not account for 

environmental effects and either the design cycles or the projected cycles (based on actual 

service cycle counts) enveloped the 60 years of operation.

4.3.2.1 Absence of a TLAA for Thermal Stresses in Piping Connected to RCSs: NRC 

Bulletin 88-08

4.3.2.1.1 Summary of Technical Information in the Application

LRA Section 4.3.2.1 describes the applicant’s evaluation for the absence of a TLAA for thermal 

stresses in piping connected to the RCS. The applicant stated that, in response to NRC Bulletin 

88-08, it evaluated the possibility and effects of fluid in-leakage to the RCS from leaking valves 

by identifying seven piping sections that are unisolable from the RCS and pressurized by the 

charging pumps. The applicable plant-specific locations are four high head safety injection lines 

and three charging system lines. The applicant also stated that, in 1988, prior to initial criticality, 

a one-time non-destructive examination was performed for the four high head safety injection 

lines, and the examination showed acceptable results. In addition, in 1989, prior to initial 

criticality, the applicant deployed a temperature monitoring program for the high head safety 

injection lines and three charging system lines. The LRA stated that this monitoring is still 

installed and credited in its Management of Thermal Fatigue Program for Normally Stagnant 

Non-Isolable Reactor Coolant System Branch Lines (MRP-146/146S). 

The applicant further stated that it evaluated the possibility of and the effects from fluid 

out-leakage and concluded that unisolable piping sections connected to the RCS are not subject 

to stresses from thermal stratification or temperature oscillations resulting from the mechanism 
Time-Limited Aging Analyses

22

described in NRC Bulletin 88-08 and related supplements. The LRA also states that the NRC 

approved Seabrook Station’s response to NRC Bulletin 88-08. Therefore, the applicant stated 

that there is no specific TLAA for locations addressed by NRC Bulletin 88-08 and related 

supplements.

4.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.1 and the applicant’s evaluation for the absence of a 

TLAA for thermal stresses in piping connected to the RCS to verify, consistent with SRP-LR 

Section 4.1.3, the applicant’s basis for concluding that there is no specific TLAA associated with 

the mechanisms described in NRC Bulletin 88-08 and related supplements. 

LRA Section 4.3.2.1 states that unisolable piping sections connected to the RCS are not subject 

to stresses from thermal stratification or temperature oscillations resulting from the mechanism 

described in NRC Bulletin 88-08. The applicant stated that, in the charging system, the 

temperature differences imposed upon the unisolable piping sections during normal operation 

are limited to acceptable values because any leakage would first pass through the regenerative 

heat exchanger and become sufficiently heated. The applicant further stated that it deployed a 

temperature monitoring program that detects adverse temperature distributions and has 

established appropriate temperature limits. The staff confirmed the deployment of the 

temperature monitoring program in applicant’s response to Bulletin 88-08, dated Jan 13, 1989, 

The staff found that the temperature monitoring program was acceptable to provide continuing 

assurance that unisolable sections of all piping connected to the RCS will not be subjected to 

combined cyclic and static thermal and other stresses that could cause fatigue failure during the 

remaining life of the unit. The applicant stated that the monitoring is still installed and credited 

its own Management of Thermal FatigueProgram for Normally Stagnant Non-Isolable Reactor 

Coolant System Branch Lines under MRP-146/146S. The staff noted that the aging effect of 

craking is managed by that the applicant's One-Time Inspection of ASME Code Class 1 Small 

Bore Piping program, which credited the inspection and monitoring recommendations in MRP146/146S. The staff's review of the applicant's One-Time Inspection of ASME Code Class 1 

Small Bore Piping program is doucmented in SER Section 3.0.3.2.13.The staff finds the 

applicant’s conclusion, that there is no specific TLAA associated with NRC Bulletin 88-08, 

acceptable because the applicant has demonstrated that its CLB does not contain an analysis 

that considers cumulative fatigue damage associated with NRC Bulletin 88-08; therefore, it is 

not a TLAA, in accordance with Criteria 2 and 6 of 10 CFR 54.3(a). 

4.3.2.1.3 UFSAR Supplement

On the basis of its review, the staff finds that a UFSAR supplement is not required because a 

TLAA associated with thermal stresses in piping connected to the RCS and NRC Bulletin 88-08 

is not applicable, as described above.

4.3.2.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant demonstrated that the CLB 

does not contain an analysis that considers cumulative fatigue damage associated with NRC 

Bulletin 88-08; therefore, it is not a TLAA. The staff also concludes that a UFSAR supplement is 

not required.
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23

4.3.2.2 NRC Bulletin 88-11, PSL Thermal Stratification

4.3.2.2.1 Summary of Technical Information in the Application

LRA Section 4.3.2.2 provides the applicant’s evaluation of the TLAA for the PSL, pressurizer 

surge nozzle (PSN), and hot leg surge line nozzle (HLSN) subject to thermal stratification and 

striping in addition to the original design transients. The applicant stated that thermal 

stratification was not part of the original piping design, but it was later identified by industry 

operating experience that resulted in issuance of NRC Bulletin 88-11. The applicant also stated 

that it previously evaluated the PSL piping and nozzles for the effects of thermal stratification 

and identified the HLSN as the limiting fatigue location. The applicant further stated that it 

performed the ASME Section III, Class 1, fatigue analysis for both the PSN and the HLSN 

locations for the plant-specific modified transients, based on the NSSS vendor evaluation of its 

operating procedures.

The applicant dispositioned the “NRC Bulletin 88-11, Pressurizer Surge Line Thermal 

Stratification,” related ASME Section III, Class 1, fatigue TLAAs (without environmental effects) 

for the PSL, PSN, and HSLN, in accordance with 10 CFR 54.21(c)(1)(i), that the analyses 

remain valid for the period of extended operation.

4.3.2.2.2 Staff Evaluation

The staff reviewed LRA Subsection 4.3.2.2 and the ASME Section III, Class 1, fatigue TLAAs 

for PSL thermal stratification to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses 

remain valid for the period of extended operation. The staff reviewed these TLAAs and the 

corresponding disposition by the applicant, consistent with SRP-LR Section 4.3.3.1.1.1, which 

states that the operating transient experience and the list of assumed transients in the existing 

CUF calculations for the current operating term should be reviewed to ensure that the number of 

assumed transients would not be exceeded by the number of transient cycles projected to occur 

at the end of the period of extended operation.

LRA Section 4.3.2.2 states that the PSL piping was previously evaluated for the effects of 

thermal stratification and plant-specific transients in 1990, and it was determined that the PSL 

will remain within the ASME Code requirements for the design life. However, the applicant did 

not provide the details of this analysis; therefore, the staff was not able to verify the applicability 

of thermal stratification during the period of extended operation. LRA Section 4.3.2.2 also 

states that the evaluation of the structural weld overlay applied to the PSN includes an 

elastic-plastic formulation and resulted in a CUF value less than 1.0. The staff was not able to 

verify acceptability of the elastic-plastic analyses. By letter dated January 5, 2011, the staff 

issued RAI 4.3.2-1 requesting that the applicant provide the CUF values in the original design 

and updated analyses for 60-year operation, without environmental effects, for all components 

that are applicable to LRA Section 4.3.2.2. The staff also asked the applicant to clarify how the 

elastic-plastic formulation was used in the evaluation to reduce the conservatism that existed in 

the evaluations prior to the structural weld overlay. Furthermore, the staff asked the applicant to 

justify how the disposition of 10 CFR 54.21(c)(1)(i) is appropriate for these components.

In its response to RAI 4.3.2-1 dated February 3, 2011, the applicant provided CUF values for 

the PSL, PSN, and HLSN components from the original design basis analyses, the subsequent 

analyses performed for power uprate, weld overlay repair activity, and in support of license

renewal. The staff noted that the 60-year CUF values in the subsequent analysis in support of 

license renewal are less the limit of 1.0. 
Time-Limited Aging Analyses

24

In its response to RAI 4.3.2-1 Requests 2 and 3, the applicant also clarified that the PSN 

weld-overlay repair was reanalyzed with a non-linear elastic-plastic method to determine the 

refined CUF. The applicant stated that the maximum CUF is 0.6325, and the analysis showed 

that shakedown occurred within 10 cycles (e.g., deformation does not continue after 10 cycles). 

The applicant also stated that transients in the design analyses and updated analyses for the 

PSL, PSN, and HLSN were developed based on the transients listed in LRA Table 4.3.1-2, and 

the occurrences of the thermal stratification transients were correlated to the RCS heatup and 

RCS cooldown transients. The staff noted that for all the transients in LRA Table 4.3.1-2, 

including RCS heatup and RCS cooldown, the current cycle count and the 60-year projections 

are bounded by NSSS design limits.

Based on its review, the staff finds the applicant’s response to RAI 4.3.2-1 acceptable because 

(1) the CUF values for the PSL, PSN, and HLSN are less than 1.0; (2) the applicant 

demonstrated that the reduction in excess conservatism was appropriate in accordance with 

ASME Code Section III, Subsection NB-3228, on plastic analysis, which permits the relaxation 

of stress limits provided that shakedown is confirmed by the analysis; and (3) the applicant 

supported the 10 CFR 54.21(c)(1)(i) disposition of the TLAA by indicating that all applicable 

transients, including the thermal stratification transients, are included in LRA Table 4.3.1-2, and 

the 60-year projections of all the transients are bounded by NSSS design limits. The staff’s 

concern described in RAI 4.3.2-1 Requests 2 and 3 are resolved.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analyses for PSL thermal stratification remain valid for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.1 because the 60-year 

projected number of cycles of the transients in the design analyses and the updated analyses 

will not exceed the NSSS design limits during the period of extended operation, and thus the 

bounding CUF values for these components are all less than the design limit of 1.0.

4.3.2.2.3 UFSAR Supplement

LRA Section A.2.4.2.2.1 provides the UFSAR supplement summarizing the ASME Section III, 

Class 1, fatigue TLAAs for PSL thermal stratification, which address the additional transients 

from thermal stratification identified in NRC Bulletin 88-11. The staff reviewed LRA 

Subsection A.2.4.2.2.1, consistent with SRP-LR Section 4.3.3.3, which states that the summary 

description should contain information associated with the TLAA for PSL thermal stratification 

regarding the basis for determining that the applicant has made the demonstration required by 

10 CFR 54.21(c)(1).

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.3. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address PSL thermal stratification, as required 

by 10 CFR 54.21(d).

4.3.2.2.4 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 fatigue analyses for the PSL thermal 

stratification (identified in NRC Bulletin 88-11) 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).
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25

4.3.3 Reactor Vessel Internals Aging Management

4.3.3.1 Summary of Technical Information in the Application

LRA Section 4.3.3 describes the applicant’s TLAAs for its RVIs. The applicant stated that, in 

order to assure continued functionality of the RVIs during the desired operating period, including 

license renewal, it is essential to demonstrate that the effects of aging are adequately managed. 

In addition to metal fatigue, LRA Section 4.3.3 identifies several other aging mechanisms for the 

RVIs, including stress corrosion cracking (SCC); irradiation-assisted SCC; wear; thermal aging 

embrittlement; irradiation embrittlement; void swelling and irradiation growth; and, thermal and 

irradiation-enhanced stress relaxation or irradiation-enhanced creep. LRA Section 4.3.3 states 

that the EPRI Materials Reliability Program (MRP) Reactor Internals Inspection and Evaluation 

(I&E) Guidelines, MRP-227, are intended to support a demonstration that the effects of aging on 

the RVI are adequately managed during the plant operating period, including license renewal. 

This LRA section further states that the PWR Vessel Internals Program will manage the aging 

effects for the RVI components. 

LRA Section 4.3.3 dispositions the TLAAs for the RVIs 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 by the PWR Vessel Internals Program.

4.3.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.3 and the TLAAs for the RVIs to verify, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue damage; stress corrosion cracking 

(SCC); irradiation-assisted SCC; wear; thermal aging embrittlement; irradiation embrittlement; 

void swelling and irradiation growth; and, thermal and irradiation-enhanced stress relaxation or 

irradiation-enhanced creep on the intended functions will be adequately managed for the period 

of extended operation.

The staff reviewed the applicant’s TLAAs and the corresponding disposition, consistent with 

SRP-LR Section 4.3.3.1.1.3, which state that the reviewer should verify the appropriateness of 

the applicant’s program for monitoring and tracking the number of critical thermal and pressure 

transients for the selected RCS components. The SRP-LR further states that the reviewer 

should verify that the applicant has identified the appropriate program as described and 

evaluated in the GALL Report. Furthermore, the reviewer should also ensure that the 

applicant’s program contains the same program elements that the staff evaluated and relied 

upon in approving the corresponding generic program in the GALL Report.

LRA Section 4.3.3 states that the applicant’s RVIs were designed and constructed prior to the 

development of ASME Code requirements for core support structures, but the RCS functional 

design requirements were considered in the design. Furthermore, the RVIs were analyzed for 

fatigue as part of a power uprate, and it was determined that the 40-year CUFs would remain 

less than 1.0. However, the staff noted that the LRA and the UFSAR do not provide a list of 

CUF values for the RVI components. Without this information, the staff was unable to evaluate 

the applicant’s disposition for these TLAAs. The staff noted during the aging management 

program (AMP) audit that the CUF for some RVIs, such as the upper and lower core plates or 

baffle-former bolts, could be greater than 0.5 and would require evaluation for the period of 

extended operation.
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26

The staff also noted that LRA Section 4.3.3 states that the PWR Vessel Internals Program will 

manage changes in dimensions, cracking, loss of fracture toughness, wear, and loss of preload 

of the RVI components for the period of extended operation. The staff's evaluation of the 

applicant's PWR Vessel internals Program is documented in SER Section 3.0.3.3.5. 

The staff noted that SRP-LR Section 4.3.2.1.1.3 provides the staff's recommendations for 

accepting CUF calculations in accordance with 10 CFR 54.21(c)(1)(iii). The staff noted that this 

SRP-LR section recommends that a program analogous or equivalent to GALL Report AMP

X.M1, “Metal Fatigue of Reactor Coolant Pressure Boundary,” be credited as the AMP for 

accepting CUF-based TLAAs in accordance with 10 CFR 54.21(c)(1)(iii) and for managing 

cumulative fatigue damage on the component intended functions during the period of extended 

operation.

The staff noted that the applicant's proposed aging management methodology did not conform 

to the recommendations in SRP-LR Section 4.3.2.1.1.3 because the applicant credited its PWR 

Vessel Internals Program to manage cumulative fatigue damage of the RVI and their associated

TLAAs. The staff noted that the applicant did not provide an acceptable basis for using the 

PWR Vessel Internals Program to disposition the RVI metal fatigue TLAAs in accordance with 

10 CFR 54.21(c)(1)(iii) because the applicant did not provide sufficient information to support 

that the PWR Internals Program will adequately manage the effects of metal fatigue for the RVI 

components that have a CUF analysis.

By letter dated January 5, 2011, the staff issued RAI 4.3.3-1, asking the applicant to justify its 

basis for concluding that the proposed AMP would adequately manage cumulative fatigue 

damage for the RVI components during the period of extended operation. The staff also asked 

the applicant to provide, if appropriate, updated CUFs for the period of extended operation for 

the reactor internals and to justify the proposed TLAA dispositions in accordance with 

10 CFR 54.21(c)(1)(i) or 10 CFR 54.21(c)(1)(ii).

In its response to RAI 4.3.3-1 dated February 3, 2011, the applicant stated that the intent is to 

disposition metal fatigue of the vessel internals using 10 CFR 54.21(c)(1)(i). The applicant also 

stated that in accordance with the ASME Code at the time of construction, CUF values were not 

calculated for the RVI components as part of the original design basis. The staff confirmed that 

CUF calculations for the RVI components were not required by the ASME Code and a TLAA 

disposition is not necessary. The applicant stated that plant-specific fatigue analyses for the 

limiting vessel internals locations were performed to support the stretch power uprate

application for the facility, which was approved in an NRC safety evaluation dated 

February 28, 2005. The applicant stated that the power uprate basis identified the following 

plant limiting fatigue locations for metal fatigue analysis: lower support columns, core barrel 

nozzle, lower core plate, and upper core plate. 

The applicant provided fatigue 40-year CUFs for these locations in its response to RAI 4.3.3-1, 

and the staff confirmed the CUF values for the limiting RVI component locations were all less 

than 1.0. The applicant further stated that the effects of fatigue on these specific locations 

would be monitored by cycle counting under its Metal Fatigue of Reactor Coolant Pressure 

Boundary Program during the period of extended operation to verify that the number of design 

cycles assumed in the analyses will not be exceeded. However, the applicant also stated that 

the “intent of the fatigue management program is to disposition fatigue of the vessel internals 

using 10 CFR 54.21 (c)(1)(i); that is, applying results of supplemental fatigue analyses to 

demonstrate continued acceptance of the components.” The staff noted that the acceptance 

criteria in SRP-LR Section 4.3.2.1.1.1 states that the metal fatigue CUF TLAAs may be 
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27

accepted in accordance with 10 CFR 54.21(c)(1)(i) if it can be demonstrated that the “existing 

CUF calculations remain valid because the number of assumed transients would not be 

exceeded during the period of extended operation.” A CUF TLAA may not be dispositioned in 

accordance with 10 CFR 54.21(c)(1)(i) by crediting an AMP to manage the effects of cumulative 

fatigue damage on the component's intended functions during the period of extended operation. 

Therefore, the staff found the applicant's response to RAI 4.3.3-1 unacceptable because, the 

applicant did not demonstrate the number of transient cycles analyzed for in the existing CUF 

analyses would bound the number of corresponding transient cycles that would be projected to 

occur at the facility through 60 years of licensed operations.

By letter dated March 30, 2011, the staff issued RAI 4.3.3-1b, asking the applicant to revise LRA 

Section 4.3.3—and applicable sections in LRA Appendix A—to indicate that, for the specific RVI 

components, the TLAA disposition complies with 10 CFR 54.21(c)(1)(i) and 

10 CFR 54.21(c)(1)(iii), using its Metal Fatigue of Reactor Coolant Pressure Boundary Program. 

In its response dated April 22, 2011, the applicant revised LRA Section 4.3.3 such that it is 

consistent with its response dated February 3, 2011. The applicant amended its discussion of 

metal fatigue in LRA Section 4.3.3, indicating that the effects of fatigue on these specific 

locations of the RVI will be monitored by cycle counting under its Fatigue Monitoring Program. 

However, the staff noted that there is no AMP called “Fatigue Monitoring Program” in the LRA. 

The applicant also revised the TLAA disposition basis to 10 CFR 54(c)(1)(i), that the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program will monitor the number of design 

cycles assumed in the fatigue analysis to assure that these will not be exceeded. The staff 

noted that the appropriate TLAA disposition basis for using an AMP should be 

10 CFR 54(c)(1)(iii). Furthermore, the staff noted that LRA Section A.2.4.2.2.2 was not updated 

to reflect the changes in LRA Section 4.3.3 due to the letter dated April 22, 2011.

By letter dated May 23, 2011, the staff issued RAI 4.3.3-1c, asking the applicant to revise LRA 

Section 4.3.3—and the applicable section in LRA Appendix A—to indicate that, for the specific 

locations of the RVI, the TLAA disposition is in accordance with 10 CFR 54.21(c)(1)(iii), using its 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. 

In its response dated June 2, 2011, the applicant revised LRA Section 4.3.3, the TLAA 

disposition basis, for the specific locations of the RVI, to 10 CFR 54(c)(1)(iii) to state that the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program will monitor the number of 

design cycles assumed in the fatigue analysis to assure that these will not be exceeded. The 

applicant also updated LRA Section A.2.4.2.2.2 to reflect the TLAA disposition basis. The staff 

confirmed that the applicant’s Metal Fatigue of Reactor Coolant Pressure Boundary Program

tracks the number of transient cycles that occur and this program also requires the applicant to 

take corrective actions prior to any analyzed number of cycles being reached in the applicable 

TLAA, which ensures that the analyses remain valid and the design limit of 1.0 is not exceeded. 

The staff’s evaluations of the applicant’s Metal Fatigue of Reactor Coolant Pressure Boundary 

Program is documented in SER Section 3.0.3.2.21.

Based on its review, the staff found the applicant's response acceptable because the applicant 

provided an accurate TLAA disposition basis and consistent UFSAR supplement for the specific 

locations of the RVI by updating LRA Section 4.3.3 and Section A.2.4.2.2.2. The staff’s concern 

described in RAI 4.3.3-1c is resolved.

The staff also noted that LRA Table 3.1.2-3 indicates that a TLAA is credited for the flux thimble 

tubes and flux thimble guide tubes to manage cumulative fatigue damage. However, LRA 

Section 4.3.3 does not provide CUF values for the flux thimble tubes and flux thimble guide 
Time-Limited Aging Analyses

28

tubes to support this TLAA disposition. By letter dated January 5, 2011, the staff issued 

RAI 4.3.3-2, asking the applicant to provide the CUF values for the flux thimble tubes and flux 

thimble guide tubes and to ensure that cumulative fatigue damage of these components will be 

adequately managed by the PWR Vessel Internal Program, in accordance with 

10 CFR 54.21(c)(1)(iii).

In its response dated February 3, 2011, the applicant stated that the flux thimble tubes are not 

within the scope of license renewal, and LRA Table 3.1.2-3 has been revised in response to 

RAI 3.1.1.60-2. The applicant stated that LRA Table 3.1.2-3 incorrectly listed cumulative fatigue 

damage as an aging effect requiring management for the flux thimble tubes and the line item will 

be deleted. The staff’s evaluation of the applicant’s response to RAI 3.1.1.60-2 is documented 

in SER Section 3.1.2.1.1. The applicant also stated that the flux thimble guide tubes are internal 

to the RPV for structural support of the flux thimble tubes and they do not have a fatigue 

analysis. Thus, a metal fatigue TLAA disposition is not necessary. The applicant also stated 

that the RPV bottom head instrument tubes are ASME Class 1 components, associated with the 

RPV, with a CUF value of 0.3184. The applicant explained that, as discussed in LRA 

Section 4.3.1, since the 40-year design transient cycle numbers bound the numbers of projected 

cycles during 60-years operation, the NSSS Class 1 fatigue analyses remain valid for the period 

of extended operation in accordance with 10 CFR 54.21(c)(1)(i). The staff also confirmed the 

Section III Subsection NC of the ASME Code, which consists of the stress requirements to 

which the flux thimble guide tubes were designed, does not require a fatigue evaluation.

Based on its review, the staff finds the applicant’s response to RAI 4.3.3-2 acceptable because 

the flux thimble guide tubes are not required by the ASME Code to have a fatigue analysis 

Additionally, the applicant demonstrated that the metal fatigue TLAA disposition for the bottom 

head instrument tubes is in accordance with 10 CFR 54.21(c)(1)(i). The staff’s concern 

described in RAI 4.3.3-2 is resolved.

LRA Table 4.1-2 states that the analysis associated with flow-induced vibration (FIV) endurance 

limit is applicable, and the TLAA is addressed in LRA Section 4.3.3. UFSAR Section 3.9(N).2.4 

discusses the effects of FIV on the integrity of the RVI components. However, LRA 

Section 4.3.3 does not describe how the effects of FIV are being managed in the RVI 

components. It was not clear to the staff if cracking and loss of material induced by FIV are 

aging effects requiring management for the RVI components in LRA Table 3.1.2-3 and if the 

analysis is a TLAA, as defined in 10 CFR 54.3.

By letter dated January 5, 2011, the staff issued RAI 4.1-1, asking the applicant to clarify 

whether cracking induced by FIV or loss of material (i.e., wear or fretting) induced by FIV is an 

aging effect requiring management for the RVI components that are subject to aging 

management review (AMR). The staff also asked the applicant to clarify if its CLB includes any 

analysis that evaluated the impact of FIV on the structural integrity of the RVI components as a 

result of these aging mechanisms, and to explain if the analysis is a TLAA, as defined in 

10 CFR 54.3. Furthermore, the staff asked the applicant to clarify if LRA Section 4.3.3 needs to 

be amended to include the analysis, in accordance with 10 CFR 54.21(c)(1).

In its response dated February 3, 2011, the applicant stated that its FIV analysis of the RVI was 

not performed as part of the CLB. The applicant stated that Westinghouse has studied FIV of 

PWR internals using in-plant and scale-model tests, as well as tests in fabricator’s shops and 

bench tests of components to show the structural integrity and reliability of reactor internals 

components. The applicant stated that these results, and further analyses performed for its 

reactor internals, indicate that the effect of FIV on fatigue is extremely small and the stress level 
Time-Limited Aging Analyses

29

is well within the allowable stress based on the high cycle endurance limit for the materials. 

Therefore, the applicant concluded that there is no need to monitor the age-related effects of 

FIV on the fatigue of RVIs. The applicant did not amend LRA Table 4.1-3 to indicate that FIV 

analysis is not a TLAA. The staff noted that LRA Section 4.3.3 does not include any discussion 

on how the FIV analysis factors into the CUF calculations for the RVI core support structure 

components. The staff also noted that, in the response to RAI 4.1-1, the applicant indicated that 

there are “further analyses performed for the Seabrook Station reactor internals” for FIV of the 

RVI components. However, the applicant’s response did not provide any comparison of these 

FIV analyses to the six criteria for TLAAs in 10 CFR 54.3. Therefore, the staff could not 

determine whether these additional analyses need to be identified as a TLAA for the LRA. This 

issue was combined with an issue on ductility reduction of fracture toughness, for which the staff 

issued followup RAI 4.1-1b. Discussion of this RAI is provided later in this section.

LRA Table 4.1-2 states that the analysis associated with ductility reduction of fracture toughness 

for the RVI components is applicable, and the TLAA is addressed in LRA Section 4.3.3. 

However, LRA Section 4.3.3 does not include a discussion related to this specific issue. The 

staff also noted that LRA Table 3.1.2-3 identifies loss of fracture toughness as an aging effect 

requiring management for the RVI components that are subject to an AMR. The staff noted that 

the service conditions that may degrade material properties of RVI components include neutron 

irradiation, temperature, and reactor coolant environment. It was not clear to the staff if the CLB 

includes any neutron fluence-dependent reduction of fracture toughness analysis for the RVI 

components or if the analysis is a TLAA, as defined in 10 CFR 54.3.

By letter dated January 5, 2011, the staff issued RAI 4.1-2, asking the applicant to clarify 

whether its CLB includes any neutron fluence-dependent reduction of fracture toughness 

analysis for the RVI components that are subject to an AMR in LRA Table 3.1.2-3. The staff 

also asked the applicant to explain if the analysis is a TLAA, as defined in 10 CFR 54.3, and if 

the LRA needs to be amended to include this analysis, in accordance with 10 CFR 54.21(c)(1).

In its response dated February 3, 2011, the applicant stated that the fluence-dependent 

reduction of fracture toughness of vessel internals is not analyzed as part of the CLB because 

this has been analyzed generically for all Westinghouse-designed plants. The applicant also 

stated that loss of fracture toughness due to irradiation is an aging management effect that will 

be managed by inspection and evaluation per its PWR Vessel Internals Program.

The staff noted the applicant’s conclusion, that the analysis of ductility reduction of fracture 

toughness for the RVI is not a TLAA, is based on the determination that the analysis is not 

contained or incorporated by reference in the CLB. The staff noted that the applicant addressed 

the potential for a reduction in fracture toughness properties for the RVI components in its PWR 

Vessel Internals Program. The staff’s evaluation of the PWR Vessel Internals Program is 

documented in SER Section 3.0.3.1.5. However, the applicant did not amend LRA Table 4.1-2

to indicate that ductility reduction of fracture toughness for the RVI is not part of its CLB, and 

LRA Section 4.3.3 does not include any discussion regarding how the ductility reduction of 

fracture toughness factor into the CUF calculations for the RVI core support structure 

components. The staff noted that the issues related to ductility reduction of fracture toughness 

are similar to those identified in the applicant’s response to RAI 4.1-1 related to FIV. As a 

result, the staff combined the issues of FIV and ductility reduction of fracture toughness into 

followup RAI 4.1-1b.

By letter dated March 30, 2011, the staff issued RAI 4.1-1b, asking the applicant to amend LRA 

Table 4.1-2 to show that the issues of FIV and ductility reduction of fracture toughness are not 
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TLAAs and to provide the justification for making these changes to LRA Table 4.1-2. Otherwise, 

the staff asked that the applicant amend LRA Section 4.3.3 to clarify how the CUF calculations 

account for FIV in the RVI core support structures and the reduction in ductility or fracture 

toughness properties for the core support structures materials. The staff also asked the 

applicant to justify why the “further analyses” described in the LRA for FIV of the RVI 

components do not conform to the definition of a TLAA in 10 CFR 54.3.

In its response to RAI 4.1-1b dated April 22, 2011, the applicant revised LRA Table 4.1-2 to 

show that FIV and ductility reduction and loss of fracture toughness are not TLAAs. The 

applicant also stated that the analyses for FIV (including the "further analyses") and the 

reduction in ductility and fracture toughness are not incorporated in its CLB and do not involve a 

time-limited aging effect for the licensed operating period. Thus, the analyses do not meet all 

six criteria of a TLAA, defined in 10 CFR 54.3.

Based on its review, the staff finds the applicant’s response to RAI 4.1-1b acceptable because 

the applicant revised LRA Table 4.1-2 to show that the fatigue analyses for FIV in the RVI core 

support structures and the reduction in ductility or fracture toughness properties for the core 

support structures materials are not TLAAs. Additionally, the applicant explained that those 

fatigue analyses are not TLAAs, as defined in 10 CFR 54.3. The staff’s concern in RAI 4.1-1b is 

resolved.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue damage on the intended functions 

of the specific locations of the RVI will be adequately managed for the period of extended 

operation because the staff has confirmed that the applicant will use its Metal Fatigue of 

Reactor Coolant Pressure Boundary Program to manage this aging effect during the period of

extended operation, consistent with the recommendations of SRP-LR Section 4.3.2.1.1.3, by 

tracking the number of transient cycles that occur. This program also requires that the applicant 

take corrective actions prior to any analyzed number of cycles being reached in the applicable 

TLAA, which ensures that the analyses remain valid and the design limit of 1.0 is not exceeded.

In addition, based on its review, the staff also finds that the applicant has provided an 

acceptable basis for concluding that the LRA does not need to include any FIV, reduction of 

ductility or reduction in fracture toughness TLAAs for the RVI components because the staff has 

confirmed these type of analyses are not incorporated in or referenced by the CLB for the 

facility.

4.3.3.3 UFSAR Supplement

LRA Section A.2.4.2.2.2, as amended by letter dated June 2, 2011, provides the UFSAR 

supplement summarizing the metal fatigue TLAA of RVIs. The staff reviewed LRA 

Section A.2.4.2.2.2 consistent with SRP-LR Section 4.3.3.3, which states that the summary 

description should contain information associated with the metal fatigue TLAA of RVIs regarding 

the basis for determining that the applicant has made the demonstration required by 

10 CFR 54.21(c)(1).

Based on its review of the UFSAR supplement, as amended by letter dated June 2, 2011, the 

staff finds it meets the acceptance criteria in SRP-LR Section 4.3.2.3. Additionally, the staff 

determined that the applicant provided an adequate summary description of its actions to 

address fatigue TLAA of RVIs, 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, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue 

damage on the intended functions of the RVIs 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).

4.3.4 Environmentally-Assisted Fatigue Analysis

4.3.4.1 Summary of Technical Information in the Application

LRA Section 4.3.4 describes the applicant’s evaluation of the effects of reactor coolant 

environment on fatigue usage for the period of extended operation. The applicant stated that, 

although environmentally-assisted fatigue (EAF) analyses do not meet the definition of TLAA 

under 10 CFR 54.3 because they are not contained or incorporated by reference in its CLB, the 

discussion of EAF calculations is provided in response to the recommendation in SRP-LR, 

Revision 1, Section 4.3.2.2, “Generic Safety Issue,” that applicants address the effects of the 

coolant environment on component fatigue life as aging management programs are formulated

in support of license renewal. The applicant also stated that GALL AMP X.M1 provides an 

acceptable program that addresses the effects of the reactor coolant environment on 

component fatigue life by assessing the impact of the reactor coolant environment on a sample 

of critical components for the plant. The applicant stated that NUREG/CR-6260 provides 

environmental fatigue calculations for a newer vintage Westinghouse plant, like Seabrook, for 

the locations of highest design CUF.

The 60-year CUFs obtained from the ASME air curve, and the EAF adjusted values for seven 

locations in the six NUREG/CR-6260 components, are summarized in LRA Table 4.3.4-1. The

applicant stated that, for all locations, the ASME air-curve CUFs are less than 1.0 for the 

60-year service. However, the 60-year EAF-adjusted CUFs exceed 1.0 for the hot leg surge 

line nozzle (HLSN) located on the pressurizer surge line (PSL) and the RCS charging nozzle. 

The applicant further stated that another acceptable option to disposition EAF is to manage 

fatigue of these components using the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program by tracking the number and severity of plant transients and comparing with the design 

basis transients. Under this option, when the counted number of a specific plant transient 

reaches the plant design basis number associated with that transient, a preemptive remedial 

action described in the program will be undertaken by the applicant.

LRA Section 4.3.4 states that, based on NUREG/CR-6260, plant-specific components were 

identified, and the design ASME fatigue usage factors were adjusted by the environmental life 

correction factors (Fen) to obtain the environmentally-corrected CUF (CUFen) for the RPV inlet 

and outlet nozzles, RPV shell and lower head, and residual heat removal (RHR) hot leg nozzle. 

The results for 60-year operation are summarized in LRA Table 4.3.4-1. LRA Section 4.3.4 also 

states that—for the RPV shell and lower head, RPV inlet and outlet nozzles, and RHR hot leg 

nozzle—the CUFs were determined using the number and severity of the design cycles of 

record, which bound the projected 60-year cycles and for these components. Furthermore, the 

environmental fatigue effects were determined using the maximum Fen, which incorporates the 

lowest strain rate, a temperature greater than 200° C, and dissolved oxygen level less than 50 

parts per billion (ppb).
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32

The applicant further stated that, for the remainder of the NUREG/CR-6260 locations (i.e., 

pressurizer surge line (PSL) nozzle, charging nozzle, and safety injection nozzle), the CUFs 

were determined using the projected 60-year cycles, and environmental effects were 

incorporated using an effective Fen. Based on the material at each location, Fen factors were 

determined for each transient pair using a temperature greater than 200° C, a dissolved oxygen 

level less than 50 ppb, and a strain rate that was calculated by the integrated strain rate 

method. The effective Fen factor for each location was then determined by the ratio of 

CUFen/CUF. LRA Section 4.3.4 states that the fatigue analyses indicate that the 60-year CUF in 

air for all locations is less than the ASME design limit of 1.0, but the 60-year CUF adjusted for 

environmental effects is greater than 1.0 for the HLSN located on the PSL and the RCS 

charging nozzle.

The applicant dispositioned the EAF analyses for the RPV shell and lower head, and the RPV 

inlet and outlet nozzles, 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. The applicant also dispositioned the 

EAF analysis for the RCS PSL nozzle, RCS charging nozzle, RCS safety injection nozzle, and 

RCS RHR system Class 1 piping, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of 

reactor coolant environment on fatigue usage factors will be adequately managed for the period 

of extended operation using the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

4.3.4.2 Staff Evaluation

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 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 the effects of the reactor coolant environment on 

component fatigue life do not fall within the definition of a TLAA in 10 CFR 54.3 because these 

evaluations are not in the applicant’s CLB. Consistent with Commission Order No. CLI-10-17, 

the staff finds the applicant’s evaluation of the effects of the reactor coolant environment on 

component fatigue life is an acceptable practice consistent with the staff’s recommendations in 

the SRP-LR and the closure of GSI-190.

The staff reviewed LRA Section 4.3.4 and the EAF analyses for the RPV shell and lower head 

and the RPV inlet and outlet nozzles 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. The staff 

reviewed LRA Section 4.3.4 and the EAF analyses for RCS PSL nozzle, RCS charging nozzle, 

RCS safety injection nozzle, and RCS RHR system Class 1 piping to verify, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of reactor coolant environment on component fatigue life 

will be adequately managed for the period of extended operation using the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program.

The staff reviewed the applicant’s evaluations and the corresponding disposition consistent with 

SRP-LR Section 4.3.3.2, which state that the reviewer should verify that the applicant has 

addressed the effects of the coolant environment on component fatigue life as AMPs that are 

formulated in support of license renewal. The SRP-LR also states that if the applicant has 

chosen to assess the impact of the reactor coolant environment on a sample of critical 

components, the reviewer should verify the following:

• The critical components include, as a minimum, those selected in NUREG/CR-6260.
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33

• The sample of critical components has been evaluated by applying environmental 

correction factors to the existing ASME Code fatigue analyses.

• The formulae for calculating the Fen are those contained in NUREG/CR–6583, for carbon 

and low-alloy steels, and in NUREG/CR-5704, for austenitic SSs, or an approved 

technical equivalent.

During its review the staff identified that the applicant did not provide sufficient details on how 

the CUFs in air and the associated values of Fen were determined for the NUREG/CR-6260 

locations listed in Table 4.3.4-1. It was not clear if all design transients were lumped together 

into the worst-case transient or if other transients were also considered in the fatigue analyses. 

The staff noted that LRA Section 4.3.4 states that the RHR system Class 1 piping analysis was 

based on its specific conditions, whereas footnote 4 of Table 4.3.4-1 states that this analysis 

was performed using design number and design-severity cycles. Therefore, it was not clear to 

the staff if the CUF analysis for the RHR system Class 1 piping was performed using 

plant-specific 60-year projected cycles or the design number and severity cycles.

By letter dated January 5, 2011, the staff issued RAI 4.3.4-2, asking the applicant to clarify if the 

60-year ASME air-curve CUFs were calculated using ASME Code Section III NB-3200 or 

NB-3600 for each location listed in LRA Table 4.3.4-1. The staff also asked the applicant to 

describe how the transient definitions are selected and to justify the use of the integrated 

strain-rate method in the fatigue calculation and how it provides conservative results. 

Furthermore, the staff requested that the applicant clarify what the Seabrook-specific conditions 

are, as discussed in LRA Section 4.3.4, and to clarify if the CUF analysis for the RHR system 

Class 1 piping was performed using plant-specific conditions or using the design number and 

severity cycles, as noted in footnote 4 of LRA Table 4.3.4-1.

In its response dated February 3, 2011, the applicant stated that the 60-year ASME air-curve 

CUF values for all the components listed in LRA Table 4.3.4-1 were calculated using ASME 

Code Section III Subsection NB-3200. The applicant further stated that, in the integrated 

strain-rate method, Fen is computed at multiple points over the increasing (tensile) portion of a 

paired strain range. Additionally, an overall Fen is integrated over the entire tensile portion (i.e., 

from the algebraically lowest stress point of the maximum compressive stress event to the 

algebraically highest stress point of the maximum tensile stress event). The staff noted that the 

integrated strain-rate approach is rigorous because the strain-rate was computed for multiple 

points along the tensile portion of the paired strain range resulting in a more refined Fen value. 

The applicant also clarified that Seabrook-specific conditions are the 60-year projected number 

of cycles and design-severity cycles. The applicant stated that the RHR system Class 1 piping 

evaluation was not performed using plant-specific conditions but using the design number and 

severity of cycles, as noted in footnote 4 of LRA Table 4.3.4-1.

Based on its review, the staff finds the response to RAI 4.3.4-2 acceptable for the following 

reasons:

• The applicant clarified that the CUF analysis for the RHR system Class 1 piping was 

performed using the design number and severity of cycles. 

• The applicant calculated Fen using a more rigorous integrated strain-rate method that 

results in a more refined Fen value.

The staff’s concern described in RAI 4.3.4-2 is resolved.
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34

LRA Section 4.3.4 discusses the methodology to determine the locations that require EAF 

analyses consistent with NUREG/CR-6260 “Application of NUREG/CR-5999 Interim Fatigue 

Curves to Selected Nuclear Power Plant Components.” The staff recognized that, in LRA 

Table 4.3.4-1, there are seven plant-specific locations listed based on the six generic 

components identified in NUREG/CR-6260. However, the GALL Report AMP X.M1 states that 

the impact of the reactor coolant environment on a sample of critical components should include 

the locations identified in NUREG/CR-6260 as a minimum, and additional locations may need 

evaluation. During its review, the staff recognized that footnote 2 of LRA Table 4.3.4-1 states 

that these locations are plant-specific limiting locations within the boundary of the applicable 

NUREG/CR-6260 component. However, CUF values for other locations were not available in 

the LRA, and the applicant did not explain that these are the limiting locations for the plant. The 

staff noted that the applicant’s plant-specific configuration may contain locations that should be 

analyzed for the effects of the reactor coolant environment other than those identified in 

NUREG/CR-6260. This may include locations that are limiting or bounding for a particular 

plant-specific configuration or that could have CUFen values that are greater when compared to 

the locations identified in NUREG/CR-6260.

The staff noted that LRA Section 4.3.2.2 stated that the controlling fatigue location of the PSL

piping was the HLSN safe-end. However, footnote 2 in LRA Table 4.3.4-1 indicates the hot-leg 

surge nozzle-to-pipe weld to be the plant-specific limiting location within the boundary of the 

applicable NUREG/CR-6260 component locations.

By letter dated January 5, 2011, the staff issued RAI 4.3.4-1, Request 1, asking the applicant to 

provide the 40-year design CUF value and the projected 60-year CUF values (with and without 

environmental effects) for the HLSN safe-end. The staff also asked to applicant to clarify that 

the hot-leg surge-nozzle-to-pipe weld is the limiting location for the PSL.

In its response dated February 3, 2011, the applicant clarified that the HLSN-to-pipe weld was 

evaluated to be the limiting component in the surge line because it was reported to be the 

highest CUF in the surge line in the original analysis. The applicant also provided the 40-year 

design CUF and the projected 60-year CUF values for the HLSN safe-end. The applicant stated 

that the 40-year design CUF for the HLSN safe end is 0.6. A new analysis performed in support 

of the LRA, using the design-basis numbers of design-severity cycles, yielded CUF values of 

0.52 in air and 6.63 in reactor environment. The applicant also stated that the CUF values for 

the same location, using the 60-year projected number of design-severity cycles, are 0.2844 in 

air and 3.2848 in reactor environment.

In its review, it was not clear to the staff whether the fatigue limiting CUF evaluations were 

performed for the nozzle-to-safe end weld or the safe end-to-pipe weld. In footnote 1 of Table 1 

of the applicant’s response to RAI 4.3-1, the highest fatigue usage location is listed as nozzle 

transition and safe end, whereas in Table 2 of the applicant’s response to RAI 4.3.2-1, it is listed 

as nozzle safe end-to pipe weld. Furthermore, the staff noted inconsistencies in the CUF values 

listed in various tables. In LRA Table 4.3.4-1, for the HLSN-to-pipe weld, the 60-year CUFs are

0.2844 in air and 3.428 in reactor coolant environment, and the Fen factor is 12.05. In the 

response to RAI 4.3.4-1, for the HLSN safe-end, the 60-year CUFs are 0.2844 in air and 3.2848 

in reactor coolant environment, and the Fen factor is 11.55.

By letter dated March 30, 2011, the staff issued followup RAI 4.3.4-1b, requesting that the 

applicant either resolve or justify the inconsistencies in the reported values of CUF, and clarify 

the fatigue limiting location of the HLSN.
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35

In its response dated April 22, 2011, the applicant stated that the correct CUF for the 

HLSN-to-surge line weld is 0.2844, and the 60-year EAF-adjusted CUF is 3.428. The applicant 

stated that for the HLSN, which is an all-stainless steel configuration, the fatigue limiting location 

is the HLSN-to-surge line weld. The applicant revised LRA Table 4.3.4-1 to show the limiting 

location for the HLSN and the CUF values.

Based on its review, the staff finds the applicant’s response to RAI 4.3.4-1b acceptable because 

the applicant revised the LRA clarifying that the fatigue limiting location of the HLSN and 

resolved the inconsistency in the 60-year EAF-adjusted CUF value for the HLSN-to-surge line 

weld. The staff’s concern in RAI 4.3.4-1b is resolved.

By letter dated January 5, 2011, the staff issued RAI 4.3.4-1, Requests 2 and 3, asking the 

applicant to clarify that the plant-specific locations listed in LRA Table 4.3.4-1 are bounding for 

the generic NUREG/CR-6260 components. The staff also asked the applicant to confirm and 

justify that the locations selected for EAF analyses in LRA Table 4.3.4-1 consist of the most 

limiting locations for the plant (beyond the generic components identified in the 

NUREG/CR-6260 guidance). If these locations are not bounding, the applicant was requested

to clarify the locations that require an EAF analysis and the actions that will be taken for these 

additional locations. Furthermore, if the identified limiting location consists of nickel alloy, the 

applicant must state if the methodology used to perform the EAF calculation for nickel alloy is 

consistent with NUREG/CR-6909 or justify the method chosen.

In its response dated February 3, 2011, the applicant stated that, at least 2 years prior to 

entering the period of extended operation, it will perform a review of design basis ASME Class 1 

component fatigue evaluations. This review will determine if the NUREG/CR-6260-based 

components that have been evaluated for the effects of the reactor coolant environment on 

fatigue usage are the limiting components for the Seabrook plant configuration. If more limiting 

components are identified, the most limiting component will be evaluated for the effects of the 

reactor coolant environment on fatigue usage. If the limiting location identified consists of nickel 

alloy, the EAF calculation for nickel alloy will be performed using the rules of NUREG/CR-6909.

The applicant further modified Commitment No. 44 of LRA Appendix A, Commitment List A.3, 

with the following:

NextEra Seabrook will perform a review of design basis ASME Class 1 

component fatigue evaluations to determine whether the NUREG/CR 6260 

based components that have been evaluated for the effects of the reactor coolant 

environment on fatigue usage are the limiting components for the Seabrook plant 

configuration. If more limiting components are identified, the most limiting 

component will be evaluated for the effects of the reactor coolant environment on 

fatigue usage. If the limiting location identified consists of nickel alloy, the EAF 

calculation for nickel alloy will be performed using the rules of NUREG/CR 6909.

Based on its review, the staff finds the applicant response to RAI 4.3.4-1, Requests 2 and 3, 

and modified Commitment No. 44, acceptable for the following reasons:

• The applicant will review its design basis ASME Code Class 1 fatigue evaluations to 

determine if the NUREG/CR-6260 based locations that have been evaluated for the 

effects of the reactor coolant environment on fatigue usage are the limiting locations for 

its plant configuration. 
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36

• If more limiting locations are identified, the applicant will perform EAF analyses for the 

most limiting location. 

• Methodology consistent with NUREG/CR-6909 will conservatively be used in the 

evaluation if the limiting component identified consists of nickel alloy. 

• Commitment No. 44 is consistent with the recommendations in SRP-LR Sections 4.3.2.2 

and 4.3.3.2, and the GALL AMP X.M1, to consider environmental effects for the 

NUREG/CR-6260 locations, at a minimum. 

The staff’s concern in RAI 4.3.4-1, Requests 2 and 3, is resolved.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the analyses for the RPV shell and lower head and the RPV inlet 

and outlet nozzles have been projected to the end of the period of extended operation. This 

disposition is acceptable because the applicant has demonstrated that the CUFen, when using 

the maximum Fen factor, is projected to remain below the design limit of 1.0 for the period of 

extended operation.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the fatigue-related effects of reactor coolant environment on the 

intended functions of the RCS PSL nozzle, RCS charging nozzle, RCS safety injection nozzle, 

and RCS RHR system Class 1 piping, will be adequately managed for the period of extended 

operation. This disposition is acceptable because the applicant will continue to manage the 

effects of reactor coolant environment for these components with its Metal Fatigue of Reactor 

Coolant Pressure Boundary Program to ensure that the CUFen values will not exceed the design 

limit of 1.0, or it will take corrective actions to reanalyze, repair, or replace the affected 

components.

4.3.4.3 UFSAR Supplement

LRA Section A.2.4.2.3 provides the UFSAR supplement summarizing the evaluation of the 

effects of reactor coolant environment on fatigue life of piping and components. The staff 

reviewed LRA Section A.2.4.2.3 consistent with SRP-LR Section 4.3.3.3, which states that the 

reviewer should verify that the applicant provided information, to be included in the UFSAR 

supplement, which includes a summary description of the evaluation of the effects of reactor 

coolant environment on fatigue. The SRP-LR also states that the reviewer should verify that the 

applicant has identified and committed in the LRA to any future aging management activities, 

including enhancements and commitments to be completed before the period of extended 

operation.

The staff also noted that the applicant committed (Commitment No. 44) to the following, as 

modified in its letter dated February 3, 2011:

• NextEra Seabrook will perform a review of design basis ASME Class 1 component 

fatigue evaluations to determine whether the NUREG/CR-6260-based components that 

have been evaluated for the effects of the reactor coolant environment on fatigue usage 

are the limiting components for the Seabrook plant configuration. If more limiting 

components are identified, the most limiting component will be evaluated for the effects 

of the reactor coolant environment on fatigue usage. If the limiting location identified 

consists of nickel alloy, the EAF calculation for nickel alloy will be performed using the 

rules of NUREG/CR-6909.
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37

• Consistent with the Metal Fatigue of Reactor Coolant Pressure Boundary Program, 

Seabrook will update the fatigue usage calculations using refined fatigue analyses, if 

necessary, to determine acceptable CUFs (i.e., less than 1.0) when accounting for the 

effects of the reactor water environment. This includes applying the appropriate Fen

factors to valid CUFs determined from an existing fatigue analysis valid for the period of 

extended operation or from an analysis using an NRC-approved version of the ASME 

code or NRC-approved alternative (e.g., NRC-approved code case).

• If acceptable CUFs cannot be demonstrated for all the selected locations, then additional 

plant-specific locations will be evaluated. For the additional plant-specific locations, if 

CUF, including environmental effects, is greater than 1.0 then corrective actions will be 

initiated, in accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program. Corrective actions will include inspection, repair, or replacement of the 

affected locations before exceeding a CUF of 1.0 or the effects of fatigue will be 

managed by an inspection program that has been reviewed and approved by the NRC 

(e.g., periodic non-destructive examination of the affected locations at inspection 

intervals to be determined by a method accepted by the NRC). 

Based on its review of the UFSAR supplement, as amended by letter dated February 3, 2011, 

the staff finds it meets the acceptance criteria in SRP-LR Section 4.3.2.3. Additionally, the staff 

determined that the applicant provided an adequate summary description of its actions to 

address the effects of reactor coolant environment on fatigue usage, 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’s evaluations on the effects of 

the reactor coolant environment on component fatigue life is not a TLAA as defined by 

10 CFR 54.3 and is consistent with Commission Order No. CLI-10-17 (July 8, 2010). The staff 

also concludes that the applicant provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1)(ii), that the effects of reactor coolant environment on fatigue usage of the 

RPV shell and lower head and RPV inlet and outlet nozzles has been projected to the end of the 

period of extended operation. The staff also concludes that the applicant has demonstrated, 

pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of reactor coolant environment on fatigue 

usage of the RCS PSL nozzle, RCS charging nozzle, RCS safety injection nozzle, and RCS 

RHR system Class 1 piping, 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 evaluation, as required by 10 CFR 54.21(d).

4.3.5 Steam Generator Tube, Loss of Material and Fatigue Usage from Flow-Induced 

Vibration

4.3.5.1 Summary of Technical Information in the Application

LRA Section 4.3.5 describes the applicant’s TLAA for steam generator tube loss of material due 

to wear and fatigue in the U-bend region resulting from FIV. The applicant stated that the TLAA 

for loss of material and fatigue of steam generator tubing addressed the impact of the power 

increase on the FIV as a result of its power uprates. The applicant stated that its pre-uprate 

analysis of the effects of FIV on tube wear and fatigue usage assumed 40 years of operation. 

The applicant also stated that its post-uprate analysis, when projected for 60 years of operation, 

showed that the increased wear loss did not exceed the acceptance limit of the original analysis. 

The applicant also stated that the fatigue usage computed for extended operation was zero 
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38

because the steam generator tube bending stress, due to FIV, is below the fatigue endurance 

limit. The applicant also stated that a prerequisite for high cycle U-bend fatigue is a dented 

support condition at the upper tube support plate, and thus there is no concern for high cycle 

fatigue at Seabrook since the steam generators have stainless steel tube support plates.

The applicant dispositioned the TLAA related to steam generator tubes in accordance with 

10 CFR 54.21(c)(1)(i), that the analyses of the loss of material due to wear and fatigue in the 

U-bend region of steam generator tubing remain valid for the period of extended operation.

4.3.5.2 Staff Evaluation

The staff reviewed LRA Section 4.3.5 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses of the loss of material due to wear and fatigue in the U-bend region of steam generator 

tubing remain valid for the period of extended operation.

The staff reviewed the applicant’s TLAAs and the corresponding disposition consistent with 

SRP-LR Section 4.3.3.1.1.1, which state that the staff should review the operating transient 

experience and a list of the assumed transients used in the existing cumulative usage factor 

(CUF) calculations for the current operating term to ensure that the number of assumed 

transients would not be exceeded during the period of extended operation.

The staff reviewed LRA Section 4.3.5 and determined that the applicant included, as an 

applicable aging effect, the loss of material due to the wear of the steam generator tube from 

flow-induced vibrations. The staff noted that the applicant discussed that the maximum 40-year 

wear is less than 0.0050 in. and the maximum 60-year tube wear will be 0.0075 in., and it 

concluded that the estimated maximum 60-year tube wall wear will be less than the acceptance 

criteria of 40 percent of wall thickness. The staff noted that the applicant did not provide the 

wall thickness of the tube to justify these statements.

By letter dated January 5, 2011, the staff issued RAI 4.3.5-2, asking the applicant to provide the 

tube wall thickness and to demonstrate that the estimated maximum 60-year tube wall wear is 

under the 40 percent of wall thickness acceptance limit. The staff also asked the applicant to 

explain why the TLAA analysis and disposition associated with tube wall wear should not be 

included as a stand-alone subsection under LRA Section 4.7 “Plant-Specific TLAA.”

In its response dated February 3, 2011, the applicant stated that the nominal tube wall thickness 

for its 11/16-in. diameter tubes is 0.040 in. and explained that the estimated maximum 60-year 

tube wall wear will be less than the 40 percent of wall thickness acceptance criteria. The 

applicant also stated that the TLAA analysis and disposition associated with tube wall wear 

should be included as a stand-alone subsection under LRA Section 4.7 “Plant-Specific TLAA.” 

The applicant amended its LRA to include LRA Section 4.7.15 “Steam Generator Tube Wall 

Wear From Flow-Induced Vibration.” 

Based on its review, the staff finds the applicant’s response to RAI 4.3.5-2 acceptable because 

the applicant justified that the estimated maximum 60-year tube wall wear will be less than the 

acceptance criteria of 40 percent of wall thickness. Additionally, the applicant amended its LRA 

to include LRA Section 4.7.15 to discuss steam generator tube wall wear due to FIV. The staff’s 

concern in RAI 4.3.5-2 is resolved. The staff’s evaluation of loss of material due to the wear of 

the steam generator tube from FIV is documented in SER Section 4.7.15.2.

LRA Section 4.3.5 states that the evaluation showed that significant levels of tube vibration will 

not occur from either the fluidelastic or turbulent mechanisms above those associated with the 
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39

pre-uprated condition. The staff noted that, over time, flow patterns may change, and the 

applicant’s summary did not consider flow pattern changes when making the extrapolation from 

its 40-year analysis. In addition, LRA Section 4.3.5 states “[l]ow-cycle fatigue usage for the 

most limiting tube in the most limiting power-uprated operating condition resulting from the FIV 

tube bending stress is 0.2 [kips per square inch] ksi.” The staff noted the applicant’s statement 

implies that the low-cycle fatigue usage is 0.2 ksi.

By letter dated January 5, 2011, the staff issued RAI 4.3.5-1, Request 1, asking the applicant to 

provide its technical basis to support the linear extrapolation method and to demonstrate that its

analysis envelops likely changes in wear and fatigue over the period of extended operation, as 

affected by FIV or fluid-structure interactions. The staff also asked the applicant to identify any 

past or future planned independent confirmation to ensure the validity of the analyses, and the

adequacy of the confirmation for the period of extended operation.

The applicant's response to RAI 4.3.5-1, Request 1, dated February 3, 2011, that relates to 

wear is described and evaluated in SER Section 4.7.15. The staff noted that the applicant did 

not remove the wear-related (loss of material) discussion in the amended LRA Section 4.3.5.

As a part of its response to RAI 4.3.5-1, the applicant amended LRA Section 4.3.5, to, in part, 

change the disposition of the TLAA addressed in this section to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging will be adequately managed for the period of extended operation by the Steam 

Generator Tube Integrity Program.

The staff noted that the fatigue evaluation documented in LRA Section 4.3.5 demonstrates that 

the 60-year CUF value is well below the design limit, which indicates how much margin is 

available before the design limit of 1.0 is reached. However, the staff noted that the Steam 

Generator Tube Integrity Program cannot be used to substitute an ASME Code Section III 

fatigue evaluation unless the applicant can justify and demonstrate that the AMP can address 

the fatigue-related CUF analysis. Therefore, the staff does not find the applicant’s amendment 

to 10 CFR 54.21(c)(1)(iii) acceptable for the steam generator tube fatigue due to the FIV TLAA.

By letter dated March 30, 2011, the staff issued followup RAI 4.3.5-1b, asking the applicant to 

revise LRA Section 4.3.5 and move the wear-related (loss of material) discussion to LRA 

Section 4.7.15. The staff also requested that the applicant justify the TLAA disposition of the 

steam generator tube fatigue due to FIV in accordance with 10 CFR 54.21(c)(1)(iii) or revise the 

TLAA disposition of the steam generator tube fatigue TLAA due to FIV in accordance with 

10 CFR 54.21(c)(1)(i).

In its response dated April 22, 2011, the applicant revised LRA Sections 4.3.5 and A.2.4.2.4 to 

focus only on steam generator tube fatigue usage due to FIV. The applicant also revised the 

TLAA disposition of the FIV fatigue usage to 10 CFR 54.21(c)(1)(i), which states that the 

analyses remain valid for the period of extended operation. The staff also verified that the 

applicant made the corresponding administrative change to LRA Table 4.1-1 associated with 

these LRA revisions.

Based on its review, the staff finds the applicant’s response to RAI 4.3.5-1b acceptable because 

the change in TLAA acceptance basis for the FIV fatigue analysis is in accordance with 

10 CFR 54.21(c). The staff’s concern described in RAI 4.3.5-1b is resolved.

By letter dated January 5, 2011, the staff issued RAI 4.3.5-1, Request 2, asking the applicant to 

clarify the value for the low-cycle fatigue usage and the induced bending stress that is 

referenced in LRA Section 4.3.5. In its response to RAI 4.3.5-1, Request 2, dated February 3, 
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40

2011, the applicant indicated that the “0.2 ksi” referred to the alternating FIV bending stress and 

the value is below the fatigue endurance limit of 20 ksi at 1E+11 cycles. The applicant stated 

that the resulting fatigue usage is zero. The staff noted that when the bending stress range is 

less than the fatigue endurance limit, the resultant fatigue usage is zero.

Based on its review, the staff finds the applicant’s response to RAI 4.3.5-1, Request 2, 

acceptable because the applicant clarified that the fatigue usage factor of the most limiting 

steam generator U-bend tube will remain zero during the period of extended operation. The 

staff’s concern in RAI 4.3.5-1, Request 2, is resolved.

The applicant stated that a prerequisite for high-cycle U-bend fatigue is a dented support 

condition at the upper tube support plate, and there is no concern for high cycle fatigue because

the steam generators have stainless steel tube support plates. The staff noted that, from 

industry experience in mid to late-1970s, denting resulted from the corrosion of the carbon steel 

support plates. The use of stainless steel tube support plate minimized the likelihood of denting.

Thus, the staff finds it acceptable that the applicant concluded that high-cycle fatigue is not likely 

to occur.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the FIV

fatigue analysis for the steam generator tube remains valid for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.1 because the number 

of assumed FIV cycles would not be exceeded during the period of extended operation.

4.3.5.3 UFSAR Supplement

LRA Section A.2.4.2.4, as amended by letter dated April 22, 2011, provides the UFSAR 

supplement summarizing the TLAA for steam generator tube fatigue in the U-bend region due to 

FIV. The staff reviewed LRA Section A.2.4.2.4 consistent with SRP-LR Section 4.3.3.3, which 

states that the summary description should contain information associated with the TLAA for 

steam generator tube fatigue regarding the basis for determining that the applicant has made 

the demonstration required by 10 CFR 54.21(c)(1).

Based on its review of the UFSAR supplement, as amended by letter dated April 22, 2011, the 

staff finds that the supplement meets the acceptance criteria in SRP-LR Section 4.3.2.3. 

Additionally, the staff determined that the applicant provided an adequate summary description 

of its actions to address steam generator tube 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 FIV fatigue analysis for the steam 

generator tubes 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).

4.3.6 Absence of TLAAs for Fatigue Crack Growth, Fracture Mechanics Stability, or 

Corrosion Analysis Supporting Repair of Alloy 600 Materials

4.3.6.1 Summary of Technical Information in the Application

LRA Section 4.3.6 describes the applicant’s evaluations for fatigue crack growth, fracture 

mechanics stability, or corrosion issues supporting the repair of Alloy 600 materials. 
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41

Specifically, the applicant stated that the pressurizer contains Alloy 600 material only as Alloy 

82/182 welds which are used to attach the pressurizer surge, spray, and relief valve nozzles to 

the safe ends and to attach the safe ends to the connecting piping. For these dissimilar metal 

welds, the applicant also stated that complete Alloy 690 structural weld overlays were 

performed during refueling outage 12 (spring 2008) as a mitigation measure, and these overlays 

were supported by fatigue crack growth analyses projected for a 60-year life. For this reason, 

the applicant concluded that these overlay fatigue crack growth analyses are not TLAAs.

LRA Section 4.3.6 also states that an RPV hot-leg nozzle Alloy 600 weld was mitigated through 

mechanical stress improvement process (MSIP) repair during refueling outage 13 (fall 2009). 

The applicant also stated that the MSIP repair for the vessel was supported by fatigue crack 

growth analysis projected for a 60-year life (the end of the period of extended operation); 

therefore, the applicant concluded that this analysis is not a TLAA.

4.3.6.2 Staff Evaluation

The staff reviewed LRA Section 4.3.6 and the applicant’s evaluation for the absence of TLAAs 

for these fatigue crack growth analyses to verify the applicant’s basis for concluding that there is 

no specific TLAA associated with the analyses performed to support the repair of Alloy 600 

materials. The staff’s review was performed in accordance with the review procedures in 

SRP-LR Section 4.1.3 and the acceptance criteria in SRP-LR Section 4.1.2, considering the

clarification in Section III.g.(i) of the SOC for 10 CFR Part 54 (FRN Volume 60, No. 88).

The applicant’s claim that the fatigue crack growth analyses that support the repair of Alloy 600 

materials are not TLAAs is based on the determination that Criterion 3 of 10 CFR 54.3(a), the 

analysis involves time-limited assumptions defined by the current operating term, is not met. 

However, LRA Section 4.3.6 does not provide the details regarding the fatigue crack growth 

analyses for the pressurizer and the RPV to allow the staff to confirm the applicant’s conclusion. 

The applicant stated that the fatigue crack growth analyses for both the pressurizer and the 

RPV were projected for a 60-year life, but it did not demonstrate why such analyses did not 

meet all of the six criteria identified in 10 CFR 54.3.

By letter dated January 5, 2011, the staff issued RAI 4.3.6-1, asking the applicant to explain the 

projection of the fatigue crack growth analyses performed for the pressurizer and RPV and 

justify why these analyses do not need to be identified as a TLAA.

In its response dated February 3, 2011, the applicant stated that the fatigue crack growth 

analyses performed for the pressurizer and the RPV weld repairs used a 43-year assumption 

that covers the entire period of extended operation for the relevant weld components. The 

applicant stated that the analyses should not be identified as a TLAA because Criterion 3 of 

10 CFR 54.3(a) (the analyses involve time-limited assumptions defined by the current operating 

period) is not met. 

Based on its review, the staff finds the applicant’s response to RAI 4.3.6-1 acceptable because 

the applicant’s fatigue flaw growth analyses for the pressurizer and the RPV weld repairs was 

performed to the end of the period of extended operation. Therefore, it does not meet Criterion 

3 of 10 CFR 54.3(a).

The staff finds acceptable the applicant’s conclusion that there is no specific TLAA that meets 

the requirements of 10 CFR 54.21(c)(1) and is associated with fatigue crack growth, fracture 

mechanics stability, or corrosion issues supporting the repairs of Alloy 600 materials, because 
Time-Limited Aging Analyses

42

the applicant has demonstrated that these analyses are not TLAAs, in accordance with Criterion 

3 of 10 CFR 54.3(a).

4.3.6.3 UFSAR Supplement

On the basis of its review, the staff finds that a UFSAR supplement is not required because the 

analyses associated with fatigue crack growth, including fracture mechanics stability or 

corrosion analyses, supporting the repair of Alloy 600 materials address the period of extended 

operation and thus are not TLAAs.

4.3.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration that the analyses performed to support the repair of Alloy 600 material are not 

TLAAs. The staff also concludes that a UFSAR supplement is not required.

4.3.7 Non-Class 1 Component Fatigue Analyses

4.3.7.1 Summary of Technical Information in the Application

LRA Section 4.3.7 describes the applicant’s fatigue TLAAs of the non-Class 1 piping and 

components designed in accordance with ASME Section III, Class 2 and 3. The applicant 

stated that the design of non-Class 1 piping and components in accordance with ASME Code 

Section III did not require an analysis based on the cumulative fatigue usage, rather the cyclic 

loading is considered in a simplified manner. The applicant noted that the design analysis 

compared the overall number of thermal and pressure cycles expected during the 40-year 

lifetime to cycle ranges specified in ASME Section III, Class 2 and 3 design codes, with 

consideration of allowable stress reduction if the total number of cycles exceeded 7,000.

The applicant stated that its TLAA assessment for 60-years of operation consisted of projecting 

the total number of applicable transient cycles for the period of extended operation, comparing 

these projections with the limit of 7,000, and assessing the fatigue impact if the projected cycles 

required a reduction in the allowable stress ranges. The applicant further stated that its 

assessment, even if all of the projected operational transients were added together, showed that 

there is no impact upon the original fatigue analyses used for these piping and components 

when designed to the ASME Section III, Class 2 and 3 requirements.

The applicant dispositioned the non-Class 1 piping and components fatigue analysis TLAA in 

accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended 

operation.

4.3.7.2 Staff Evaluation

The staff reviewed LRA Section 4.3.7 and the non-Class 1 piping and components fatigue 

analyses to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the 

period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with 

SRP-LR Section 4.3.3.1.2.1. These procedures state that the operating cyclic experience, and 

a list of the assumed thermal cycles used in the existing allowable stress determination, should 

be reviewed to ensure that the number of assumed thermal cycles would not be exceeded 

during the period of extended operation.
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43

LRA Section 4.3.7 states that the applicant projected the number of cycles for various relevant 

transients to evaluate the TLAA for 60 years and then compared this projection to the 7,000 

cycles considered in the original design. The staff noted that the 60-year projections are based 

on a linear extrapolation that uses the number of cycles accumulated through April 1, 2009. 

The staff confirmed that the total number of projected cycles for all applicable transients, 

provided in LRA Table 4.3.1-3, does not exceed the original design limit of 7,000 cycles, in 

accordance with ASME Code Section III, Subsections NC and ND.

SRP-LR Section 4.3.1.1.2 states that, for piping designed and analyzed to American National 

Standards Institute (ANSI) B31.1, allowable stress levels based on the number of anticipated 

thermal cycles are specified. The staff noted that UFSAR Table 3.2-2 indicates that the piping 

(downstream of the safety valves) of the pressurizer relief discharge system is designed to 

ANSI B31.1. The staff further noted that LRA Section 2.3.1.1 states that the pressurizer relief 

tank, pump, heat exchanger, and connected pipes and valves are within the scope of the 

license renewal. However, the applicant did not provide details regarding the applicable 

ANSI B31.1 piping and the associated TLAA in the LRA Section 4.3.7.

By letter dated January 5, 2011, the staff issued RAI 4.3.7-1, asking the applicant to clarify if 

there are any piping, piping components or piping elements—designed and analyzed in 

accordance with ANSI B31.1—that are within the scope of license renewal. The staff also 

asked the applicant to justify that LRA Section 4.3.7 provides adequate disposition of the 

fatigue-related TLAA for all non-Class 1 piping and components (including Class 2, Class 3, and 

ANSI B31.1).

In its response dated February 3, 2011, the applicant stated that, as shown in UFSAR 

Table 3.2-2, the principal design code is ANSI B31.1 for several sections of piping. 

Furthermore, these piping, piping components, or piping elements are within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2), as a failure could affect a 

10 CFR 54.4(a)(1) classified component. The applicant also stated that, as specified in LRA 

Section 4.3.7, the 60-year transient projection results shown in LRA Table 4.3.1-3 show that, 

even if all of the projected operational transients are added together, the total number of cycles 

projected for 60 years will not exceed the 7,000 cycles limit. Therefore, the allowable stress 

range does not need to be reduced as described in ASME Section III Class 2 and 3 and B31.1 

rules.

However, the staff noted that the applicant did not amend LRA Section 4.3.7 to include the 

piping, piping components, and piping elements that were designed in accordance with ANSI 

B31.1 rules and are within the scope of license renewal. The applicant also did not identify that 

the evaluation performed in LRA Sections 4.3.7 and A.2.4.2.5 is applicable to the ANSI B31.1 

piping. The staff noted that, in LRA Sections 4.3.7 and A.2.4.2.5, only ASME Section III, 

Class 2 and 3 components, were considered as non-Class 1 and dispositioned in accordance 

with 10 CFR 54.21(c)(1)(i). By letter dated March 30, 2011, the staff issued followup

RAI 4.3.7-1b, requesting that the applicant revise LRA Section 4.3.7 and the applicable LRA 

Appendix A section to show that piping and piping components that were designed in 

accordance with ANSI B31.1 rules are included as part of the non-Class 1 piping and 

components addressed by this TLAA.

In its response dated April 22, 2011, the applicant revised LRA Sections 4.3.7 and 

Section A.2.4.2.5 to show that piping and piping components designed to ANSI B31.1 rules are 

within the scope of license renewal. The applicant also stated that the fatigue analysis of those 

B31.1 piping and piping components is dispositioned as part of the non-Class 1 piping in LRA 
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44

Section 4.3.7. Based on its review, the staff finds the applicant’s response to RAI 4.3.7-1b 

acceptable because the applicant revised LRA Sections 4.3.7 and A.2.4.2.5 to include piping 

and components designed to ANSI B31.1, in accordance with SRP-LR Section 4.3.2.1.2.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the TLAA 

associated with fatigue analyses of non-Class 1 piping and components 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 cycles for all applicable 

transients over the period of extended operation does not exceed the 7,000 cycle limit.

4.3.7.3 UFSAR Supplement

LRA Section A.2.4.2.5, as amended by letter dated April 22, 2011, provides the UFSAR 

supplement summarizing the non-Class 1 piping and components fatigue analysis. The staff 

reviewed LRA Section A.2.4.2.5, consistent with SRP-LR Section 4.3.3.3, which states that the 

summary description should contain information associated with the evaluation of the 

non-Class 1 piping and components fatigue analyses.

Based on its review of the UFSAR supplement, as amended by letter dated April 22, 2011, the 

staff finds that the supplement meets the acceptance criteria in SRP-LR Section 4.3.2.3. 

Additionally, the staff determined that the applicant provided an adequate summary description 

of its actions to address the non-Class 1 piping and components fatigue analysis, as required by 

10 CFR 54.21(d).

4.3.7.4 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 non-Class 1 piping and components 

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).

4.4

4.4.1 Summary of Technical Information in the Application

Environmental Qualification (EQ) of Electrical Equipment

LRA Section 4.4 summarizes the evaluation of EQ of electrical equipment for the period of 

extended operation. The applicant stated that the Seabrook EQ of Electric Components 

Program implements aging management activities, which are credited for the management of 

aging in selected components within the scope of 10 CFR 54. The Seabrook EQ Program is an 

existing program that is consistent with NUREG-1801, GALL Report Section X.E1, 

“Environmental Qualification (EQ) of Electric Components.” The applicant also stated that the 

program is administered in accordance with the Seabrook EQ Manual. The applicant further 

stated that as required by 10 CFR 50.49, EQ components not qualified for the current license 

term are to be refurbished, replaced, or have their qualification extended prior to reaching the 

aging limits established in the evaluation. Aging evaluations for electrical components in the 

Seabrook EQ Program that specify a qualification of at least 40 years are TLAAs for license 

renewal because the criteria contained in 10 CFR 54.3 are met.
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45

The applicant stated that, under 10 CFR Part 54.21(c)(1)(iii), the Seabrook EQ Program, which 

implements the requirements of 10 CFR 50.49 (as further defined and clarified by 

NUREG-0588, and RG 1.89, Revision 1), is viewed as an AMP for license renewal. 

Reanalysis of an aging evaluation to extend the qualifications of components is performed on a 

routine basis as part of the Seabrook EQ Program. Important attributes for the reanalysis of an 

aging evaluation include analytical methods, data collection and reduction methods, underlying 

assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met).

The applicant dispositioned the EQ requirements 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. The applicant stated that the 

Seabrook EQ Program has been demonstrated to be capable of programmatically managing the 

qualified lives of the components within the scope of the program for license renewal. The 

continued implementation of the Seabrook EQ Program insures that the aging effects will be 

managed and that EQ components will continue to perform their intended functions for the 

period of extended operation.

4.4.2 Staff Evaluation

The staff reviewed LRA Section 4.4 on the TLAA associated with the EQ of Electrical 

Components Program 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 SRP-LR 

Section 4.4.3.1.3. The staff’s review of the EQ of Electrical Components Program is 

documented in SER Section 3.0.3.1.16.

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 10 CFR 50.49 EQ 

Program 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 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 high-energy line break 

(HELB), or post-LOCA environment. EQ equipment comprises safety-related and Q-list 

equipment, 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, B.2,3.2, plant basis documents and interviewed plant 

personnel to verify whether the applicant provided adequate information to meet the 

requirement of 10 CFR 54.21(c)(1). For the 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. The staff 

reviewed the applicant’s 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. Per 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 AMP X.E1, “Environmental Qualification 
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46

(EQ) of Electric Components,” provides a means to meet the requirements of 

10 CFR 54.21(c)(1)(iii). 

The staff’s evaluation of the components qualification focused on how the EQ Program 

manages the aging effects to meet the requirements pursuant to 10 CFR 50.49. The staff 

conducted an audit of the information provided in LRA Sections 4.4, Section B.2.3.2, and 

program basis documents. LRA Section 4.4 discusses the component reanalysis attributes, 

including analytical methods, data collection and reduction methods, underlying assumptions, 

acceptance criteria, and corrective actions. As evaluated in SER Section 3.0.3.1.16, the staff 

found that the EQ Program, which the applicant claimed to be consistent with GALL AMP X.E1, 

“Environment Qualification of (EQ) Electric Components,” is consistent with the GALL Report. 

The staff further concludes that the applicant’s EQ of Electrical Equipment TLAA is implemented 

per the requirements of 10 CFR 54.21(c)(1)(iii). 

Therefore, the staff finds that the applicant’s EQ Program demonstrates, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effect of aging on the intended function(s) will be adequately 

managed for the period of extended operation. The applicant’s EQ Program is, therefore,

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

In LRA Appendix A, Section A.2.4.3, the applicant provides the UFSAR summary description for 

the EQ of Electrical Equipment TLAA.

. 

The staff reviewed the UFSAR supplement description of the program against the 

recommended description for this type of program, as described in SRP-LR Tables 4.4-1 and 

4.4-2, and finds the UFSAR supplement consistent with the guidance of SRP-LR Tables 4.4.1 

and 4.4.2.

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, 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 demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the environmental qualification of electrical equipment TLAA will be 

adequately managed for the period of extended operation. The staff also reviewed the UFSAR 

supplement and concludes that it provides an adequate summary description of the program, as 

required by 10 CFR 54.21(d).

. 

4.5

4.5.1 Summary of Technical Information in the Application

Concrete Containment Tendon Pre-stress

LRA Section 4.5 summarizes the evaluation of concrete containment tendon pre-stress for the 

period of extended operation. The applicant stated that it has no TLAA associated with the 

concrete containment tendon pre-stress because the containment does not use pre-stressed 

tendons. Therefore, tendon pre-stress evaluations are not applicable.
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47

4.5.2 Staff Evaluation

The staff reviewed relevant containment design information in the UFSAR to evaluate the 

validity of the applicant’s basis. The staff noted that UFSAR Section 3.8.1.1 identifies the 

containment as a Category I reinforced concrete dry structure, which is designed to function at 

atmospheric conditions. The staff noted that UFSAR Section 3.8.1.1 states that the 

containment was designed as a seismic Category I conventionally reinforced concrete structure 

and does not use a pre-stressed concrete design. Based on this review, the staff verified that 

the design of the containment structure is not reinforced with pre-stressed tendons; therefore, 

the staff finds that this TLAA is not required. The staff also references its evaluation in SER 

Section 3.5.2.2.1.5 (“Loss of Prestress due to Relaxation, Shrinkage, Creep and Elevated 

Temperature”).

4.5.3 UFSAR Supplement

The staff concludes that no UFSAR supplement is required because Seabrook has no 

pre-stressed tendons in the containment building.

4.5.4 Conclusion

On the basis of its review, the staff concludes that loss of pre-stress in concrete containment 

tendons is not a TLAA.

4.6

4.6.1 Containment Liner Plate Fatigue Usage

Containment Liner Plate Fatigue Usage and Containment Penetration 

Pressurization Cycles

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 describes the applicant’s TLAA of the containment structure, which is a 

leak-tight membrane made of a welded carbon steel liner attached to the inside face of the 

concrete shell. The LRA states that fatigue of the containment liner plate was considered in the 

original design based on an assumed number of loading cycles that could occur during the life 

of the plant. The applicant determined that the Seabrook containment liner plate does not 

require analysis for cyclic service because it meets the criteria of ASME Section III Article 

NE-3221.5(d). The applicant further stated that the transients needing assessment for 

conformance with the ASME Section III Article NE-3221.5(d) exemption criteria are as follows: 

• atmospheric-to-service pressure cycles and normal service pressure fluctuations

• temperature differences—startup and shutdown for similar and dissimilar materials

• mechanical loads

The LRA states that the anticipated stress cycles through 40 years of operation satisfy the 

exemption criteria of ASME Section III Article NE-3221.5(d), as follows: 

• atmospheric-to-service pressure cycles (120 cycles)

• temperature differences from startup to shutdown (120 cycles)

• operating basis earthquake (OBE) (500 cycles)

• LOCA (10 cycles)
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48

The LRA also states that the 40-year values were increased (linearly) by 50 percent to derive 

the projected values for 60 years of operation, and that the 60-year projections continue to 

satisfy the criteria of ASME Section III Article NE-3221.5(d).

The applicant dispositioned the containment liner plate fatigue TLAA, 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.

4.6.1.2 Staff Evaluation

The staff reviewed LRA Section 4.6.1, and the containment liner plate TLAA, 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.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with 

SRP-LR Section 4.6.3.1.1.2, which states that the operating transient experience and the list of 

the number of assumed cyclic loads projected to the end of the period of extended operation 

need to be satisfied to ensure that the cyclic load projection is adequate under the code of 

record.

The staff noted that the applicant evaluated the requirements for fatigue exemption using a 

linearly increased number of cycles to extend the analysis to the end of the period of extended 

operation. The staff also noted the applicant’s assertion that, with the increased number of 

cycles, the analysis continues to meet the requirements of ASME Section III Article 

NE-3221.5(d) for exemption from cyclic analyses. The staff reviewed Section 3.8 of UFSAR, 

titled “Design of Category I Structures,” but noted an apparent discrepancy in the stress cycles 

that were reported in the LRA initial exemption when compared to those reported in the UFSAR 

for the same exemption. In a teleconference held on May 5, 2011, the staff requested 

clarification of this discrepancy. 

By letter dated April 16, 2012, the applicant responded by stating that the entry in UFSAR 

Section 3.8.1.3 titled “Loads and Loading Combinations,” under “a. Design Loads,” item 8 

“Cyclic Loading,” shows the design loads for the containment liner plate. The applicant used 

these loads for the screening calculations to qualify the liner for the exemption from detailed 

fatigue analysis. The applicant further stated that it used the UFSAR-reported 120 cycles for 

plant startups and shutdowns for the exemption qualification requirements (e.g., because of the 

pressure and temperature relationship, the same cycles were used for both 

atmospheric-to-service pressure cycles and temperature differences during startup and 

shutdown.) The staff considered this input and did an independent code-based verification of

the liner according to the requirements of ASME Section III Article NE-3221.5(d). The staff 

concluded that the liner plate meets the criteria set by the code to qualify it for the exemption 

from detailed fatigue analysis for the period of extended operation or for 60 years of operation.

During the May 5, 2011 teleconference, the staff also asked the applicant why 10 accident 

(LOCA) cycles were used in the fatigue exemption analysis instead of one cycle as stated in the 

UFSAR. 

By letter dated April 16, 2012, the applicant responded that it used 10 cycles for conservatism in 

the TLAA analysis, but that the design basis load is one cycle as stated in the UFSAR. The 

staff found the approach acceptable because it provided a more conservative analysis for the

code exemption. The staff's concern is resolved.
Time-Limited Aging Analyses

49

The staff finds that the applicant has demonstrated, pursuant to 10 CFR (c)(1)(ii), that the 

exemption analyses for the containment liner plate fatigue usage have been projected to the 

end of the period of extended operation.

Additionally, it meets the acceptance criteria in SRP-LR Section 4.6.2.1.1.2 because the 

analysis has been re-evaluated in accordance with the ASME code of record fatigue exemption 

criteria based on an increased number of cycles to cover the period of extended operation.

4.6.1.3 UFSAR Supplement

LRA Section A.2.4.4, “Fatigue of the Containment Liner and Penetrations,” provides the UFSAR 

supplement summarizing the TLAA of the containment liner plate. The staff reviewed LRA 

Section A.2.4.4 consistent with SRP-LR Section 4.6.3.2, which states that the applicant should 

provide a summary description of the fatigue evaluation of the containment liner and 

penetrations including the basis for determining that the applicant has made the demonstration 

required by 10 CFR 54.21(c)(1).

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address the TLAA of the containment liner plate, 

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 provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the TLAA of the containment liner plate 

is projected to the end of the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.6.2 Pressurization Cycles: Personnel Airlock, Equipment Hatch, and Fuel Transfer 

Tube Assembly Absence of TLAA for Containment Penetrations

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6.2 describes the applicant’s assessment of time-limited aging analyses (TLAAs) 

for the personnel airlock, equipment hatch, and the fuel transfer tube assembly containment 

penetrations. The LRA states that the designs of other containment penetrations designed to 

ensure a leak-tight membrane to contain the radioactive material released in the unlikely event 

of a loss of coolant accident (LOCA) are not TLAAs because they do not include any cyclic 

evaluations. 

The LRA also states that the design of the Seabrook containment penetrations considered the 

design stresses against allowable stress limits independent of the number of load cycles and 

that there was no fatigue analysis. The applicant further stated that comparison to other 

containment systems designed by United Engineers and Constructors (UE&C) resulted in 

similar design criteria. 

The applicant stated that the anticipated number of cycles for the personnel airlock, equipment 

hatch, and fuel transfer tube assembly projected to occur during the period of extended 

operation is bounded by the original design. The applicant stated that this basis is documented 

in UFSAR Section 3.8.2.3, and the cyclic loads considered in the design include 120 cycles of 
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50

plant startup and shutdown, 400 OBE cycles, 100 SSE cycles, 1 accident cycle (LOCA), and 

160 pressure test cycles. For the fuel transfer tube assembly, the cyclic loads considered are 

400 OBE cycles, 1 accident cycle (LOCA), 160 pressure test cycles, and 1,000 temperature 

cycles.

The applicant dispositioned the personnel airlock, equipment hatch, and fuel transfer tube 

assembly penetration TLAA in accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain 

valid for the period of extended operation.

4.6.2.2 Staff Evaluation

The staff reviewed LRA Section 4.6.2 and the personnel airlock, equipment hatch, and the fuel 

transfer tube assembly fatigue usage TLAA to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation, and to verify the applicant’s claim 

that the design of other containment penetrations is not a TLAA.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with 

SRP-LR Section 4.6.3.1.1.1, 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 confirms that the number of transients in the existing analyses will not be 

exceeded during the period of extended operation.

The staff reviewed LRA Table 4.3.1-3 and found that the plant is designed to 200 temperature 

cycles, 50 OBE cycles, 1 SSE (10 cycles), and 1 LOCA. The personnel airlock and equipment 

hatch were designed to 400 OBE cycles, 100 SSE cycles, and 1 LOCA, which exceed the 

number of cycles used for those transients in the plant design. For the temperature cycles, 

however, the staff noted that the 120 cycles to which the personnel airlock and equipment hatch 

were designed are less than the cycles assumed in the original plant design. Although the 60-

year temperature cycle projections of 87 heatup and 84 cooldown cycles (LRA Table 4.3.1-3) 

are bounded by the design fatigue analyses for the personnel airlock and equipment hatch, the 

staff was concerned that fatigue may not be considered if the plant approached or exceeded 

120 cycles, since the NSSS design limits allow for 200 cycles. 

In a conference call on November 22, 2011 the staff inquired how the applicant will track design

limits related to plant startups and shutdowns as listed in LRA Section 4.6.2 related to the

Equipment Hatch and Personnel Air Lock. In asking this question, the staff noted that in the 

applicant’s response to RAI B.2.3.1-3 and RAI B.2.3.1-4 (Reference 3) the design limit tracked 

by FatiguePro is 200 Plant Heatups and Cooldowns with an 80% trigger level for further

evaluation. The staff further noted that this action limit would exceed the design limit of 120 

heatup and cooldown cycles for the Personnel Airlock and Equipment Hatch as specified in LRA 

section 4.6.2.

By letter dated December 15, 2011, the applicant stated that it had revised LRA Table 4.3.1-2 

previously submitted in response to RAI B2.3.1-3 to include the specific plant startup and 

shutdown design limit of 120 cycles for the Personnel Airlock and Equipment Hatch. In addition, 

cycle counting for these specific components will initiate appropriate evaluations through the 

corrective action program if the 80% action limit is reached and this limit will be used by the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program for all limits tracked in 

FatiguePro. The applicant stated that this action limit will provide sufficient margin and time to 

allow for appropriate corrective actions as defined in the Metal Fatigue of Reactor Coolant 
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51

Pressure Boundary Program to be implemented prior to reaching the design limit. The staff 

reviewed the revised LRA Table 4.3.1-2 and confirmed that the applicant included a separate 

line item with a design limit of 120 cycles, which is specific only to the Personnel Airlock and 

Equipment Hatch analysis.

The applicant's December 15, 2011, letter confirmed that there were no additional non 

conservative design limits utilized in the TLAA for the Personnel Airlock and Equipment Hatch.

The staff finds the applicant’s supplement acceptable because (1) the applicant’s Metal Fatigue 

of Reactor Coolant Pressure Boundary Program ensures that the design cycles (120 plant 

heatups and cooldowns) that were used in the fatigue analysis for the personnel airlock and 

equipment hatch will not be exceeded during the period of extended operation; (2) the program 

ensures sufficient time for corrective actions to be taken (i.e. reanalysis of the component, repair 

or replacement of the component) with an 80% action limit on the design cycles; and (3) the 

applicant confirmed that there are no other analyses that contain more limiting number of cycles 

that need to be incorporated into the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program.

The design of the fuel transfer tube assembly considers 400 OBE cycles, 1 LOCA, and 1,000 

temperature cycles, all of which exceed the respective number of transients considered in the 

original plant design, so the existing fuel transfer tube assembly fatigue calculations for these 

transients will also remain valid for 60 years of operation. 

As described in SER Section 4.7.5, the applicant's response to RAI 4.7.5-1 part (1), stated that 

the number of pressure test cycles considered in the personnel airlock, equipment hatch, and 

fuel transfer tube assembly designs is consistent with containment pressure testing. During the 

regional inspection the week of April 4, 2011, the staff asked the applicant whether the 

containment pressure testing referenced in the RAI 4.7.5-1 response referred to 10 CFR Part 50 

Appendix J containment leak rate testing. The applicant confirmed that the referenced 

containment pressure testing is the Appendix J testing. The staff finds that the original design 

value of 160 pressurization cycles provides adequate margin for the period of extended 

operation because these loading cycles are in excess of the current cycles and those 

anticipated from projected Appendix J testing, as described in LRA Section B.2.1.31 for the 60 

years of plant operation. 

The staff finds the disposition of the TLAAs for the personnel airlock, equipment hatch, and fuel 

transfer tube assembly acceptable in accordance with 10 CFR 54.21(c)(1)(i), because the 

number of transients in the existing fatigue analyses will not be exceeded during the period of 

extended operation.

For the other containment penetrations, the staff reviewed UFSAR Section 3.8.2; subsections 

relating to piping, electrical, instrumentation, and ventilation penetrations; and the LRA. The 

LRA states that the design of the containment penetrations did not involve cyclic evaluations 

and, therefore, the designs are not TLAAs. The staff noted in the UFSAR that these five 

penetrations are designed according to the ASME Boiler and Pressure Vessel Code, Section III, 

Division 1, and that cyclic loading and fatigue was not considered in the original design.

In a teleconference held on May 5, 2011, the staff asked the applicant to confirm whether the 

design of any containment penetrations contained cyclic analyses. 

By letter dated April 16, 2012, the applicant reaffirmed that these are not TLAAs and noted that 

its design engineer, United Engineers and Constructors, did not perform any cyclic analyses. 
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The staff reviewed the applicant’s response and finds it acceptable because the current

licensing basis does not include cyclic analyses, and therefore, the design of the penetrations 

does not meet the definition of a TLAA as stated in 10 CFR 54.3(a) Criterion 6. The staff's 

concern is resolved.

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i) that the 

analyses for the personnel airlock, equipment hatch, and fuel transfer tube assembly remain 

valid during the period of extended operation. The staff also finds that for the analyses of the 

other containment penetrations, TLAAs are not required.

4.6.2.3 UFSAR Supplement

LRA Section A.2.4.4 originally provided the UFSAR supplement summarizing the TLAA for the 

containment liner plate, and did not include the personnel airlock, equipment hatch, and fuel 

transfer tube assembly. By letter dated April 22, 2011, the applicant addressed the staff’s 

observation of this inconsistency by amending LRA Section A.2.4.4 to summarize the TLAAs for 

the personnel airlock, equipment hatch, and fuel transfer tube assembly. The staff reviewed the 

amended LRA Section A.2.4.4 consistent with SRP-LR Section 4.6.3.2, which states that the 

applicant should provide a summary description of the fatigue evaluation of the containment 

liner and penetrations including the basis for determining that the applicant has made the 

demonstration required by 10 CFR 54.21(c)(1).

Based on its review of the UFSAR supplement, as amended, the staff finds it meets the 

acceptance criteria in SRP-LR Section 4.6.2.2. Additionally, the staff determined that the 

applicant provided an adequate summary description of its actions to address the TLAA of the 

personnel airlock, equipment hatch, and fuel transfer tube assembly, 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 provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the TLAA of the personnel airlock, 

equipment hatch, and fuel transfer tube assembly 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). The staff further 

concludes that a TLAA is not required for the other containment penetrations.

4.7

An applicant may need to include a plant-specific analysis in the CLB as a TLAA for its LRA if 

the analysis conforms to the six criteria for TLAAs in 10 CFR 54.3. The NRC’s recommended 

“acceptance criteria” and “review procedure” guidance on matters related to the acceptance of 

plant-specific TLAAs are given in SRP-LR Section 4.7 and its subsections.

Other Plant-Specific TLAA

SRP-LR Section 4.7.2 provides the staff’s recommended “acceptance criteria” guidance for 

these TLAAs, and SRP-LR Section 4.7.3 provides the staff’s recommended “review procedures” 

for these TLAAs. The subsections in SRP-LR Sections 4.7.2 and 4.7.3 provide the “acceptance 

criteria” and “review procedures” for accepting plant-specific TLAAs in accordance with the 

requirements of 10 CFR 54.21(c)(1)(i), 10 CFR 54.21(c)(1)(ii), or 10 CFR 54.21(c)(1)(iii).
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4.7.1 Absence of a TLAA for Reactor Pressure Vessel Underclad Cracking Analyses

4.7.1.1 Summary of Technical Information in the Application

The applicant states that the growth of underclad cracks is not an applicable aging effect for 

Seabrook because the procedure qualification for laying down the cladding on the RPV low alloy 

steel components (SA-508, Class 2) required a special evaluation to assure freedom from 

underclad cracking, as described in the Seabrook UFSAR. Therefore, the applicant stated that 

no TLAA has been assigned in the CLB to the evaluation of cracking in the applicable RPV 

cladding-to-forging welds.

4.7.1.2 Staff Evaluation

The staff reviewed LRA Section 4.7.1 and pertinent information in the plant UFSAR to evaluate 

the validity of the applicant's basis.

The staff noted that RG 1.43 identifies that intergranular separations (i.e., underclad cracks) 

have been reported in SA-508, Class 2 RPV forgings when the vessel was manufactured with a 

cladding applied by a high-heat-input, submerged arc welding (SAW) process. According to this 

RG, there is a potential (although small) for these cracks to grow into the ferritic RPV shell as a 

result of cyclical loading. Therefore, Section 3.1.2.2.5 of the SRP-LR states that cyclic crack 

growth could occur and such growth is a TLAA that should be evaluated for the period of 

extended operation if the cladding was welded to the RPV SA-508, Class 2 forgings using a 

high-heat-input welding process. Such analyses may need to be identified as TLAAs for the 

LRAs if they conform to the six criteria for TLAAs in 10 CFR 54.3.

The staff verified that UFSAR Sections 5.2.3 and 5.3.1.4 indicate that the applicant applied the 

NRC’s recommended weld control process in RG 1.43, “Control of Stainless Steel Weld 

Cladding of Low Alloy Steel Components,” as the process for controlling the welding fabrication 

of the cladding to those RPV components that were fabricated from SA 508, Class 2 forging 

materials. The staff also verified that UFSAR Section 1.8 shows the applicant’s procedural 

qualification was performed in accordance with the weld fabrication requirements in Sections III 

and XI of the ASME Code and in accordance with supplemental qualification criteria (i.e., 

Position C.2) of RG 1.43, which provides the staff’s recommended welding qualification process 

controls for avoiding underclad cracking in these cladding-to-forging welds.

Therefore, given the applicant’s special evaluation included the appropriate weld procedure 

qualification protocols for the cladding-to-forging welds, the staff determined that the RPV 

underclad cracking is not relevant in making a safety determination and, therefore, does not 

meet the definition of a TLAA, consistent with the requirements of 10 CFR 54.3(a)(4).

4.7.1.3 Conclusion

The staff concludes that there is not a TLAA for RPV underclad cracking because the RPV was 

manufactured with a cladding procedure that required a special evaluation and procedural 

qualification to assure freedom from underclad cracking. Therefore, according to the definition 

in 10 CFR 54.3(a)(4), this item is not a TLAA for Seabrook.
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4.7.2 Reactor Coolant Pump Flywheel Fatigue Crack Growth Analyses

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2 discusses reactor coolant pump (RCP) flywheel fatigue crack growth 

analyses. The applicant stated that Westinghouse Commercial Atomic Power 

(WCAP)-14535-A, “Reactor Coolant Pump Flywheel Inspection Elimination,” provided an 

engineering basis for elimination of RCP flywheel inservice inspection (ISI) requirements for all 

operating Westinghouse plants and certain Babcock and Wilcox plants. To be consistent with 

the defense-in-depth philosophy for protection against events or degradation mechanisms that 

are not anticipated or considered in the analysis, the NRC issued an SER in September 1996 

that requires continuation of ISI with a 10-year inspection interval that coincides with RCP motor 

maintenance. Fatigue crack growth analyses that are included in the WCAP-14535-A report 

have been identified as a TLAA. The applicant stated that the number of cycles (pump starts 

and stops) used in this report (6,000 for a 60-year plant life) is substantially less than the 

60-year cycle projection for the Seabrook RCP flywheels found in LRA Table 4.4.2-1. 

Therefore, any potential crack growth from an existing flaw would be minimal, and the analysis 

in the WCAP-14535-A report remains valid for the period of extended operation.

In LRA Table 4.4.2-1, the applicant provided the current and 60-year projected number of RCP 

start and stop cycles. Based on data obtained from Seabrook cycle-counting records to date 

and projecting the count to a 60-year EOL, the applicant concluded that the 60-year projection 

of RCP start and stop cycles for the four Seabrook RCPs will be no more than 536 cycles. The 

applicant concluded that the projected number of RCP starts and stops is not expected to 

exceed 6,000 cycles during the period of extended operation. The applicant dispositions this 

flywheel TLAA, in accordance with 10 CFR 54.21(c)(1)(i).

4.7.2.2 Staff Evaluation

SRP-LR Section 4 does not list RCP flywheel fatigue crack growth analyses as TLAAs that are 

generic to industry LRAs. As a result, the staff reviewed LRA Section 4.7.2 against the 

acceptance guidance in SRP-LR Section 4.7.2.1 for disposition of a plant-specific TLAA in 

accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended 

operation.

The staff noted that RG 1.14, Revision 1, “Reactor Coolant Pump Flywheel Integrity” (August 

1976), provides the staff’s recommended acceptance criteria for material and minimum fracture 

toughness properties of SA 508, Classes 2 and 3, materials and SA 533 Grade B, Class 2, 

materials used in the fabrication of U.S. RCP flywheels. RG 1.14, Revision 1, also provides 

guidelines for performing structural integrity assessments of the RCP flywheels in U.S. 

light-water reactors, including assessments for ensuring the integrity of the flywheels against 

unacceptable fatigue-induced crack growth failures.

The applicant stated that the fatigue crack growth assessments are based on the number of 

start-stop cycles assumed in the design specifications for the pumps. Therefore, to meet the 

10 CFR 54.21(c)(1)(i) acceptance criterion, the applicant indicated that it must demonstrate that 

the total number of RCP start-stop cycles, projected through the end of the period of extended 

operation, will be bounded by the number of RCP start-stop cycles assumed in the fatigue crack 

growth analysis for the RCP flywheels.
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The staff noted that the applicant is relying on the flaw growth analysis in WCAP-14535-A 

(ADAMS Accession No. ML9601290303) as the TLAA for the RCP flywheels. The staff verified 

that the NRC endorsed the methodology and results in this WCAP report in an SE dated 

September 12, 1996 (ADAMS Accession No. ML9609230010). However, in the conclusion 

section of the SE (Section 4.0), the staff concluded that that the inspections of the flywheels 

should be performed even if all of the recommendations of RG 1.14, Revision 1, were met, and 

the inspections of the RCP flywheels should not be eliminated. It was not clear to the staff from 

the TLAA discussion if the applicant intends to continue the inservice inspections of the RCP 

flywheels during the period of extended operation consistent with the position taken in the staff’s 

SE of September 12, 1996, or if the applicant is proposing to discontinue the ISI examinations of 

the RCP flywheels during the period of extended operation.

By letter dated January 5, 2011, the staff issued RAI 4.7.2-1, asking the applicant to clarify if it is 

using the safety basis in the TLAA for the RCP flywheels to justify elimination of the RCP 

flywheel examinations altogether or if it intends to continue ISI of the RCP flywheels consistent 

the NRC’s SE on WCAP-14535-A, dated September 12, 1996. If ISI will be performed during 

the period of extended operation, the staff also asked the applicant to explain what type of 

examinations will be performed on the RCP flywheels during the period of extended operation 

and the frequency that will be used for the examinations. Otherwise, the applicant was asked to 

justify its basis for discontinuing ISI of the RCP.

The applicant’s February 3, 2011, response indicated that over the first 20 years of operation, all 

of the RCP flywheel inspections have been performed in accordance with TS requirements. 

During that time, no unacceptable indications have been found during the required surface and 

volumetric inspections. In addition, the applicant stated that, during the period of extended 

operation, Seabrook will continue the surface and volumetric inspections of the RCP flywheels 

on the required interval. However, the applicant did indicate that it was evaluating a license 

amendment request to change the inspection frequency from 10 years (current requirement) to 

20 years.

The staff reviewed the applicant’s February 3, 2011, response, Section 4.7.2 of the LRA, and 

WCAP-14535-A, along with the associated NRC SE. The staff determined that the projected 

start-stop cycles after 60 EFPY will be well below the 6,000 cycles used in fatigue flaw growth 

analysis of WCAP-14535-A. The staff also noted that the applicant will continue to perform 

surface and volumetric inspection every 10 years.

In summary, the staff finds the applicant’s response to RAI 4.7.2-1, and the applicant’s claim 

that the RCP flywheels will maintain their structural integrity during the period of extended 

operation acceptable, for the following reasons:

• The maximum number of start-stop cycles projected for 60 years (e.g., 536 start-stop 

cycles) have been demonstrated to be bounded by the 6,000 start-stop cycles limit 

assumed in the WCAP-14535-A fatigue flaw growth analysis.

• WCAP-14535-A has been endorsed for use in the staff’s SE of September 12, 1996.

• Future inspections will be performed once every 10 years.

The staff’s concerns described in RAI 4.7.2-1 are resolved.

Based on this review, the staff concludes that the applicant has demonstrated, in accordance 

with 10 CFR 54.21(c)(1)(i), that the fatigue analysis for the RCP flywheels has been 

demonstrated to remain valid for the period of extended operation. 
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4.7.2.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the RCP flywheel fatigue crack growth analysis in LRA Section A.4.4.2. On the basis of its 

review of the UFSAR supplement, the staff concludes that the summary description of the 

applicant’s actions to address RCP flywheel fatigue crack analyses is adequate.

4.7.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the fatigue crack analysis for RCP flywheels remains valid for the 

period of extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.3 Leak-Before-Break Analyses

4.7.3.1 Summary of Technical Information in the Application

LRA Section 4.7.3 describes the applicant’s TLAA for leak-before-break (LBB) analyses for RCS 

primary loop piping. The applicant stated that these analyses were conducted to eliminate the 

need to consider dynamic effects of pipe ruptures from the design basis of the plant, as 

described in 10 CFR Part 50 Appendix A, “General Design Criteria for Nuclear Power Plants,” 

Criterion 4, “Environmental and Dynamic Effects Design Bases.” The applicant also stated that 

the fundamental premise of the LBB methodology is that the materials used in nuclear power 

plant piping are sufficiently tough that even a large through-wall crack would remain stable and 

would not result in a double-ended pipe rupture. The applicant further stated that the 

application of the LBB methodology is limited to those high-energy fluid systems not considered 

to be overly susceptible to failure from such mechanisms as corrosion, water hammer, fatigue, 

thermal aging, or indirectly from such causes as missile damage or the failure of nearby 

components.

The applicant dispositioned the LBB analyses TLAA for RCS primary loop pipe in accordance 

with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended operation.

4.7.3.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3, LBB analyses for RCS primary loop pipe, to verify that, 

pursuant to 10 CFR 54.21(c)(1)(i), the analyses remain valid for the period of extended 

operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with 

SRP-LR Section 4.7.3, which states that for certain applicants, plant-specific analyses may 

meet the definition of a TLAA as given in 10 CFR 54.3 and that these analyses may not have 

considered the length of the period of extended operation. The SRP-LR also states that this 

review will ensure that the aging effect under consideration will be properly addressed for the 

period of extended operation.

By letter dated August 9, 1984, the applicant requested an exemption from a portion of General 

Design Criterion 4 of Appendix A to 10 CFR Part 50 regarding the need to analyze large primary 

loop pipe ruptures as a structural design basis for Seabrook, Units 1 and 2. The staff notes that 

this exemption was granted in a letter from the NRC to the applicant dated November 22, 1985 

(ADAMS Accession No. ML011790520). The staff also notes that this exemption was granted 
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based on the LBB analysis contained in the SE attached to the November 22, 1985, letter and 

the Westinghouse Report, WCAP 10567 (proprietary). Based on this 1985 SE, the staff 

concludes that the LBB analysis conducted by the applicant is valid for the period of the original 

license for the conditions that existed at the plant at the time the analysis was conducted.

By letter dated March 17, 2004 (ADAMS Accession No. ML040850074), the applicant 

transmitted proprietary information to the NRC in support of its request for a power uprate 

license amendment. By letter dated February 28, 2005, the NRC granted the power uprate 

license amendment. The staff notes that the power uprate amendment was granted based in 

part on the staff’s evaluation of the licensee’s updated LBB analysis. This SE concluded that 

even after the effects of the power uprate were considered, the previously conducted LBB 

evaluation remained valid. Based on this 2005 safety analysis and the absence of additional 

changes to the applicant’s license which could affect the validity of the LBB analysis during the 

current licensing period, the staff concluded that the applicant’s LBB analysis remained valid for 

the current licensing period.

The staff notes that some of the components in the piping for which the leak before break 

analysis applies are constructed from cast austenitic stainless steel. This material is subject to 

thermal aging which reduces its fracture toughness. After some period of time at elevated 

temperature, the toughness of this material reaches a minimum. The staff also notes that the 

toughness of this material may or may not have reached its minimum before entry into the 

period of extended operation and that, depending on the toughness value used, the existing 

analysis may be valid for the current licensing period but not valid for the period of extended 

operation. The staff finally notes that specific statements are included in the LRA and the leak 

before break safety evaluations which indicate that the minimum toughness values expected for 

the cast austenitic stainless steel, irrespective of age, were used in the original leak before 

break analyses. The staff, therefore, finds that, from the perspective of material properties, the 

existing leak before break analyses will remain valid during the period of extended operation.

The staff notes that projections of the number of fatigue cycles which will be experienced by the 

plant are used in the fatigue crack growth calculation in the LBB analyses. The staff also notes 

that, in this case, the number of cycles used in the fatigue crack growth analysis was based on 

an anticipated plant life of 40 years. The staff further notes that plant operation beyond 40 

years could invalidate the analysis if the actual number of cycles exceeds the predicted number 

of cycles. The staff finally notes that LRA Table 4.3.1-3 contains the 40-year projection of 

cycles used in the calculation, the actual number of cycles experienced to date, and the 60-year 

cycle projection based on current cycle accumulation rate. In all cases, the number of cycles 

currently expected in 60 years is less than the number of cycles considered in the original 

fatigue crack growth analysis. The staff, therefore, finds that, from the perspective of fatigue 

crack growth calculation, the existing LBB analyses will remain valid for the period of extended 

operation.

In Section 4.7.3 of the LRA, the applicant stated that mechanical stress improvement process

(MSIP) had been performed at one of the RPV primary hot leg nozzle locations in 2009. This 

indicates that materials (Alloys 600/82/182) susceptible to primary water stress corrosion 

cracking (PWSCC) are present in the RCS primary loop piping, and PWSCC either has 

occurred or is considered highly likely to occur at this location. The staff notes that 

Section 3.6.3.III.3 of the SRP (NUREG 0800, Revision 1) states that in an LBB evaluation, the 

applicant must demonstrate that “PWSCC is not a potential source of pipe rupture.” The staff 

also notes that SRP Section 3.6.3.III.7 states that “other regulatory guidance on LBB specifies 
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that two mitigation methods are needed to address materials susceptible to an active stress 

corrosion cracking degradation mechanism.”

Given that materials susceptible to PWSCC exist in the RCS primary loop piping, that there is a 

history of PWSCC in these materials, and that it appears that not all of the susceptible materials 

have been mitigated, it was not clear to the staff that the use of LBB analyses during the period 

of extended operation is consistent with NRC guidance on the subject. To resolve these issues, 

the staff issued RAI 4.7.3-1 by letter dated December 14, 2010. This RAI asked that the 

applicant: 

• specifically identify the location of all materials which are susceptible to PWSCC in the 

piping systems covered by LBB analyses

• describe the inspection program covering these susceptible materials including 

inspections which monitor the growth of known indications

• describe in detail the results of these inspections including details on any known 

indications

• describe mitigation techniques that have been applied to these susceptible materials

• do one of the following:

– demonstrate how the LBB analyses are consistent with Section III.3 of Part 3.6.3 

of the SRP, that “PWSCC is not a potential source of pipe rupture” or 

Section III.7 of Part 3.6.3 of the Standard Review Plan, that “two mitigation 

methods are needed to address materials susceptible to an active stress 

corrosion cracking degradation mechanism”

– describe how activities described above provide reasonable assurance that an 

LBB analysis, which considers the possibility of PWSCC is bounded by the 

existing LBB analysis

– provide additional calculations that, considering the potential for PWSCC, 

demonstrate that the principles of LBB analyses are satisfied

In its response dated January 13, 2011, the applicant stated the following: 

• LBB analyses are applicable only to reactor coolant loop piping. 

• The inspection program for materials susceptible to PWSCC is documented in the 

Seabrook RCS Materials Degradation Management Reference Manual, which adheres 

to the guidelines documented in EPRI MRP-139.

• During refueling outage OR013 (fall 2009), all eight RPV nozzle butt welds were 

volumetrically inspected in accordance with MRP-139. 

• During this inspection, a flaw indication connected to the inner diameter of the nozzle 

was identified on the RPV loop 158 degree hot leg nozzle. 

• An MSIP repair was performed on this nozzle.

• As part of the MSIP repair, Westinghouse reviewed its impact on the LBB analyses for 

Seabrook, which is documented in WCAP-10567, “Technical Bases for Eliminating 

Large Primary Loop Pipe Rupture as the Structural Design Basis for Seabrook Units 1 

and 2, June 1984.”
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• As a result of that evaluation, the applicant concluded that the original LBB analysis 

remained valid.

The staff finds the applicant’s response to this RAI acceptable for the 158 degree hot leg nozzle 

because the flaw on the 158 degree hot leg nozzle was mitigated by MSIP and the leak before 

break analysis has been reevaluated based on the mitigation. This is in accordance with staff 

guidance on the subject. The staff also finds the applicant’s response to this RAI acceptable for 

the nozzles which have not been mitigated. This acceptance is based on two criteria. First, in 

“User Need Request On Development of a Probabilistic Method for Evaluating the Probability of 

Leak-Before-Break of Nickel Based Alloys Exposed to Primary Water Environments,” 

(ML102140300), the staff states that “because of the high level of conservatism used in the 

traditional approach for LBB analysis, the staff is satisfied in the short term that adequate 

structural margins exist in all welds approved for LBB, even if PWSCC were occurring. The 

staff continues to gather and assess information to validate the continued existence of adequate 

margins.” Second the staff notes that the inspection frequency for welds associated with leak 

before break contained in MRP-139 (and now ASME Code Case N77-1) is designed to be 

sufficient to detect cracking prior to rupture. The staff’s concern described in RAI 4.7.3-1 is 

resolved.

The staff finds the applicant has demonstrated that, pursuant to 10 CFR 54.21(c)(1)(i), the 

applicant’s LBB analyses for RCS primary loop pipe remain valid for the period of extended 

operation. This finding is based on the fact that the inputs for the two issues in the analyses, 

materials properties for the CASS and fatigue cycles used in the fatigue crack growth 

calculations, which were specifically based on the plant’s original 40-year license were 

sufficiently conservative that the materials properties and the fatigue cycles bound those for the 

period of extended operation. Additionally, the applicant was able to demonstrate that the LBB 

analyses remain valid despite the existence of PWSCC susceptible material in LBB piping 

because the LBB analyses and other AMPs associated with PWSCC aging management (e.g., 

XI.M1, ASME ISI and XI.M11, Nickel Alloy Nozzles and Penetrations) are consistent with NRC 

guidance on the subject and provide appropriate aging management of the PWSCC susceptible 

material.

4.7.3.3 UFSAR Supplement

LRA Section A.2.4.5.2 provides the UFSAR supplement summarizing the LBB analyses of RCS 

primary loop piping. The staff reviewed LRA Section A.2.4.5.2 consistent with SRP-LR 

Section 4.7.2.2, which states that the summary description of the evaluation of TLAAs for the 

period of extended operation in the FSAR supplement is sufficient to demonstrate the basis for 

the applicant’s assertion that 10 CFR 54.21(c)(1)(i) has been met.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address LBB analyses of RCS primary loop 

piping, as required by 10 CFR 54.21(d).

4.7.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration that, pursuant to 10 CFR 54.21(c)(1)(i), the LBB analyses of RCS primary loop 

piping remain valid for the period of extended operation. The staff also concludes that the 
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FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.7.4 High-Energy Line Break Postulation Based on Cumulative Usage Factor

4.7.4.1 Summary of Technical Information in the Application

LRA Section 4.7.4 describes the applicant’s TLAA for the CUF analyses for ASME Code 

Class 1 HELB locations. The applicant stated that its HELB analysis used a screening criterion 

of CUF greater than 0.1 to identify areas of investigation. The applicant indicated that UFSAR 

Section 3.6(B).2.1(a) eliminated locations in each piping run or branch run from further 

consideration as HELB locations on the basis that the CUF was less than 0.1 according to 

NUREG-0800, Revisions 1, "Standard Review Plan for the Review of Safety Analysis Reports 

for Nuclear Power Plants” Branch Technical Position MEB 3-1, "Postulated Rupture Locations in 

Fluid System Piping Inside And Outside Containment." The applicant also stated that its revised 

stress analysis permitted omission of the surge-line intermediate breaks based on CUF and that 

an LBB analysis eliminated large breaks in the main reactor coolant loops. The applicant 

concluded that the scope of the TLAA for HELB locations was limited to ASME Code Class 1 

piping connected to the RCS from the primary coolant loops to the ASME Code Class 1 or 

Class 2 piping interface. The applicant stated that the applicable loading cycles projected for 

the 60-year period are bounded by the original design cycles.

The applicant dispositioned the TLAA for the CUF analyses of Class 1 HELB locations in 

accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of 

extended operation.

4.7.4.2 Staff Evaluation

The staff reviewed LRA Section 4.7.4 and the TLAA for CUF analyses of ASME Code Class 1 

HELB locations to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses remain valid for 

the period of extended operation. The staff reviewed this TLAA and the corresponding 

disposition by the applicant, consistent with SRP-LR Section 4.7.3.1.1. The SRP-LR states that 

the staff may accept the applicant’s basis if the conditions and assumptions used in the analysis 

already address the relevant aging effects for the period of extended operation and the 

acceptance criteria provide assurance that the intended function(s) is maintained.

The staff reviewed UFSAR Section 3.6(B) and noted that it discussed eight primary reactor 

coolant loop locations that were approved in accordance with the applicant’s LBB analysis. The 

staff noted that the LBB analysis permits an applicant to remove dynamic effect considerations 

from the scope of its large pipe LOCA analysis. The staff grants the use of an LBB analysis for 

the piping locations in compliance with the requirements in 10 CFR Part 50, Appendix A, 

GDC 4, “Dynamic Effects.”

The staff’s review of LRA Section 4.7.4 indicated that the applicant did not identify the ASME 

Code Class 1 RCPB locations in UFSAR Section 3.6(B) that are within the scope of the 

applicant’s LBB analysis and the piping locations that are within the scope of the applicant’s 

HELB CUF analyses. The staff also noted that LRA Section 4.7.4 dispositioned the TLAA in 

accordance with 10 CFR 54.21(c)(1)(i) without identifying the current CUF values or the design 

basis transients in LRA Table 4.3.1-2 that are applicable to the HELB locations. As a result, the 

staff could not determine if the disposition, in accordance with 10 CFR 54.21(c)(1)(i), is 
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appropriate for the piping locations that are supported by the design transient projections in LRA 

Table 4.3.1-3.

By letter dated January 5, 2011, the staff issued RAI 4.7.4-1, requesting that the applicant:

• identify which ASME Code Class 1 piping locations discussed in UFSAR Section 3.6(B) 

are within the scope of the LBB analysis and LRA Section 4.7.3

• identify the ASME Code Class 1 piping locations discussed in UFSAR Section 3.6(B) 

that are within the scope of the CUF analyses discussed in LRA Section 4.7.4

• clarify whether the current design basis uses the LBB analysis to replace any of the 

original CUF analyses for HELB piping locations

• provide the CUF values and the design basis transients applicable to each HELB piping 

location within the scope of LRA Section 4.7.4

• provide the design cycle limits and 60-year projected cycle bases for the applicable 

transients, if the projections are included in LRA Table 4.3.1-3

In its response dated February 3, 2011, the applicant stated that all eight primary reactor 

coolant loop locations discussed in UFSAR Section 3.6(B) are the postulated break locations 

established by Westinghouse, as documented in report WCAP-8082. The applicant also stated 

that WCAP-10567 identified that the six safe-end welds enveloped the intermediate welds. 

Therefore, the applicant stated that all primary loop piping welds are within the scope of the LBB 

analysis and LRA Section 4.7.3. As a result, the applicant clarified that all intermediate Class 1 

piping locations, with the exception of the primary loop locations eliminated by the LBB analysis 

in Section 4.7.3, were within the scope of HELB break postulation elimination on the basis of 

CUF. The applicant clarified that the current design basis does not use LBB analysis to replace 

any of the original CUF analyses for HELB piping locations.

The applicant also confirmed that there are 11 ASME Code Class 1 piping locations discussed 

in UFSAR Section 3.6(B) that are within the scope of the CUF analyses discussed in LRA 

Section 4.7.4 for which it performed a break elimination evaluation. The applicant provided the 

results from this evaluation as part of its response dated February 3, 2011. The applicant 

confirmed that the design basis transients shown in LRA Table 4.3.1-2 and the design cycle 

limits with 60-year projected cycles for the applicable transients, provided in LRA Table 4.3.1-3, 

are applicable for these HELB CUF evaluations. The staff noted that the highest design basis 

CUF value for the HELB locations was 0.085, and the current design basis CUF values for the 

HELB locations are all less than the design limit of 0.1.Consistent with SRP-LR 

Section 4.7.3.1.1, the staff compared the design basis cycle limits for all design transients listed 

in LRA Table 4.3.1-2 to their respective 60-year cycle projections, documented in LRA 

Table 4.3.1-3 (as amended by letter dated February 3, 2011). The staff’s review and evaluation 

of the applicant’s 60-year projections are documented in SER Section 4.3.1.2, which determined 

that the applicant provided an acceptable basis for projecting the number of cycles for the 

plant’s design basis transients through 60 years of plant operation.

The staff noted that the 60-year projections for all design transients in LRA Table 4.3.1-3 are 

less than or equal to the design limit for these transients in LRA Table 4.3.1-2, which were the 

cycle inputs to the applicant’s HELB CUF calculations. Thus, the staff confirmed that the 

number of cycles projected to occur through 60 years of operation is bounded by the number of 

cycles that were analyzed for in the applicant’s HELB CUF calculations.
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The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses for the HELB postulation based on CUF remain valid for the period of extended 

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the 

applicant demonstrated that the current HELB CUF analyses used conditions and assumptions 

that address the cumulative fatigue damage for the period of extended operation. 

4.7.4.3 UFSAR Supplement

LRA Section A.2.4.5.3 provides the UFSAR supplement summarizing the TLAA for the HELB 

postulation based on CUF. The staff reviewed LRA Section A.2.4.5.3, consistent with SRP-LR 

Section 4.7.3.2, to verify that it contains information that the TLAA has been dispositioned for 

the period of extended operation.

Based on its review of the UFSAR supplement, and the applicant’s response dated February 3, 

2011, with acceptable resolution of the issues raised in RAI 4.7.4-1, the staff finds they meet the 

acceptance criteria in SRP-LR Section 4.7.3.1.1. Additionally, the staff determined that the 

applicant provided an adequate summary description of its actions to address the TLAA for the 

HELB postulation based on CUF, as required by 10 CFR 54.21(d).

4.7.4.4 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 TLAA for the HELB postulation based 

on CUF remains valid for the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.7.5 Fuel Transfer Tube Bellows Design Cycles

4.7.5.1 Summary of Technical Information in the Application

LRA Section 4.7.5 describes the applicant’s TLAA for the evaluation of fuel transfer tube bellows 

design cycles for the period of extended operation. The LRA states that the fuel transfer tube 

assembly is comprised of a 24-in. diameter penetration sleeve penetrating through the 

containment and spent fuel building walls and three sets of expansion joints (bellows). The LRA 

also states that since this assembly performs a water-retaining intended function, the 

penetration sleeve and three bellows are within the scope of license renewal.

The LRA states that the fatigue analysis for the design of each of the three bellows is based on 

the consideration of 20 occurrences of the OBE with each having 20 seismic movement cycles. 

In order to determine if the design analyses remain valid for 60 years of operation, the applicant 

projected the number of seismic cycles likely to occur through the period of extended operation. 

The LRA further states that, as of January, 2010, the Seabrook transfer tube bellows have been 

exposed to zero (0) OBE cycles, and it projected that one (1) OBE would occur for Seabrook in 

60 years of operation.

The applicant dispositioned the fuel transfer tube bellows design cycle TLAA in accordance with 

10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended operation.
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4.7.5.2 Staff Evaluation

The staff reviewed LRA Section 4.7.5 and the fuel transfer tube bellows design cycle TLAA to 

verify, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analyses of the fuel transfer tube 

bellows remain valid for the period of extended operation.The staff reviewed the applicant’s 

TLAA and the corresponding disposition, consistent with SRP-LR Section 4.7 for dispositioning 

plant-specific TLAAs.The adequacy of the bellows as part of the fuel transfer tube assembly is 

described in UFSAR 3.8.2.5, "Structural Acceptance Criteria," which discusses the ability of the 

bellows to sustain loads imparted under test, normal, upset and faulted conditions and the ability 

of the fuel transfer tubes to remain within the prescribed design basis loading limits. In 

accordance with the review procedures in SRP-LR Section 4.7.3.1.1, the staff needed more 

information to confirm that the applicant considered all possible design basis transients in the 

fatigue analysis for the fuel transfer tube bellows. By letter dated January 21, 2011, the staff 

issued RAI 4.7.5-1. In part (1) of RAI 4.7.5-1, the staff asked the applicant to confirm that all 

considerations with regard to cyclic loads due to the number of OBE occurrences, as well as the 

other transients such as the LOCA, pressure tests, and temperature cycles for the entire fuel 

transfer assembly used in the fatigue analysis were considered for the period of extended 

operation.

The applicant responded by letter dated February 18, 2011, and confirmed that all of the 

transients were considered for the entire fuel transfer tube assembly and that the cycles will be 

monitored by the enhanced cycle counting program, which is referenced in Commitment 42. 

This includes the design limits specified in the UFSAR for OBE cycles, accident cycle, pressure 

test cycles and temperature cycles. The number of temperature cycles is counted by monitoring 

to the number of plant heatup and plant cooldown cycles and the number of pressure test cycles 

is consistent with containment pressure testing. The accident cycle is counted as a faulted 

condition as listed in LRA Table 4.3.1-3.

The LRA states that the Seabrook fuel transfer tube bellows were designed to withstand 20 

occurrences of the OBE. The UFSAR supplement also states that the fuel transfer tube bellows 

fatigue analysis is based on the consideration of 20 cycles of the OBE at 20 cycles maximum 

response (total of 400 cycles), but it further states that the design limit was five occurrences of 

10 OBE cycles (total of 50 cycles). In part (2) of RAI 4.7.5-1, the staff asked that the applicant 

verify the number of OBE cycles used for the fatigue analysis.

In its response, dated February 18, 2011, the applicant clarified that the fatigue analysis for the 

fuel transfer tube bellows design is based on 20 occurrences of the OBE at 20 cycles each. 

The overall plant design for OBE is 50 cycles (five occurrences of 10 cycles.) The plant design 

transient limit listed in LRA Table 4.3.1-3 is more limiting and, therefore, the acceptance criteria 

for the transient is monitored to a value lower than analyzed for individual components (in this 

case, the fuel transfer tube bellows).

The staff's concern in RAI 4.7.5-1 is resolved. The plant design limit for OBE of five 

occurrences of 10 cycles is conservative for the fuel transfer tube bellows, which are designed 

to 400 cycles. This conservative estimate is still in excess of the one OBE that is projected to 

occur in 60 years of operation. The staff finds this acceptable because the design transients for 

the bellows exceed the NSSS design cycles for the plant. 

The staff finds the applicant has demonstrated, pursuant to the requirements of 

10 CFR 54.21(c)(1)(i) and the acceptance criteria in SRP-LR Section 4.7.2.1, that the fatigue 

analysis for the fuel transfer tube bellows remains valid during the period of extended operation.
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4.7.5.3 UFSAR Supplement

LRA Section A.2.4.5.4 provides the UFSAR supplement summarizing the TLAA for the fuel 

transfer tube bellows design cycles. The staff reviewed LRA Section A.2.4.5.4 consistent with 

SRP-LR Section 4.7.3.2, which state that the applicant should provide a summary description of 

the fatigue evaluation of the containment vessel including the basis for determining that the 

applicant has made the demonstration required by 10 CFR 54.21(c)(1). 

Based on its review of the UFSAR supplement, the staff finds it 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 fuel transfer tube bellows design 

cycle TLAA, as required by 10 CFR 54.21(d).

4.7.5.4 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 fuel transfer tube bellows TLAA 

remains valid for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d).

4.7.6 Crane Load Cycle Limits

4.7.6.1 Polar Gantry Crane

4.7.6.1.1 Summary of Technical Information in the Application

LRA Section 4.7.6.1 states that the design specification for the 420/50-ton polar crane in the 

containment structure required that it conform to the design requirements of Crane 

Manufacturers Association of America Specification Number 70 (CMAA-70), “Specifications for 

Electric Overhead Traveling Cranes.” The applicant also states that the service requirements 

specified for the design of this crane correspond to the cyclic loading requirements of CMAA-70, 

Class A, and, therefore, it is a TLAA.

According to the LRA, the polar crane was designed for up to 100,000 load cycles per criteria of 

CMAA-70 for service Class A. The applicant estimated that the polar crane will perform 

19,440 lifts over the remaining 40 years of service, which includes 20 years of extended 

operation, with most of the lifts being less than 2,500 pounds. The LRA states that the rate is 

based on refueling outage use; therefore, the first 20 years of service life for the polar crane 

would include approximately 10,000 load cycles. Therefore, the total service life load cycles will 

be approximately 30,000.

The applicant dispositioned the polar gantry crane load cycle limit TLAA in accordance with 

10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of extended operation.

4.7.6.1.2 Staff Evaluation

The staff reviewed LRA Section 4.7.6.1 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation. The staff reviewed the applicant’s 

TLAA and the corresponding disposition, consistent with SRP-LR Section 4.7 for dispositioning 

plant-specific TLAAs.
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The staff’s review of the LRA Section 4.7.6.1 and Seabrook UFSAR Section 9.1.4.2 indicate that 

the containment polar gantry crane is designed in accordance with CMAA-70, which is 

recommended for crane design in NUREG-0612. The staff noted that, although the LRA states 

that the crane is designed to service Class A, the applicant’s UFSAR does not specifically state 

the service class for the polar gantry crane. Since the applicant’s CLB does not specify service 

class, the staff performed its review assuming no service class information was provided. The

CMAA-70, service Class A is the most conservative service class, with a design rating of up to 

100,000 cycles. According to the applicant, the estimated number of lifts is based on refueling 

outage use, which for the first 20 years of service life includes approximately 10,000 load 

cycles. The applicant has projected that for the remaining 40 years of service through the end 

of the period of extended operation, the polar crane would experience 19,440 additional lifts, 

thus the total number of load cycles over the service life will be approximately 30,000. The staff 

believes that 30,000 lifts is a conservative number of lifts that the crane will experience through 

the end of the period of extended operation and the estimate is less than the 100,000 load 

cycles allowable for a Class A crane. Therefore, the staff has determined that the polar crane 

can continue to operate and the existing fatigue analysis will remain valid for the period of 

extended operation.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the analyses for the polar crane remains valid for the period of 

extended operation because the crane is designed for more cycles than the maximum expected 

number of cycles during 60 years of operation.

4.7.6.1.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the load cycle limits of the containment polar crane in LRA Section A2.4.5.5.1. The polar crane 

is designed for more than the maximum number of load cycles for the period of extended 

operation. Based on its review of the UFSAR supplement, the staff concludes that the applicant 

provided an adequate summary description of its actions to address the crane load cycle limits.

4.7.6.1.4 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)(i), that the analysis for the polar crane TLAA 

remains valid for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d).

4.7.6.2 Cask Handling Crane

4.7.6.2.1 Summary of Technical Information in the Application

In LRA Section 4.7.6.2 the applicant states that the cask handling crane was replaced in 2008 

by a single failure-proof crane, designed to the requirements of ASME NOG-1-2004, 

NUREG-0554, and NUREG-0612. The crane is also designed to CMMA-70, “Specifications for 

Electric Overhead Traveling Cranes,” with an allowable design life cycle range of up to 100,000 

cycles.

The applicant states that, although the crane became operational in 2008, the bridge structure is 

original equipment. The applicant further states that the projected number of lifts for the cask 
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handling crane is less than 500, and the estimate is based upon the expected number of casks 

that must be handled during each cask loading campaign and the projected number of 

campaigns through the period of extended operation. The applicant allowed for double that 

number for minor lifts, or 1,000 cycles, for a total of 1,500 cycles.

The applicant dispositioned the cask handling crane load cycle limit TLAA in accordance with 

10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of extended operation.

4.7.6.2.2 Staff Evaluation

The staff reviewed LRA Section 4.7.6.2 and Seabrook UFSAR Section 9.1.4.2 to verify, 

pursuant to 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended 

operation. The staff reviewed the applicant’s TLAA and the corresponding disposition, 

consistent with SRP-LR Section 4.7 for dispositioning plant-specific TLAAs.

The staff reviewed FSAR Section 9.1.4.2 and found that the cask handling crane is designed to 

the requirements of CMAA-70, ASME NOG-1-2004, and NUREG-0554. 

The applicant based the analysis of the cask handling crane on the load cycles experienced by 

the bridge structure, since it has been in service through the entire period of plant operation. 

The applicant’s UFSAR does not specify the service class for which the cask handling crane 

was designed. The minimum number of cycles for all cranes designed to CMAA-70 is 

100,000 cycles; since no service class is specified in the CLB, it is conservative to assume 

100,000 cycles as the allowable design life cycle upper limit. The applicant stated that it 

included a conservative estimate of 1,500 lifts over 60 years, which includes 500 Cask Handling 

Crane lifts for 60 years of plant operation and an additional 1,000 cycles for minor lifts. The staff 

finds the estimate to be realistic because the cask handling crane is only used for handling 

spent fuel storage casks. Spent fuel storage casks are normally lifted infrequently, including

when they are ready to be transported outside the fuel building. The estimate of 1,500 cycles 

over 60 years is significantly less than the 100,000 cycles for which the crane is designed. 

Therefore, the staff has determined that the existing fatigue analysis for the cask handling crane 

will remain valid for the period of extended operation.

Based on its review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the analyses for the cask handling crane remain valid for the period 

of extended operation because the crane is designed for more cycles than the maximum 

expected cycles for 60 years of operation.

4.7.6.2.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the load cycle limits of the cask handling crane in LRA Section A2.4.5.5.2. Based on its review 

of the UFSAR supplement, the staff concludes that the applicant provided an adequate 

summary description of its actions to address the crane load cycle limits.

4.7.6.2.4 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 cask handling crane TLAA remains 

valid for the period of extended operation. The staff also concludes the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d).
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4.7.7 Service Level I Coatings Qualification

4.7.7.1 Summary of Technical Information in the Application

LRA Section 4.7.7 describes the applicant’s TLAA for qualification of Service Level I coatings. 

The applicant stated that, during a design basis accident (DBA), the emergency core cooling 

system (ECCS) at Seabrook could potentially be negatively impacted by detached coating 

debris contributing to blockage of the ECCS suction strainers. The applicant assumes that the 

radiation exposure used in the original DBA testing of the Service Level 1 coatings was intended 

to bound 40 years of operation. Thus, the applicant has determined that continued performance 

of Service Level 1 coatings is a TLAA.

The applicant dispositioned the Service Level I coatings qualification 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. The applicant indicated that the Seabrook 

Service Level I coatings are managed by the Protective Coatings Monitoring and Maintenance 

AMP.

4.7.7.2 Staff Evaluation

The staff reviewed LRA Section 4.7.7 and the Service Level I coatings qualification 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 SRP-LR Section 4.7 for dispositioning 

plant-specific TLAAs.

In the LRA, the applicant stated that the operability of the ECCS suction strainers in providing 

long-term cooling is a requirement per 10 CFR 50.46(b)(5). The applicant provided a 

comprehensive list of coated surfaces inside containment in UFSAR Table 6.1(B)-2 that have 

the potential of being exposed to a post-LOCA environment. It was indicated in the LRA that 

the qualification of the coatings to withstand the effects of radiation and the DBA conditions 

assures that the coatings will remain intact and will not contribute to clogging of ECCS strainers 

beyond analyzed limits. The applicant stated that the Protective Coatings Monitoring and 

Maintenance AMP manages cracking, blistering, flaking, peeling, and delamination of the 

Service Level 1 coatings, consistent with the guidelines of Regulatory Position C4 of NRC 

RG 1.54, Revision 1, “Quality Assurance Requirements for Protective Coatings Applied to 

Water-Cooled Nuclear Power Plants,” as described in NUREG 1801, Revision 1. In addition, 

the applicant stated that the coatings used in Service Level 1 applications are qualified and 

applied in accordance with the requirements of the following documents: 

• NRC RG 1.54, ANSI N101.4-1972, “Quality Assurance for Protective Coatings Applied to 

Nuclear Facilities” 

• ANSI N101.2-1972, “Protective Coatings (Paints) for Light Water Nuclear Containment 

Facilities” 

• ANSI N512-1974, “Protective Coatings (Paints) for the Nuclear Industry”

The staff finds that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging on the intended functions of the applicant’s TLAA for qualification of Service 

Level I coatings will be adequately managed for the period of extended operation because the 

applicant will use its Protective Coating Monitoring and Maintenance Program to manage 
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coating degradation effects during the period of extended operation. Additionally, the staff finds 

that the TLAA meets the acceptance criteria in SRP-LR Section 4.7.3.1.3 because the applicant 

will use the Protective Coating Monitoring and Maintenance AMP, which the staff determined in 

SER Section 3.0.3.2.20 to be consistent with GALL AMP XI.S8.

4.7.7.3 FSAR Supplement

LRA Section A.2.4.5.6 provides the FSAR supplement summarizing the Service Level I 

qualification TLAA. The staff reviewed the LRA Section A.2.4.5.6 consistent with SRP-LR 

Section 4.7.3.2, which states that the applicant must provide information that includes a 

summary description of the evaluation of each TLAA. The SRP-LR also states that each such 

summary description is reviewed to verify that it is appropriate such that later changes can be 

controlled by 10 CFR 50.59. The SRP-LR further states that the description should contain 

information that the TLAAs have been dispositioned for the period of extended operation.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.3.2. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address qualification of Service Level I coatings, 

as required by 10 CFR 54.21(d).

4.7.7.4 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)(iii), that the effects of aging on the intended 

functions of Service Level I coatings will be adequately managed for the period of extended 

operation. The staff also concludes that the FSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.8 Absence of a TLAA for Reactor Coolant Pump: Code Case N-481

4.7.8.1 Summary of Technical Information in the Application

LRA Section 4.7.8 describes the absence of a TLAA for RCPs when using ASME Code Case 

N-481, “Alternative Examination Requirements for Cast Austenitic Pump Casings.” ASME 

Boiler and Pressure Vessel Code, Section XI, specifies that a volumetric inspection of the RCP 

casing welds and a visual inspection of pump casing internal surfaces be performed on a RCP 

within each 10-year inspection period. The applicant stated that, since these inspections are 

difficult to perform, ASME Code Case N-481 was developed to allow for the replacement of 

volumetric examinations with fracture mechanics-based evaluations, supplemented by specific 

visual inspections. The applicant also stated that its pump casings are cast in one piece, 

eliminating welds in the casing; in addition, support feet are cast integral with the casing, 

eliminating any weld region. The applicant further stated that, per UFSAR Section 5.4.1.4, the 

RCPs can be inspected in accordance with the ASME Code, Section XI, for ISI of nuclear 

RCSs. The applicant concluded that, since the pump casings were cast in one piece and do not 

contain welds, ASME Code Case N-481 is not applicable to the RCPs.

4.7.8.2 Staff Evaluation

The staff reviewed LRA Section 4.7.8 to verify, pursuant to 10 CFR 54.3, that a TLAA of the 

ASME Code Case N-481 for RCPs is not applicable. The staff reviewed the applicant’s 

evaluation and conclusion, consistent with SRP-LR Section 4.1.3, which states that the review 
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verifies that the selected analyses do not meet at least one of the six criteria of a TLAA as 

defined in 10 CFR 54.3.

The staff reviewed the applicable ASME Code Section XI requirements, the alternative 

inspection requirements of ASME Code Case N-481, and the applicant’s UFSAR. The staff 

noted that Code Case N-481 was developed to provide alternative examination requirements of 

cast austenitic pump casings because the weld inspections that are required by ASME Code 

Section XI would involve a large amount of time, resources, and radiation exposure. The staff 

reviewed UFSAR Figure 5.4-17, “Reactor Coolant Pump Supports,” and UFSAR 

Section 5.4.1.4, “Tests and Inspections,” for the RCPs and confirmed that the pump casings are 

cast in one piece. The staff finds that since the pump casings are cast in one piece, this 

eliminates welds in the casings, and since the support feet are cast integral with the casing, this 

eliminates a weld region. UFSAR Section 5.4.1.4 also states that the design of the RCPs 

enables the disassembly and removal of the pump internals for visual access to the internal 

surface of the pump casing. Based on its review, the staff concluded that the applicant can 

inspect the internal surface of the RCPs in accordance with the ASME Code Section XI for ISI of 

RCPs without invoking Code Case N-481.

Based on its review, the staff finds the applicant’s conclusion, that there is no specific TLAA 

associated with ASME Code Case N-481, acceptable because the applicant demonstrated that 

its CLB does not contain analyses related to the Code Case N-481 for the RCP casings.

Therefore, ASME Code Case N-481 is not a TLAA, in accordance with Criterion 6 of 

10 CFR 54.3(a).

4.7.8.3 UFSAR Supplement

On the basis of its review, the staff finds that an UFSAR supplement is not required because 

this TLAA is not applicable, as described above.

4.7.8.4 Conclusion

On the basis of its review, the staff concludes that that the applicant provided an acceptable 

demonstration that ASME Code Case N-481 is not applicable to its RCPs and, therefore, is not 

a TLAA. The staff also concludes that an UFSAR supplement is not required.

4.7.9 Canopy Seal Clamp Assemblies

4.7.9.1 Summary of Technical Information in the Application

LRA Section 4.7.9 describes the fatigue analyses for the canopy seal clamp assemblies. The 

application describes that the original fatigue analyses considered the forces that would be 

applied to the center head adapter, which maximized the moments on the J-grove weld and the 

moment along the length of the adapter. The applicant stated that the design fatigue analyses 

for the canopy seal clamps are based on the consideration of 400 cycles consisting of 20 

occurrences of the OBE, each occurrence having 20 cycles of maximum response. The 

applicant projected the number of seismic cycles for 60 years in order to determine if the design 

analyses remain valid for 60 years of operation. The applicant stated that, as of January 2010, 

the canopy seal clamps have been exposed to zero OBE cycles. The applicant projected that 

only one OBE with 20 seismic cycles would occur in 60 years of operation and, therefore, the 

fatigue analyses remain valid for the period of extended operation since it is conservatively 

bounded by the design values. The applicant concluded that the canopy seal clamp assemblies 
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are shown to be acceptable for the period of extended operation, in accordance with the TLAA 

acceptance criterion in 10 CFR 54.21(c)(1)(i).

4.7.9.2 Staff Evaluation

The staff reviewed LRA Section 4.7.9 and the canopy seal clamp assemblies TLAA to verify, 

pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analyses of the canopy seal clamp 

assemblies remain valid for the period of extended operation. The staff reviewed the applicant’s 

TLAA and the corresponding disposition, consistent with SRP-LR Section 4.7 for dispositioning 

plant-specific TLAAs.

The staff noted that fatigue analyses were performed for the canopy seal clamp assemblies, but 

it was not clear if the analyses referred to fatigue crack initiation or fatigue flaw growth. If these 

were fatigue flaw growth analyses, detailed information regarding the initial flaw size, loading 

cycle assumption, and critical flaw size are needed for the staff to evaluate the applicant’s TLAA 

disposition. In addition, the staff reviewed LRA Sections 3.1 and 4.7.9 and noted that the aging 

effect of the canopy seal clamp assemblies was not identified. The staff noted that the design 

fatigue analyses were based on the consideration of 400 cycles (20 occurrences of the OBE 

and each OBE has 20 cycles of maximum response); however, LRA Table 4.3.1-3 projects only 

one occurrence of an OBE with 10 cycles during its 60-year operation.

By letter dated January 5, 2011, the staff issued RAI 4.7.9-1, requesting that the applicant:

• clarify the aging effect of the canopy seal clamp assemblies in LRA Section 4.7.9 and 

justify that the TLAA disposition is appropriate for the aging effect of the canopy seal 

clamp assemblies

• clarify whether the fatigue analyses are crack initiation analyses or flaw growth analyses

• clarify and justify the use of a different number of cycles during an OBE earthquake in 

different sections of the LRA

In its response to RAI 4.7.9-1, Request 1, dated February 3, 2011, the applicant stated that 

there is no specific aging effect identified for the canopy seal clamp assemblies. However, 

there is an aging effect identified for the head adapters since fatigue analyses were developed 

using design transients over the current operating term. The applicant stated that it 

conservatively classified the analyses associated with the head adapters as a TLAA to verify 

that the assumptions of the analyzed design transients remain bounded for the period of 

extended operation.

LRA Section 4.7.9, as amended by letter dated February 3, 2011, states that the canopy seal 

clamp assemblies were designed for a 40-year design life and the analyses were performed for 

the head adapters. The staff reviewed LRA Table 3.1.2-2, “Reactor Vessel,” and could not 

identify an AMR line item for the head adapters that addresses this aging effect. The staff also 

noted that the applicant has not identified the relationship between the canopy seal clamp 

assemblies and the head adapters or explained how the head adapter’s 60-year evaluation 

supports the canopy seal clamp assemblies design life basis for meeting the stress limits. 

Furthermore, the staff noted that LRA Section A.2.4.5.7 was not revised to reflect the revisions 

to LRA Section 4.7.9, as a result of RAI 4.7.9-1. By letter dated March 30, 2011, the staff 

issued followup RAI 4.7.9-1b, requesting that the applicant:
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• identify the AMR line item, in the LRA Section 3, that is applicable to the head adapters

as required by 10 CFR 54.21(a)(1) or justify that an AMR line item is not needed for the 

head adapters

• explain how the head adapter’s 60-year TLAA evaluation supports the canopy seal 

clamp assemblies design life basis for meeting the stress limits

• provide an updated UFSAR supplement section in LRA Appendix A commensurate with 

the changes in LRA Section 4.7.9

In its response to RAI 4.7.9-1b, Request 1, dated April 22, 2011, the applicant stated that the 

head adapters are commonly referred to as the canopy seal pressure housing within its 

documents and are reflected in AMR Table 3.1.2-2. The staff reviewed LRA Table 3.1.2-2 and 

confirmed that the applicant has included canopy seal pressure housing with an aging effect of 

cumulative fatigue damage and credited this TLAA for managing this aging effect.

In its response to RAI 4.7.9-1b, Request 2, dated April 22, 2011, the applicant stated that it had 

not provided an adequate response to RAI 4.7.9-1 in its letter dated February 3, 2011. LRA 

Section 4.7.9, as amended by letter dated April 22, 2011, now states that the canopy seal 

pressure housings have been exposed to zero OBE cycles, and the projected number of OBE 

cycles will remain below the seismic movement cycles used in the analyses. LRA Table 4.1-1 

was also amended to clarify that LRA Section 4.7.9 applies to canopy seal pressure housings.

In its response to RAI 4.7.9-1b, Request 3, dated April 22, 2011, the applicant provided an 

amendment to LRA Section A.2.4.5.7 commensurate with the changes in LRA Section 4.7.9.

Based on its review, the staff finds the applicant’s response to RAI 4.7.9-1b acceptable because 

LRA Table 3.1.2-2 includes an AMR line to address the aging effect associated with canopy 

seal pressure housings as required by 10 CFR 54.21(a)(1), and LRA Sections 4.7.9 and 

A.2.4.5.7 have been revised to address canopy seal pressure housings. The staff’s concerns 

described in RAI 4.7.9-1b, Requests 1, 2, and 3, are resolved.In its response to RAI 4.7.9-1, 

Requests 2 and 3, dated February 3, 2011, the applicant clarified that the fatigue analyses for 

the head adapters, in LRA Section 4.7.9, refer to fatigue crack initiation analyses. The applicant 

also stated that the head adapters design fatigue analyses assumed 400 OBE cycles. The 

applicant stated that an OBE is one of the reactor coolant design transients, and the associated 

NSSS design limit is 50 cycles (five occurrences of 10 cycles) as shown in UFSAR 

Table 3.9(N)-1. The staff noted that both the projected 20 cycles (one OBE occurrence with 20 

seismic cycles) in LRA Section 4.7.9, or the 50 cycles of the NSSS design limit in UFSAR 

Table 3.9(N)-1 are well below the head adapters’ design limit of 400 cycles.

Based on its review, the staff finds the applicant’s response to RAI 4.7.9-1, Requests 1, 2, and 

3, acceptable for the following reasons:

• The applicant clarified that the fatigue analyses identified in LRA Section 4.7.9 are 

fatigue crack initiation analyses for the canopy seal pressure housing.

• There is a significant margin between the projected number of seismic cycles and the

head adapters’ design limit of 400 cycles. 

The staff’s concern described in RAI 4.7.9-1, Requests 1, 2, and 3, is resolved.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analyses for the canopy seal pressure housings remain valid for the period of extended 
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operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because, for 

the canopy seal pressure housings head adaptor, the projected number of 60-year OBE cycles 

is far less than the design limit.

4.7.9.3 UFSAR Supplement

LRA Section A.2.4.5.7 provides the UFSAR supplement summarizing the canopy seal clamp 

assemblies fatigue analyses. The staff reviewed LRA Section A.2.4.5.7, consistent with 

SRP-LR Section 4.7.2.3, to verify that it contains information that the TLAA has been 

dispositioned for the period of extended operation.

In its response to RAI 4.7.9-1b, Request 3, dated April 22, 2011, the applicant amended UFSAR 

supplement Section A.2.4.5.7 to specify that the scope of the UFSAR supplement summary 

description for the canopy seal clamp assembly fatigue analyses included the canopy seal 

pressure housings. The staff finds that this change is acceptable because it consistent with the 

changes that were made to the TLAA for the canopy seal assemblies in the RAI response letter 

of April 22, 2011, and the UFSAR supplement for this TLAA.

RAI 4.7.9-1b, Request 3, is resolved with respect to UFSAR supplement A.2.4.5.7.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address the canopy seal clamp assemblies 

analyses, as required by 10 CFR 54.21(d).

4.7.9.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to10 CFR 54.21(c)(1)(i), that the analyses for the canopy seal clamp 

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).

4.7.10 Hydrogen Analyzer

4.7.10.1 Summary of Technical Information in the Application

LRA Section 4.7.10 describes the radiation dose analysis for the hydrogen analyzer. The 

applicant stated that the UFSAR addresses accumulated radiation dose limits for a 40-year 

operating period. In addition, the post-accident hydrogen analyzer must perform its safety 

function following a LOCA, and the resulting excessive radiation exposure could jeopardize its

ability to perform this safety function. UFSAR Table 6.2-84 defines the hydrogen analyzer 

design parameter and maximum radiation dose limit of 5x106 rads for 40 years of normal 

operation.

Based on the one-year predicted integrated dose, the applicant stated that the maximum 

predicted 60-year dose for the hydrogen analyzer is 4.32x105 rads. The applicant concluded 

that this is an order of magnitude less than the specified UFSAR radiation dose limit; therefore, 

the hydrogen analyzers are shown to be acceptable for the period of extended operation, in 

accordance with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(i).
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4.7.10.2 Staff Evaluation

The staff reviewed LRA Section 4.7.10 and the hydrogen analyzer radiation dose 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 and the corresponding disposition, 

consistent with SRP-LR Section 4.7 for dispositioning plant-specific TLAAs.

The staff reviewed LRA Section 2.3.2.1 and LRA Table 3.2.2-1 and noted that the hydrogen 

analyzer is not included in the AMR of license renewal. The staff also noted that UFSAR 

Section 6.2.5 states that the hydrogen analyzer is a safety-related component. By letter dated 

January 5, 2011, the staff issued RAI 4.7.10-1, asking the applicant to identify the aging effect 

associated with the hydrogen analyzer and justify that the TLAA and its disposition are 

appropriate for the associated aging effect. The staff also asked that the applicant justify that 

the AMR results provided in LRA Table 3.2.2-1 adequately address the aging effect for the 

hydrogen analyzer.

In its response dated February 3, 2011, the applicant stated that the hydrogen analyzer was 

included as a TLAA because the radiation dose limits of the analyzer was based on a 40-year 

period, as described in UFSAR Table 6.2-84. The applicant also stated that the hydrogen 

analyzer is an active component within the scope of license renewal, and, in accordance with 

10 CFR 54.21(a)(1)(i), active components do not require AMR. The staff reviewed the 

combustible gas control system license renewal boundary drawing PID-1-CGC-LR20612 and 

confirmed that the hydrogen analyzer panels and associated piping components are within the 

scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 4.7.10-1 acceptable because 

the staff confirmed that the hydrogen analyzer is within the scope of license renewal and the 

hydrogen analyzer is not subject to an aging management review since it is an active 

component in accordance with 10 CFR 54.21(a)(1)(i). The staff’s concern described in 

RAI 4.7.10-1 is resolved.

The staff reviewed UFSAR Section 6.2.5, “Combustible Gas Control System,” and UFSAR 

Table 6.2-84, “Hydrogen Gas Analyzer Design Parameters.” The staff noted that UFSAR 

Table 6.2-84 lists the 40-year radiation dose limit for the hydrogen analyzer as 5x106 rads. LRA 

Section 4.7.10 states that the hydrogen analyzer has an annual dose rate of 7.2x103 rads, 

which is equivalent to a 60-year dose of 4.32x105 rads. The staff noted that, as discussed in 

UFSAR Section 6.2.5.2, the hydrogen analyzer is located outside the containment, where the 

radiation dose is less than that inside the containment. The staff noted that this 60-year dose is 

bounded by the current UFSAR limit (5x106 rads).

The staff finds that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analysis for the radiation dose for the hydrogen analyzer remains valid for the period of 

extended operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 

because the 60-year radiation dose for the hydrogen analyzer is less than the radiation dose 

limit, and there is significant margin between the 60-year radiation dose and the radiation dose 

limit.

4.7.10.3 UFSAR Supplement

LRA Section A.2.4.5.8 provides the UFSAR supplement summarizing the hydrogen analyzer 

dose analysis. The staff reviewed LRA Section A.2.4.5.8 consistent with SRP-LR 

Section 4.7.2.2, which states that the description should contain information associated with the 
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TLAA regarding the basis for determining that the applicant has made the demonstration 

required by 10 CFR 54.21(c)(1).

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address the dose analysis for the hydrogen 

analyzer, as required by 10 CFR 54.21(d).

4.7.10.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to10 CFR 54.21(c)(1)(i), that the radiation dose analysis for the 

hydrogen analyzer remains valid for the period of extended operation. The staff also concludes

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d).

4.7.11 Mechanical Equipment Qualification

4.7.11.1 Summary of Technical Information in the Application

LRA Section 4.7.11 describes the TLAA associated with environmental qualification (EQ) of 

mechanical equipment. The applicant stated that its CLB commits to the review and evaluation 

of the EQ of mechanical equipment to demonstrate compliance with General Design Criteria 4 

of Appendix A to 10 CFR Part 50. The applicant further stated that the design basis event 

conditions during the period of extended operation will remain the same as those in the current 

license period, having already been adjusted to account for previously approved power uprate 

conditions. Therefore, the design basis event parameters—including the temperature, pressure, 

and time profiles—do not require further evaluation as TLAAs for license renewal. However, 

since a period of 40 years was used to determine the normal service radiation exposure to the 

equipment, the applicant considers mechanical equipment qualification (MEQ) a TLAA.

In order to determine if the design analyses remain valid for 60 years of operation, the applicant 

proposed to revise the calculations for MEQ prior to entering the period of extended operation 

using techniques currently used under the CLB for equipment qualification including analytical 

methods, replacement of radiation sensitive materials, or equipment replacement. The 

applicant dispositioned the MEQ 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.

4.7.11.2 Staff Evaluation

The staff reviewed LRA Section 4.7.11 and the MEQ TLAA 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. The staff reviewed the applicant’s TLAA and the corresponding disposition, 

consistent with SRP-LR Section 4.7.3.1.2, which states that the applicant shall provide a 

sufficient description of the analysis and document the results of the reanalysis to show that it is 

satisfactory for the period of extended operation.

SRP-LR Section 4.4 states that some nuclear plants have mechanical equipment that was 

qualified in accordance with the provisions of Criterion 4 of Appendix A to 10 CFR 50, and, if 

this qualified mechanical equipment requires the performance of a TLAA, it should be performed 

in accordance with the provisions of SRP-LR Section 4.7.
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The staff noted that, in UFSAR Section 3.11.2, the environmental parameters of interest are 

temperature, pressure, humidity, radiation, chemical spray, and submergence. The applicant 

stated that the effects of aging on the intended function of equipment will be adequately 

addressed for the period of extended operation. Commitment No. 45 was provided in the LRA, 

Appendix A, indicating that the MEQ files will be revised prior to the period of extended 

operation. It was not clear to the staff if the applicant has accounted for the environmental 

parameters described in UFSAR Section 3.11.2 in addition to those that were listed in the LRA. 

It is also not clear to the staff what the “time profiles” being referred to in LRA Section 4.7.11 

are. The staff noted that the applicant did not identify the 40-year radiation exposure limit, the 

projected 60-year radiation exposure limit, nor the design limit for the radiation exposure of the 

safety-related active mechanical equipment. Without this information, the staff is not able to 

evaluate the adequacy of the applicant’s disposition for this TLAA. Furthermore, it was not clear

if the applicant will revise all or only selected MEQ files, and it was not clear what type of 

information will be re-evaluated and revised when Commitment No. 45 is implemented.

By letter dated January 5, 2011, the staff issued RAI 4.7.11-1, Request 1, asking the applicant 

to clarify that all environmental parameters identified in UFSAR 3.11.2 have been evaluated and 

accounted for during the period of extended operation and to clarify what the “time profiles” 

being referred to in LRA Section 4.7.11 are.

In its response dated February 3, 2011, the applicant stated that only the normal service 

radiation exposure was subject to a TLAA. The applicant also stated that none of the other 

environmental parameters were based on a 40-year interval. The applicant stated that MEQ 

does not have time-based thermal aging requirements, and the time profiles referenced in the 

LRA Section 4.7.11 refer to design basis event conditions that do not change due to license 

renewal and, therefore, do not need to be re-evaluated as a TLAA.

Based on its review, the staff found the applicant’s response to RAI 4.7.11-1, Request 1, 

acceptable because the applicant clarified that only the normal service radiation exposure was 

based on a 40-year interval in the MEQ. Additionally, Criterion 3 of 10 CFR 54.3 states that, in 

order to be considered a TLAA, the original analyses should involve a time-limiting assumption. 

The staff’s concern described in RAI 4.7.11-1, Request 1, is resolved.

By letter dated January 5, 2011, the staff issued RAI 4.7.11-1, Requests 2, 3, and 4, asking the 

applicant to identify the 40-year radiation exposure limit, the projected 60-year radiation 

exposure limit, and the design limit for the radiation exposure of the safety-related active 

mechanical equipment. The staff also asked the applicant to ensure that the radiation exposure 

has been appropriately accounted for in the TLAA. The staff also requested that the applicant 

explain how LRA Section 4.7.11 and Commitment No. 45 satisfy its disposition in accordance 

with 10 CFR54.21(c)(1)(ii) and amend Commitment No. 45 to delineate the information to be 

re-evaluated and revised.

In its response dated February 3, 2011, the applicant stated that it has a calculation of EQ zone 

total-integrated radiation dose design values for a 60-year plant life, which provides values for 

various environmental zones. The applicant also determined that the 60-year dose limits are 

bounded by the existing equipment design dose limits. The staff noted that there is not 

sufficient information to determine if this TLAA of normal service radiation exposure in MEQ has 

been appropriately dispositioned. The staff noted that LRA Section 4.7.11, as amended by 

letter dated February 3, 2011, does not discuss the detail regarding the calculated dose limits 

and equipment design dose limits for normal service radiation exposure.
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The applicant also stated in the response that the evaluation of normal radiation exposure for 

MEQ has been completed and is available in a license renewal technical report. The applicant 

stated that, as listed in Table A.3 in LRA Appendix A, Commitment No. 45 will track the formal 

revision of the MEQ files prior to the period of extended operation. The applicant explained that 

LRA 4.7.11 already defines the scope of the TLAA as being limited to normal service radiation 

exposure, and Commitment No. 45 is applicable to all MEQ files. The applicant also revised 

LRA Section 4.7.11, which states that the effects of aging on the intended functions of 

equipment listed in the MEQ have been projected to be bounded by existing equipment design 

limits for the period of extended operation. Furthermore, the applicant revised LRA 

Section A.2.4.5.9 to state that the effects of aging have been projected to be bounded by 

existing equipment design limits, in accordance with 10 CFR 54.21(c)(1)(ii), for the period of 

extended operation.

The staff finds the applicant’s disposition, in accordance with 10 CFR 54.21(c)(1)(ii), not 

appropriate because the existing analyses on equipment design dose limits has not been 

revised and extended. The applicant demonstrated that the existing analyses on equipment 

design dose limits are bounding for the projected 60-year doses for all zones. The staff noted 

that this demonstration of the normal service radiation exposure is consistent with a disposition 

in accordance with 10 CFR 54.21(c)(1)(i). However, SRP-LR Section 4.7.3.1.1 states that, for 

the disposition of 10 CFR 54.21(c)(1)(i), the existing analyses should be shown to be bounding

for the period of extended operation. Furthermore, the applicant did not amend Commitment 

No. 45 and stated that LRA 4.7.11 already defines the scope of the TLAA as being limited to 

normal service radiation exposure. The staff finds the applicant’s response unacceptable

because Commitment No.45 did not identify what portion of the MEQ file will be revised and the 

acceptance criteria of the revision.

By letter dated March 30, 2011, the staff issued followup RAI 4.7.11-1b, asking the applicant to 

provide the design dose limits of the equipment within the scope of MEQ and the calculated 

total integrated radiation 60-year doses for all the zones. The staff also asked the applicant to 

ensure that the TLAA of normal service radiation exposure in MEQ has been properly 

dispositioned. The staff also asked the applicant to amend LRA Section 4.7.11 and provide 

sufficient detail to support the TLAA disposition of normal service radiation exposure in MEQ. 

Furthermore, the staff asked the applicant to revise Commitment No. 45 to identify the 

information to be revised and the acceptance criteria of the revision or justify why the existing 

Commitment No.45 is acceptable. Finally, the staff asked the applicant to amend the 

disposition of TLAA of normal service radiation exposure in MEQ to 10 CFR 54.21(c)(1)(i) or 

justify why the existing TLAA disposition of 10 CFR 54.21(c)(1)(ii) is acceptable. If LRA 

Section 4.7.11 is amended as a result of RAI 4.7.11-1b, the RAI stated that the applicant should 

provide an updated UFSAR supplement section in LRA Appendix A consistent with the

revisions.

In its response dated April 22, 2011, the applicant provided information about component types, 

radiation limiting environmental zones, calculated 60-year total integrated doses, and design 

dose limits for the equipment within the scope of MEQ. The applicant concluded that the 

calculated 60-year total integrated doses are bounded by the existing equipment design dose 

limits. Furthermore, the applicant also revised LRA Section 4.7.11 and Appendix A.2.4.5.9, 

indicating that it dispositioned the TLAA in accordance with 10 CFR 54.21(c)(1)(i), that the 

analysis remains valid for the period of extended operation.

The applicant also stated that Commitment No.45 is being deleted. The applicant explained 

that the updating of MEQ files is an internal design control process, and such activity will be 
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tracked via its internal commitment tracking system. The staff noted that, by using the data 

provided in its response, the applicant has demonstrated that the calculated 60-year total 

integrated doses for all zones are bounded by the existing equipment design dose limits. Thus, 

for license renewal, the staff finds the implementation of Commitment No. 45 not necessary.

Based on its review, the staff found the applicant’s response to RAI 4.7.11-1b acceptable 

because the applicant provided data to support its disposition of the TLAA for MEQ and revised 

LRA Section 4.7.11 and Appendix A.2.4.5.9 to reflect the proper TLAA disposition basis.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analysis for the MEQ remain valid for the period of extended operation. Additionally, it meets 

the acceptance criteria in SRP-LR Section 4.7.2.1 because, for the normal service radiation 

exposure in MEQ, the calculated 60-year radiation dose is less than the existing equipment 

design dose limit.

4.7.11.3 UFSAR Supplement

LRA Section A.2.4.5.9 provides the UFSAR supplement summarizing the MEQ analysis. The 

staff reviewed LRA Section A.2.4.5.9, consistent with SRP-LR Section 4.7.3.2, which states that 

the description should contain information associated with the TLAAs regarding the basis for 

determining that the applicant has made the demonstration required by 10 CFR 54.21(c)(1).

The staff also noted that the applicant previously committed (Commitment No. 45) to revise its 

MEQ files. Based on the discussions regarding the staff’s concern in RAI 4.7.11-1b, the 

applicant deleted Commitment No. 45 in its letter dated April 22, 2011. The staff found this 

deletion acceptable, as described in its evaluation of RAI 4.7.11-1b, documented in SER 

Section 4.7.11.2.

Based on its review of the UFSAR supplement, as amended by letter dated April 22, 2011, the 

staff finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff 

determined that the applicant provided an adequate summary description of its actions to 

address MEQ analysis, as required by 10 CFR 54.21(d).

4.7.11.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to10 CFR 54.21(c)(1)(i), that the analysis for the MEQ remains valid for 

the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d).

4.7.12 Absence of a TLAA for Metal Corrosion Allowances and Corrosion Effects

4.7.12.1 Summary of Technical Information in the Application

LRA Section 4.7.12 summarizes the absence of TLAA for metal corrosion allowances and 

corrosion effects. The applicant stated that a review of the Seabrook licensing basis found no 

description of time-dependent corrosion allowances, rates, or corrosion-dependent design lives 

of pressure vessels, system components, piping, or metal containment components. The 

applicant, therefore, concluded that there are no TLAAs for metal corrosion allowances and 

corrosion effects.
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4.7.12.2 Staff Evaluation

The staff reviewed the applicant’s TLAA discussion in LRA Section 4.7.12 against the 

acceptance guidance in SRP-LR Section 4.7.3.1.1 for plant-specific TLAAs, in accordance with 

10 CFR 54.21(c)(1)(i). The staff also reviewed UFSAR Section 5.4.2.3, “Steam Generators, 

Design Evaluation,” subsection (d), “Allowable Tube Wall Thinning under All Plant Conditions,” 

which states the following:

The corrosion rate is based on a conservative weight loss rate of Inconel tubing 

in flowing 650 °F primary side reactor coolant fluid. The weight loss, when 

equated to a thinning rate and projected over a 40-year design operating 

objective, with appropriate reduction after initial hours, is equivalent to 0.083 mils 

thinning. The assumed corrosion rate of 3 mils leaves a conservative 2.917 mils 

for general corrosion thinning on the secondary side.

The staff concluded that the above weight loss rate and remaining wall calculations meet the six 

criteria of TLAAs as identified in the SRP-LR Section 4.1.2. By letter dated January 5, 2011, the 

staff issued RAI 4.7.12-1, asking that the applicant justify why the metal corrosion allowance for 

steam generator tube walls is not considered a TLAA.

In its response dated February 3, 2011, the applicant agreed with the staff’s conclusion that the 

time-dependent corrosion associated with the steam generator tubes meets the definition of a 

TLAA. The applicant revised LRA Section 4.7.12 in its entirety and stated that the linear 

projection of the tube thinning rate for a 60-year period is equivalent to 0.1245 mils thinning, 

and, based on the assumed corrosion rate of 3 mils, this leaves 2.8755 mils for general 

corrosion on the secondary side.

The applicant also revised LRA Table 4.1-1, “Time-Limited Aging Analyses Applicable to 

Seabrook Station,” by including the TLAA for metal corrosion allowance and listing the 

disposition method as 10 CFR 54.21(c)(1)(i). However, the revised Section 4.7.12 stated the 

disposition method was 10 CFR 54.21(c)(1)(iii) and also stated that the effects of aging on the 

intended function(s) will be managed for the period of extended operation by the Steam 

Generator Tube Integrity Program. The staff noted this discrepancy and, by letter dated March 

7, 2011, the staff issued RAI 4.7.12-2, asking the applicant to clarify which method was used to 

disposition the metal corrosion TLAA.

In its response dated April 5, 2011, the applicant revised Section 4.7.12 again, stating the 

disposition method is 10 CFR 54.21(c)(1)(i), and the analyses remain valid for the period of 

extended operation. Based on its review, the staff finds the applicant’s response acceptable 

because the linear projection of the steam generator tube thinning rate to a 60-year period is 

significantly lower than the assumed corrosion rate of 3 mils. The staff’s concerns described in 

RAIs 4.7.12-1 and 4.7.12-2 are resolved.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analysis for the metal corrosion allowance for steam generator tube wall 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 60-year thinning rate was compared to the assumed corrosion 

rate and found to be bounded by the design corrosion rate.
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4.7.12.3 UFSAR Supplement

In its response to RAI 4.7.12-1, dated February 3, 2011, the applicant added metal corrosion 

allowance of steam generator tubes as a TLAA; however, the applicant did not revise LRA 

Section A.2.4.5, “Other Plant-Specific TLAAs,” to include the TLAA for metal corrosion 

allowances and corrosion effects. By letter dated March 7, 2011, the staff issued RAI 4.7.12-2, 

asking the applicant to revise LRA Section A.2.4.5 to include the TLAA associated with the 

steam generator tube metal corrosion allowance.

In its response dated April 5, 2011, the applicant added UFSAR supplement Section A.2.4.5.11 

summarizing the metal corrosion allowances and corrosion effects analysis. The staff reviewed 

LRA Section A.2.4.5.11 consistent with SRP-LR Section 4.7.2.2, which states that the 

description should contain information associated with the TLAAs regarding the basis for 

determining that the applicant has made the demonstration required by 10 CFR 54.21(c)(1). 

Based on its review, the staff finds the applicant’s response to RAI 4.7.12-2 acceptable because 

the UFSAR supplement has been revised to add the TLAA associated with the steam generator 

tube metal corrosion allowance. The staff’s concern described in RAI 4.7.12-2 regarding the 

UFSAR supplement is resolved.

Based on its review of the UFSAR supplement, included in response to RAI 4.7.12-2, the staff 

finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff 

determined that the applicant provided an adequate summary description of its actions to 

address metal corrosion allowances and corrosion effects analysis, as required by 

10 CFR 54.21(d).

4.7.12.4 Conclusion

On the basis of the review of the LRA and associated RAI responses, the staff concludes that 

the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(i), that the 

analysis for the steam generator tube metal corrosion allowance remains valid for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.13 Absence of a TLAA for Inservice Flaw Growth Analyses that Demonstrate 

Structural Stability for 40 Years

4.7.13.1 Summary of Technical Information in the Application

LRA Section 4.7.13 addresses the issue of TLAAs related to flaws in ASME Code class 

components. In this LRA section, the applicant states that Section XI of the ASME Code 

normally requires a fatigue crack growth rate analysis when flawed components are allowed to 

remain in service. The applicant also states that these analyses, if performed, could qualify as 

TLAAs. The applicant indicated that it conducted a review of its licensing basis and identified 

three fatigue crack growth analyses, which relate to pressurizer nozzle overlays, LBB analyses, 

and mechanical stress improvement processes (MSIPs) that could qualify as TLAAs. The 

applicant then provided a description of each potential TLAA in which it indicated that the 

analysis performed is based on a 60-year plant life and, therefore, is not a TLAA.
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4.7.13.2 Staff Evaluation

In its review of LRA Section 4.7.13 the staff considered two issues—the potential existence of 

additional fatigue crack growth analyses that could be TLAAs and the assertion of the applicant 

that the identified analyses were not TLAAs because they were conducted to include the period 

of extended operation. The second aspect of the staff’s evaluation consisted of two parts. The 

first part consisted of verifying that an analysis conducted for 60 years is not a TLAA. The 

second part consisted of verifying that the analyses under consideration were conducted for a 

period of 60 years.

In its attempt to identify additional fatigue analyses that could be considered TLAAs, the staff 

searched the applicant’s UFSAR. In this search, the staff did not identify additional fatigue 

analyses. The staff, therefore, determined that the applicant had identified three fatigue crack 

growth analyses that could be TLAAs.

In its evaluation of the first aspect of the applicant’s assertion that fatigue crack growth 

evaluations conducted for a period of 60 years are not TLAAs, the staff confirmed that 

10 CFR 54.3 states that to be considered a TLAA, calculations must meet six criteria. Criteria 3 

states that TLAAs “[i]nvolve time limiting assumptions defined by the current operating term, for 

example, 40 years.” The staff, therefore, determined that the analyses whose assumptions 

include the period of extended operation, i.e., a plant life of 60 years, are not TLAAs.

In its evaluation of the second aspect of the applicant’s assertion that fatigue crack growth 

evaluations conducted for pressurizer nozzle overlays and MSIP do not constitute TLAAs, the 

staff noted that these analyses refer to LRA Section 4.3.6. In Section 4.3.6, the applicant states 

that these analyses were conducted in 2008 and 2009 and were projected through the period of 

extended operation. The staff, therefore, concludes that these analyses are not TLAAs because 

the original analyses included the period of extended operation.

In its evaluation of the second aspect of the applicant’s assertion that fatigue crack growth 

evaluations conducted for LBB do not constitute a TLAA, the staff notes that the applicant refers 

to LRA Section 4.7.3. This section is a description of the LBB TLAA. In this section, the 

applicant states that “the analyses involved with LBB are considered TLAAs.” In Section 4.7.3, 

the applicant also dispositions this TLAA in accordance with 10 CFR 54.21(c)(1)(i), indicating 

that the analyses remain valid for the period of extended operation. In its evaluation of the 

TLAA, the staff noted that the fatigue cycles used in the analysis were based on 40 years. In 

light of the information presented in LRA Section 4.7.3, it appears to the staff that the LBB TLAA 

is, in fact, a TLAA that is based on the 40-year current operating term of the plant. It also 

appears to the staff that, in accordance with SRP-LR paragraph 4.7.3.1.1, the applicant has 

identified an additional activity, cycle-counting in this case, which allows the assumptions used 

in the original 40-year calculation to be confirmed for a 60-year plant life. The staff finds that 

this process allows the TLAA to be applied during the period of operation, but it does not 

constitute a new calculation based on 60 years. The staff, therefore, disagrees with the 

applicant’s position that the LBB calculations do not constitute a TLAA. To resolve this issue, 

the staff issued RAI 4.7.13-1 by letter dated December 14, 2010. In this RAI, the staff 

requested that the applicant modify LRA Section 4.7.13 to indicate that the LBB calculations do 

constitute a TLAA, which is addressed in LRA Section 4.7.3, or provide justification as to why 

these calculations do not constitute a TLAA.
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In its response dated January 13, 2011, the applicant modified Section 4.7.13 to indicate that 

LBB calculations are a TLAA, which is addressed in LRA Section 4.7.3. The staff finds the 

applicant’s response acceptable for the following reasons: 

• The applicant correctly identifies that the calculations conducted for its LBB analysis 

constitute a TLAA.

• The applicant appropriately identifies LRA Section 4.7.3 as the location for information 

concerning this TLAA.

• The information contained within LRA Section 4.7.3 is sufficient to indicate that the LBB 

analysis is not invalidated by extending the life of the plant from 40–60 years. (The 

staff’s evaluation of the LBB TLAA is contained in Section 4.7.3 of this SER.)

The staff’s concern described in RAI 4.7.13-1 is resolved.

4.7.13.3 UFSAR

The staff determined that no UFSAR supplement is required because the applicant addresses 

fatigue crack growth calculations in the LBB analysis of the RCS primary loop in LRA 

Section 4.7.3 and the staff’s evaluation of the applicant’s LBB analysis is contained in SER 

Section 4.7.3. The staff determined that the removal of this item from this LRA section by the 

applicant is appropriate and acceptable.

4.7.13.4 Conclusion

On the basis of its review, the staff notes that the applicant has appropriately identified 

calculations related to three fatigue crack growth analyses (which relate to pressurizer nozzle 

overlays), LBB analyses, and MSIPs that could be TLAAs.

The applicant addresses fatigue crack growth calculations in the LBB analysis of the RCS 

primary loop in LRA Section 4.7.3 and the staff’s evaluation of the applicant’s LBB analysis is 

contained in SER Section 4.7.3. The staff concludes that the removal of this item from this LRA 

section by the applicant is appropriate and acceptable.

Pursuant to 10 CFR 54.3, the staff also notes that the applicant has correctly identified that the 

calculations related to pressurizer nozzle overlays and MSIPs are not TLAAs because they are 

based on assumptions that include the period of extended operation (see SRP-LR 

Section 4.3.6). The staff concludes that the manner in which the applicant addressed these 

items is acceptable. 

4.7.14 Diesel Generator Thermal Cycle Evaluation

4.7.14.1 Summary of Technical Information in the Application

LRA Section 4.7.14 describes the applicant’s TLAA for the thermal cycling analysis of its 

emergency diesel generators (EDG), which addresses the equipment qualification in 

accordance with Institute of Electrical and Electronics Engineers (IEEE) Standard 323, 

“Qualifying Class 1E Equipment for Nuclear Power Generating Stations.” The applicant stated 

that the OEM conservatively qualified the EDGs for 5,454 full thermal cycles spanning a 40-year 

design life. The applicant also stated that, based on its current operating practice, it estimates 

the EDG will be subjected to 2,160 cycles through 60 years of licensed operation, which 
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82

accounts for maintenance activities, testing activities, and starts during postulated design basis 

transients and accident events.

The applicant dispositioned the EDG thermal cycling TLAA in accordance with 

10 CFR 54.21(c)(1)(i), by indicating the analysis remains valid for the period of extended 

operation.

4.7.14.2 Staff Evaluation

The staff reviewed LRA Section 4.7.14 and the EDG thermal cycling 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 this TLAA and the corresponding disposition, consistent with SRP-LR 

Section 4.7.3.1.1, which states that the staff may approve a plant-specific TLAA under 

10 CFR 54.21(c)(1)(i) if the applicant can demonstrate that the conditions and assumptions 

used in the analysis already address the relevant aging effects for the period of extended 

operation and the acceptance criteria are maintained to provide assurance that the intended 

function(s) is maintained for renewal.

The applicant compared the number of projected scheduled and unscheduled EDG start cycles 

to the design limit of 5,454 full thermal cycles. The staff noted that the design limit is supported 

by the applicant’s equipment qualification evaluation performed in accordance with IEEE 

Standard 323. However, it was not clear to the staff which design transients would result in a 

scheduled or unscheduled start of the EDGs. The staff noted that identification of all transients 

that would initiate a start of the EDGs and the 60-year projections for these transients is needed 

for comparison to the design limit (5,454 cycles). The staff also noted that LRA Section 4.7.14 

did not identify the EDG subcomponent(s) that were qualified in accordance with IEEE Standard 

323 or discuss the aging effects that were evaluated in the applicant’s EDG thermal cycling 

TLAA. The staff noted that a TLAA, defined in accordance with 10 CFR 54.3, must meet six 

criteria, two of which are the analysis must involve a structure or component that has been 

scoped in for license renewal in accordance with 10 CFR 54.4, and the analysis must consider 

an aging effect.

By letter dated January 5, 2011, the staff issued RAI 4.7.14-1, asking that the applicant identify 

all transients in LRA Table 4.3.1-2 that will result in a scheduled or unscheduled start of the 

EDGs and any additional transients beyond those in LRA Table 4.3.1-2 that can result in a 

scheduled or unscheduled start of the EDGs. In addition, the staff asked the applicant to clarify 

if the projection of the applicable transients that will result in an EDG start was performed on a 

cumulative transient projection basis or on an individual transient projection basis. In 

RAI 4.7.14-1, the staff also asked the applicant to do the following:

• identify all relevant EDG subcomponents that were qualified in accordance with IEEE 

Standard 323

• identify the aging effects that were analyzed in the EDG thermal cycling TLAA

• clarify how the analyzed cycles relate to the aging effect and the applicable acceptance 

criteria

In its response dated February 3, 2011, the applicant stated that it conservatively included the 

EDG equipment qualification analysis as a TLAA to account for the number of thermal cycles 

based on a 40-year period per the original design, even though 10 CFR 54.21(a)(1)(i) does not 

require AMR for the EDGs. The applicant also stated that the design did not require 
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83

identification of specific aging effects and that the transients, from LRA Table 4.3.1-2, that may 

result in an unscheduled start of the EDGs are the loss of load without immediate trip and the 

loss of offsite power, both having 60-year projections of seven cycles.

The staff noted that, in accordance with Criterion 2 of 10 CFR 54.3, the IEEE Standard 323 

analysis for the EDGs did not need to be identified as a TLAA because it does not involve a 

time-dependent analysis of an aging effect that is applicable to the EDG. The staff determined 

that the applicant has conservatively identified this analysis as a TLAA.

The applicant concluded that each EDG would not exceed more than 2,160 starts over a 

60-year licensed operating period, including allowances for performing maintenance activities 

on the EDGs and testing after maintenance activities. The staff reviewed LRA Table 4.3.1-3 

and noted that there is a significant margin between the numbers of EDG starts that the 

applicant has conservatively assumed (2,160 starts) when compared to the number of starts 

assumed in the EDG equipment qualification analysis (5,454 cycles).

Based on this review, the staff finds that, consistent with SRP-LR 4.7.3.1.1, the applicant’s 

response to RAI 4.7.14-1 is acceptable because the applicant is conservatively treating the 

EDG thermal cycle analysis as a TLAA, and there is sufficient margin between the 

conservatively assumed EDG starts for 60-years of operation and the analyzed number of EDG 

starts. The staff’s concerns described in RAI 4.7.14-1 are resolved.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the TLAA 

for EDG thermal cycle analysis 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 applicant has 

adequately demonstrated that the total number of EDG starts, as projected through 60 years of 

operation, will be less than the 5,454 EDG starts analyzed in the in the EDG equipment 

qualification analysis.

4.7.14.3 UFSAR Supplement

LRA Section A.2.4.5.10 provides the UFSAR supplement summarizing the TLAA for the thermal 

cycling analysis of the EDGs, addressing the equipment qualification in accordance with IEEE 

Standard 323. The staff reviewed LRA Section A.2.4.5.10, consistent with SRP-LR 

Section 4.7.3.2, to verify that it contains information that the TLAA has 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. Additionally, the staff determined that the applicant provided an 

adequate summary description of its actions to address the TLAA for the thermal cycling 

analysis of EDGs under its equipment qualification, in accordance with IEEE Standard 323, as 

required by 10 CFR 54.21(d).

4.7.14.4 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 EDG thermal cycling TLAA remains 

valid for the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d).
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84

4.7.15 Steam Generator Tube Wall Wear from Flow-Induced Vibration

4.7.15.1 Summary of Technical Information in the Application

By letter dated February 3, 2011, the applicant amended its LRA to include LRA Section 4.7.15, 

in response to RAIs 4.3.5-1 and 4.3.5-2, to describe the applicant’s TLAA for steam generator 

tube wear from FIV. The applicant stated that its Model F steam generators were evaluated for 

tube wear from FIV for the 7.4 percent power increase implemented as part of its Power Uprate 

Project. The applicant further stated that the uprate analysis for the effects of FIV on steam 

generator tube wear assumed 40 years of operation, and the maximum predicted tube wall wear 

for a 40-year operating life was estimated to be 0.0032 in. for the pre-uprate conditions. The 

applicant also stated that the 7.4 percent power uprate resulted in an increase of the maximum 

40-year tube wall wear of 0.0050 in. The applicant projected the maximum 60-year tube wall 

wear to be 0.0075 in, (approximately 20 percent through-wall wear) based on a linear projection, 

and it concluded that the projected wear is less than the limit of acceptability of 40 percent of 

wall thickness. The applicant dispositioned the steam generator tube wear from FIV TLAA in 

accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of 

extended operation.

4.7.15.2 Staff Evaluation

The staff reviewed LRA Subsection 4.7.15 and the TLAA for steam generator tube wear from 

FIV 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 and the corresponding disposition 

consistent with SRP-LR Section 4.7.3.1.1. The SRP-LR states that the staff may accept the 

applicant’s basis if the 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 assurance that the intended function(s) is maintained.

As described previously in SER Section 4.3.5, the staff issued RAI 4.3.5-1, Request 1, by letter 

dated January 5, 2011. This RAI requested that the applicant provide its technical basis to 

support the linear extrapolation method for wear of the steam generator tubes and to 

demonstrate that its analysis bounds likely changes in wear (and fatigue) over the period of 

extended operation, as affected by FIV or fluid-structure interactions. The staff also asked the 

applicant to identify any past or future planned independent confirmation to ensure the validity of 

the analyses, and the adequacy of the confirmation for the period of extended operation.

In its response to RAI 4.3.5-1, Request 1, dated February 3, 2011, the applicant stated that a 

linear tube wall wear rate is considered reasonable to determine a 60-year projection for tube 

wear. The applicant also stated that confirmation of the validity of the analyses to determine 

tube wear is provided in the Eddy Current Inspection Program described in its Steam Generator 

Tube Integrity Program. The applicant stated that, as discussed in the NRC SE for Amendment 

No. 101 for the Seabrook, Unit No. 1, 5.2 percent Power Uprate (ADAMS Accession 

No. ML050140453), any increase in wear would progress over many cycles and would be 

readily observed during routine eddy current inspections. The applicant revised the LRA to 

include this as a clarification in support of its TLAA disposition. The applicant further amended 

the disposition from 10 CFR 54.21(c)(1)(i) to 10 CFR 54.21(c)(1)(iii) to reflect that this aging 

effect will be managed by the Steam Generator Tube Integrity Program. 

The staff noted that steam generator tube wear-rate is typically decreasing (i.e., tube wear 

decrease with time). Thus, the staff finds the applicant's use of linear tube wear projection from
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85

40-year to 60-year operating period conservative and acceptable because the linear projection 

would result in a higher tube wear estimate than the actual tube wear, and hence RAI 4.3.5-1, 

Request 1, is resolved.

In its responses to RAI 4.3.5-1 and RAI 4.3.5-2, by letter dated February 3, 2011, the applicant 

stated that the basis for its disposition of this TLAA was the stretch power uprate (SPU) 

previously approved in the staff’s SER dated February 28, 2005 (ADAMS Accession 

No. ML050140453). The staff noted that the applicant subsequently received a 1.7 percent 

measurement uncertainty recapture approval on May 22, 2006 (ADAMS Accession 

No. ML061360034). The staff noted that the SPU approved in the staff’s SER is for 5.2 percent 

power increase, and it was discussed in LRA Section 4.3.5, as amended by letter dated 

February 3, 2011. The staff’s review and evaluation of RAI 4.3.5-1 and RAI 4.3.5-2 are 

documented in SER 4.3.5.2. However, LRA Section 4.7.15 indicated that the power uprate was 

7.4 percent. In the staff’s SER for SPU, tube wear increased from approximately 0.003 in. to 

approximately 0.005 in. at the 5.2 percent uprated condition.

By letter dated March 30, 2011, the staff issued followup RAI 4.7.15-1, asking the applicant to 

clarify or reconcile the actual power uprate applicable for the period of extended operation and 

provide an updated UFSAR supplement section in LRA Appendix A commensurate with the new 

LRA Section 4.7.15. In its response dated April 22, 2011, the applicant revised LRA 

Section 4.7.15 to show that the actual thermal power is 3,648 megawatts thermal, which was 

achieved after the SPU and measurement uncertainty recapture were implemented. The 

applicant also revised Appendix A.2.4.5.12 to show that it dispositioned the TLAA in accordance 

with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of extended operation. 

The staff noted that the applicant removed the references to conflicting percentage values for 

the power uprate in the LRA. Based on its review, the staff found the applicant’s response to 

RAI 4.7.15-1 acceptable because the applicant revised LRA Section 4.7.11 to reflect the actual 

thermal power and Appendix A.2.4.5.12 to reflect the TLAA disposition basis.

The staff noted that the maximum 40-year tube wall wear is 0.0050 in. and the applicant 

calculated the projected 60-year tube wall wear by multiplying the 40-year wear of 0.0050 in. by 

a factor 1.5. The staff noted that resulting tube wall wear of 0.0075 in. (approximately 20 

percent) remains less than the design limit of 40 percent wall thickness. Furthermore, the staff 

noted that steam generator tube wear-rate is typically decreasing (i.e., tube-wearing decrease 

with time). Thus, the staff finds the applicant's use of linear tube-wearing projection from 40-year 

to 60-year operating period conservative and acceptable because the linear projection would 

result in a higher tube wear estimate than the actual tube wear. 

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses for steam generator tube wall wear from FIV remain valid for the period of extended 

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because, for 

the steam generator tube, the 60-year wall thinning due to FIV is within the acceptable design 

wall thickness limit.

4.7.15.3 UFSAR Supplement

LRA Section A.2.4.5.12, as amended by letter dated April 22, 2011, provides the UFSAR 

supplement summarizing the analysis of steam generator tube wall wear due to FIV. The staff 

reviewed LRA Section A.2.4.5.12, consistent with SRP-LR Section 4.7.3.2, which states that the 

description should contain information associated with the TLAAs regarding the basis for 

determining that the applicant has made the demonstration required by 10 CFR 54.21(c)(1).
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86

Based on its review of the amended UFSAR supplement, the staff finds the supplement meets 

the acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff determined that the 

applicant provided an adequate summary description of its actions to address the analysis for 

steam generator tube wall wear from FIV, as required by 10 CFR 54.21(d).

4.7.15.4 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 steam generator tube 

wall wear from FIV 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).

4.8 Conclusion

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 provided a sufficient list of TLAAs, as 

defined in 10 CFR 54.3, and that the applicant has demonstrated the following: 

• The TLAAs will remain valid for the period of extended operation, as required by 

10 CFR 54.21(c)(1)(i),

• 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

• The effects of aging on intended functions will be adequately managed for the period of 

extended operation, as required by 10 CFR 54.21(c)(1)(iii). 

The staff also reviewed the UFSAR supplements for the TLAAs and finds that, the supplements 

contain descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In 

addition, the staff concludes, as required by 10 CFR 54.21(c)(2), that no plant-specific, 

TLAA-based exemptions are in effect.

With regard to these matters, the staff concludes that, there is reasonable assurance that the 

activities authorized by the renewed licenses will continue to be conducted in accordance with 

the CLB. Additionally, 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.
5-1

SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

In accordance with Title 10, Part 54, of the Code of Federal Regulations, the safety evaluation 

report (SER) will be referred to the Advisory Committee on Reactor Safeguards (ACRS), which 

will review the license renewal application (LRA) for Seabrook Station, Unit 1. The ACRS 

Subcommittee on Plant License Renewal will conduct its detailed review of the LRA after this 

SER is issued. NextEra Energy Seabrook, LLC (the applicant) and the staff of the U.S. Nuclear 

Regulatory Commission (NRC or the staff) will meet with the ACRS subcommittee and the 

ACRS full committee to discuss issues associated with the review of the LRA.

After the ACRS completes its review of the LRA and SER, the full committee will issue a report 

discussing results of its review. An update to this SER will include the ACRS report and the 

staff’s response to any issues and concerns reported.

6-1

SECTION 6

CONCLUSION

The staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff) reviewed the license 

renewal application (LRA) for Seabrook Station Unit 1, in accordance with NRC regulations and 

NUREG-1800, Revision 1, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants,” dated September 2005. Title 10, Section 54.29, of the Code of 

Federal Regulations (10 CFR 54.29) sets the standards for issuance of a renewed license.

On the basis of its review of the LRA, the staff determines that, pending resolution of the open 

and confirmatory items, the requirements of 10 CFR 54.29(a) will be met.

The staff notes that any requirements of 10 CFR Part 51, Subpart A, will be documented in a 

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

Nuclear Plants (GEIS).”

A-1

APPENDIX A

Seabrook Station License Renewal Commitments

During the review of the Seabrook Station Unit 1 license renewal application (LRA) by the staff 

of the U.S. Nuclear Regulatory Commission (NRC or the staff), NextEra Energy Seabrook, LLC 

(the applicant) made commitments related to managing the effects of aging for structures and 

components. Table A-1 lists these commitments along with the implementation schedules and 

sources for each commitment.
A-2

Appendix A

Table A-1. Seabrook Station License Renewal Commitments

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

1) PWR Vessel 

Internals

An inspection plan for Reactor Vessel Internals will be submitted for 

NRC review and approval. 

A.2.1.7 Program to be implemented prior to 

the period of extended operation. 

Inspection plan to be submitted to 

NRC not later than 2 years after 

receipt of the renewed license or not 

less than 24 months prior to the 

period of extended operation, 

whichever comes first.

2) Closed-Cylce

Cooling Water

Enhance the program to include visual inspection for cracking, loss of 

material and fouling when the in-scope systems are opened for 

maintenance.

A.2.1.12 Prior to the period of extended 

operation

3) Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling 

Systems

Enhance the program to monitor general corrosion on the crane and 

trolley structural components and the effects of wear on the rails in the 

rail system.

A.2.1.13 Prior to the period of extended 

operation

4) Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling 

Systems

Enhance the program to list additional cranes for monitoring. A.2.1.13 Prior to the period of extended 

operation

5) Compressed 

Air Monitoring

Enhance the program to include an annual air quality test requirement 

for the Diesel Generator compressed air sub system. 

A.2.1.14 Prior to the period of extended 

operation

6) Fire Protection Enhance the program to perform visual inspection of penetration seals 

by a fire protection qualified inspector.

A.2.1.15 Prior to the period of extended 

operation.

7) Fire Protection Enhance the program to add inspection requirements such as spalling, 

and loss of material caused by freeze-thaw, chemical attack, and 

reaction with aggregates by qualified inspector.

A.2.1.15 Prior to the period of extended 

operation.

8) Fire Protection Enhance the program to include the performance of visual inspection of A.2.1.15 Prior to the period of extended 
Appendix A

A-3

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

fire-rated doors by a fire protection qualified inspector. operation.

9) Fire Water 

System

Enhance the program to include NFPA 25 guidance for “where sprinklers 

have been in place for 50 years, they shall be replaced or representative 

samples from one or more sample areas shall be submitted to a 

recognized testing laboratory for field service testing”. 

A.2.1.16 Prior to the period of extended 

operation.

10) Fire Water 

System

Enhance the program to include the performance of periodic flow testing 

of the fire water system in accordance with the guidance of NFPA 25.

A.2.1.16 Prior to the period of extended 

operation.

11) Fire Water 

System

Enhance the program to include the performance of periodic visual or 

volumetric inspection of the internal surface of the fire protection system 

upon each entry to the system for routine or corrective maintenance. 

These inspections will be documented and trended to determine if a 

representative number of inspections have been performed prior to the 

period of extended operation. If a representative number of inspections 

have not been performed prior to the period of extended operation, 

focused inspections will be conducted. These inspections will be 

performed within ten years prior to the period of extended operation.

A.2.1.16 Within ten years prior to the period 

of extended operation.

12) Aboveground 

Steel Tanks

Enhance the program to include components and aging effects required 

by the Aboveground Steel Tanks.

A.2.1.17 Prior to the period of extended 

operation.

13) Aboveground 

Steel Tanks

Enhance the program to include an ultrasonic inspection and evaluation 

of the internal bottom surface of the two Fire Protection Water Storage 

Tanks. 

A.2.1.17 Within ten years prior to the period 

of extended operation.

14) Fuel Oil 

Chemistry

Enhance program to add requirements to 1) sample and analyze new 

fuel deliveries for biodiesel prior to offloading to the Auxiliary Boiler fuel 

oil storage tank and 2) periodically sample stored fuel in the Auxiliary 

Boiler fuel oil storage tank.

A.2.1.18 Prior to the period of extended 

operation.

15) Fuel Oil 

Chemistry

Enhance the program to add requirements to check for the presence of 

water in the Auxiliary Boiler fuel oil storage tank at least once per quarter 

and to remove water as necessary.

A.2.1.18 Prior to the period of extended 

operation.

16) Fuel Oil 

Chemistry

Enhance the program to require draining, cleaning and inspection of the 

diesel fire pump fuel oil day tanks on a frequency of at least once every 

ten years.

A.2.1.18 Prior to the period of extended 

operation.
A-4

Appendix A

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

17) Fuel Oil 

Chemistry

Enhance the program to require ultrasonic thickness measurement of the 

tank bottom during the 10-year draining, cleaning and inspection of the 

Diesel Generator fuel oil storage tanks, Diesel Generator fuel oil day 

tanks, diesel fire pump fuel oil day tanks and auxiliary boiler fuel oil 

storage tank.

A.2.1.18 Prior to the period of extended 

operation.

18) Reactor 

Vessel 

Surveillance

Enhance the program to specify that all pulled and tested capsules, 

unless discarded before August 31, 2000, are placed in storage.

A.2.1.19 Prior to the period of extended 

operation.

19) Reactor 

Vessel 

Surveillance

Enhance the program to specify that if plant operations exceed the 

limitations or bounds defined by the Reactor Vessel Surveillance 

Program, such as operating at a lower cold leg temperature or higher 

fluence, the impact of plant operation changes on the extent of Reactor 

Vessel embrittlement will be evaluated and the NRC will be notified.

A.2.1.19 Prior to the period of extended 

operation.

20) Reactor 

Vessel 

Surveillance

Enhance the program as necessary to ensure the appropriate withdrawal 

schedule for capsules remaining in the vessel such that one capsule will 

be withdrawn at an outage in which the capsule receives a neutron 

fluence that meets the schedule requirements of 10 CFR 50 Appendix H 

and ASTM E185-82 and that bounds the 60-year fluence, and the 

remaining capsule(s) will be removed from the vessel unless determined 

to provide meaningful metallurgical data.

A.2.1.19 Prior to the period of extended 

operation.

21) Reactor 

Vessel 

Surveillance

Enhance the program to ensure that any capsule removed, without the 

intent to test it, is stored in a manner which maintains it in a condition 

which would permit its future use, including during the period of extended 

operation.

A.2.1.19 Prior to the period of extended 

operation.

22) One-Time 

Inspection

Implement the One Time Inspection Program. A.2.1.20 Within ten years prior to the period 

of extended operation.

23) Selective 

Leaching of 

Materials

Implement the Selective Leaching of Materials Program. The program 

will include a one-time inspection of selected components where 

selective leaching has not been identified and periodic inspections of 

selected components where selective leaching has been identified.

A.2.1.21 Within five years prior to the period 

of extended operation.

24) Buried Piping 

And Tanks 

Inspection

Implement the Buried Piping And Tanks Inspection Program. A.2.1.22 Within ten years prior to entering the 

period of extended operation

25) One-Time 

Inspection of 

Implement the One-Time Inspection of ASME Code Class 1 Small Bore- A.2.1.23 Within ten years prior to the period 
Appendix A

A-5

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

ASME Code 

Class 1 Small 

Bore-Piping

Piping Program. of extended operation.

26) External 

Surfaces 

Monitoring

Enhance the program to specifically address the scope of the program, 

relevant degradation mechanisms and effects of interest, the refueling 

outage inspection frequency, the inspections of opportunity for possible 

corrosion under insulation, the training requirements for inspectors and 

the required periodic reviews to determine program effectiveness. 

A.2.1.24 Prior to the period of extended 

operation.

27) Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Implement the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program.

A.2.1.25 Prior to the period of extended 

operation.

28) Lubricating 

Oil Analysis

Enhance the program to add required equipment, lube oil analysis 

required, sampling frequency, and periodic oil changes.

A.2.1.26 Prior to the period of extended 

operation.

29) Lubricating 

Oil Analysis

Enhance the program to sample the oil for the Switchyard SF6 

compressors and the Reactor Coolant pump oil collection tanks.

A.2.1.26 Prior to the period of extended 

operation.

30) Lubricating 

Oil Analysis

Enhance the program to require the performance of a one-time 

ultrasonic thickness measurement of the lower portion of the Reactor 

Coolant pump oil collection tanks prior to the period of extended 

operation.

A.2.1.26 Prior to the period of extended 

operation.

31) ASME 

Section Xi, 

Subsection IWL

Enhance procedure to include the definition of “Responsible Engineer”. A.2.1.28 Prior to the period of extended 

operation.

32) Structures 

Monitoring 

Program

Enhance procedure to add the aging effects, additional locations, 

inspection frequency and ultrasonic test requirements.

A.2.1.31 Prior to the period of extended 

operation.

33) Structures 

Monitoring 

Program

Enhance procedure to include inspection of opportunity when planning 

excavation work that would expose inaccessible concrete.

A.2.1.31 Prior to the period of extended 

operation.

34) Electrical 

Cables and 

Connections Not 

Implement the Electrical Cables and Connections Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements program.

A.2.1.32 Prior to the period of extended 

operation.
A-6

Appendix A

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

Subject to 10 

CFR 50.49 

Environmental 

Qualification 

Requirements

35) Electrical 

Cables and 

Connections Not 

Subject to 10 

CFR 50.49 

Environmental 

Qualification 

Requirements 

Used in 

Instrumentation 

Circuits

Implement the Electrical Cables and Connections Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements Used in Instrumentation 

Circuits program.

A.2.1.33 Prior to the period of extended 

operation.

36) Inaccessible 

Power Cables 

Not Subject to 10 

CFR 50.49 

Environmental 

Qualification 

Requirements

Implement the Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program.

A.2.1.34 Prior to the period of extended 

operation.

37) Metal 

Enclosed Bus

Implement the Metal Enclosed Bus program. A.2.1.35 Prior to the period of extended 

operation.

38) Fuse Holders Implement the Fuse Holders program. A.2.1.36 Prior to the period of extended 

operation.

39) Electrical 

Cable 

Connections Not 

Subject to 10 

CFR 50.49 

Environmental 

Qualification 

Requirements

Implement the Electrical Cable Connections Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements program.

A.2.1.37 Prior to the period of extended 

operation.

40) 345 KV SF6 Implement the 345 KV SF6 Bus program. A.2.2.1 Prior to the period of extended 
Appendix A

A-7

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

Bus Program operation.

41) Metal Fatigue 

of Reactor 

Coolant Pressure 

Boundary

Enhance the program to include additional transients beyond those 

defined in the Technical Specifications and UFSAR. 

A.2.3.1 Prior to the period of extended 

operation.

42) Metal Fatigue 

of Reactor 

Coolant Pressure 

Boundary

Enhance the program to implement a software program, to count 

transients to monitor cumulative usage on selected components.

A.2.3.1 Prior to the period of extended 

operation.

43) Pressure -

Temperature 

Limits, including 

Low 

Temperature 

Overpressure 

Protection Limits

Seabrook Station will submit updates to the P-T curves and LTOP limits

to the NRC at the appropriate time to comply with 

10 CFR 50 Appendix G.

A.2.4.1.4 The updated analyses will be 

submitted at the appropriate time to 

comply with 10 CFR 50 Appendix G, 

Fracture Toughness Requirements.
A-8

Appendix A

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

44) 

Environmentally -

Assisted Fatigue 

Analyses (TLAA)

NextEra Seabrook will perform a review of design basis ASME Class 1 

component fatigue evaluations to determine whether the NUREG/CR6260-based components that have been evaluated for the effects of the 

reactor coolant environment on fatigue usage are the limiting 

components for the Seabrook plant configuration. If more limiting 

components are identified, the most limiting component will be evaluated 

for the effects of the reactor coolant environment on fatigue usage. If the 

limiting location identified consists of nickel alloy, the environmentallyassisted fatigue calculation for nickel alloy will be performed using the 

rules of NUREG/CR-6909.

(1) Consistent with the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program Seabrook Station will update the fatigue usage 

calculations using refined fatigue analyses, if necessary, to determine 

acceptable CUFs (i.e., less than 1.0) when accounting for the effects of 

the reactor water environment. This includes applying the appropriate 

Fen factors to valid CUFs determined from an existing fatigue analysis 

valid for the period of extended operation or from an analysis using an 

NRC-approved version of the ASME code or NRC-approved alternative 

(e.g., NRC-approved code case).

(2) If acceptable CUFs cannot be demonstrated for all the selected 

locations, then additional plant-specific locations will be evaluated. For 

the additional plant-specific locations, if CUF, including environmental 

effects is greater than 1.0, then Corrective Actions will be initiated, in 

accordance with the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program, B.2.3.1. Corrective Actions will include inspection, 

repair, or replacement of the affected locations before exceeding a CUF 

of 1.0 or the effects of fatigue will be managed by an inspection program 

that has been reviewed and approved by the 

NRC (e.g., periodic non-destructive examination of the affected locations 

at inspection intervals to be determined by a method accepted by the 

NRC).

A.2.4.2.3 At least two years prior to entering 

the period of extended operation.

45 Number Not Used

46) Protective 

Coating 

Monitoring and 

Maintenance

Enhance the program by designating and qualifying an Inspector 

Coordinator and an Inspection Results Evaluator. 

A.2.1.38 Prior to the period of extended 

operation
Appendix A

A-9

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

47) Protective 

Coating 

Monitoring and 

Maintenance

Enhance the program by including, “Instruments and Equipment needed 

for inspection may include, but not be limited to, flashlight, spotlights, 

marker pen, mirror, measuring tape, magnifier, binoculars, camera with 

or without wide angle lens, and self sealing polyethylene sample bags.”

A.2.1.38 Prior to the period of extended 

operation

48) Protective 

Coating 

Monitoring and 

Maintenance

Enhance the program to include a review of the previous two monitoring 

reports. 

A.2.1.38 Prior to the period of extended 

operation

49) Protective 

Coating 

Monitoring and 

Maintenance

Enhance the program to require that the inspection report is to be 

evaluated by the responsible evaluation personnel, who is to prepare a 

summary of findings and recommendations for future surveillance or 

repair. 

A.2.1.38 Prior to the period of extended 

operation

50) ASME 

Section XI, 

Subsection IWE

Perform UT testing of the containment liner plate in the vicinity of the 

moisture barrier for loss of material.

A.2.1.27 No later than December 31, 2015 

and repeated at intervals of no more 

than five refueling outages

51) Number not used 

52) ASME 

Section XI, 

Subsection IWL

Implement measures to maintain the exterior surface of the Containment 

Structure, from elevation -30 feet to +20 feet, in a dewatered state.

A.2.1.28 By 2013

53) Reactor 

Head Closure 

Studs

Replace the spare reactor head closure stud(s) manufactured from the 

bar that has a yield strength > 150 ksi with ones that do not exceed 150 

ksi.

A.2.1.3 Prior to the period of extended 

operation.

54) Steam 

Generator Tube 

Integrity

Unless an alternate repair criteria changing the ASME code boundary is 

permanently approved by the NRC, or the Seabrook Station steam 

generators are changed to eliminate PWSCC-susceptible tube-totubesheet welds, submit a plant-specific aging management program to 

manage the potential aging effect of cracking due to PWSCC at least 

twenty-four months prior to entering the Period of Extended Operation.

A.2.1.10 Program to be submitted to NRC at 

least 24 months prior to the period of 

extended operation.

55) Steam 

Generator Tube 

Integrity

Seabrook will perform an inspection of each steam generator to assess 

the condition of the divider plate assembly.

A.2.1.10 Prior to entering the period of 

extended operation

56) Closed-Cycle 

Cooling Water 

System

Revise the station program documents to reflect the EPRI Guideline 

operating ranges and Action Level values for hydrazine and sulfates.

A.2.1.12 Prior to entering the period of 

extended operation.
A-10

Appendix A

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

57) Closed-Cycle 

Cooling Water 

System

Revise the station program documents to reflect the EPRI Guideline 

operating ranges and Action Level values for Diesel Generator Cooling 

Water Jacket pH.

A.2.1.12 Prior to entering the period of 

extended operation.

58) Fuel Oil 

Chemistry

Update Technical Requirement Program 5.1, (Diesel Fuel Oil Testing 

Program) ASTM standards to ASTM D2709-96 and ASTM D4057-95 

required by the GALL XI.M30 Rev 1

A.2.1.18 Prior to the period of extended 

operation.

59) Nickel Alloy 

Nozzles and 

Penetrations

The Nickel Alloy Aging Nozzles and Penetrations program will implement 

applicable Bulletins, Generic Letters, and staff accepted industry 

guidelines.

A.2.2.3 Prior to the period of extended 

operation.

60) Buried Piping 

and Tanks 

Inspection

Implement the design change replacing the buried Auxiliary Boiler supply 

piping with a pipe-within-pipe configuration with leak indication capability.

A.2.1.22 Prior to entering the period of 

extended operation.

61) Compressed 

Air Monitoring 

Program

Replace the flexible hoses associated with the Diesel Generator air 

compressors on a frequency of every 10 years.

A.2.1.14 Within ten years prior to entering the 

period of extended operation.

62) Water 

Chemistry

Enhance the program to include a statement that sampling frequencies 

are increased when chemistry action levels are exceeded.

A.2.1.2 Prior to entering the period of 

extended operation.

63) Flow Induced 

Erosion

Ensure that the quarterly CVCS Charging Pump testing is continued 

during the PEO. Additionally, add a precaution to the test procedure to 

state that an increase in the CVCS Charging Pump mini flow above the 

acceptance criteria may be indicative of erosion of the mini flow orifice as 

described in LER 50-275/94-023. 

N/A Prior to the period of extended 

operation

64) Buried Piping 

and Tanks 

Inspection

Soil analysis shall be performed prior to entering the period of extended 

operation to determine the corrosivity of the soil in the vicinity of noncathodically protected steel pipe within the scope of this program. If the 

initial analysis shows the soil to be non-corrosive, this analysis will be reperformed every ten years thereafter.

A.2.1.22 Prior to entering the period of 

extended operation.

65) Flux Thimble 

Tube

Implement measures to ensure that the movable incore detectors are not 

returned to service during the period of extended operation.

N/A Prior to entering the period of 

extended

operation

66 Number not used

67) Structures 

Monitoring 

Perform one shallow core bore in an area that was continuously wetted 

from borated water to be examined for concrete degradation and also 

No later than December 31, 2015
Appendix A

A-11

Item Number Commitment Updated Final Safety

Analysis Report 

(UFSAR) Supplement 

Section/LRA Section

Enhancement or Implementation 

Schedule

Program exposed rebar to detect any degradation such as loss of material.

68) Structures 

Monitoring 

Program

Perform sampling at the leakoff collection points for chlorides, sulfates, 

pH and iron once every three months.

Starting January 2014

B-1

APPENDIX B

CHRONOLOGY

This appendix lists chronologically the routine licensing correspondence between the staff of the 

U.S. Nuclear Regulatory Commission (NRC or the staff) and NextEra Energy Seabrook, LLC

(the applicant). This appendix also lists other correspondence on the staff’s review of the 

Seabrook Station Unit 1 (Seabrook) license renewal application (LRA) (under 

Docket No. 50-443).

Date Subject

5/25/2010 License Renewal Application for Facility Operating License (Amend/Renewal), NextEra 

Energy Seabrook, LLC, Seabrook Station—License Renewal Application, Volume I

(Agencywide Document Access and Management System (ADAMS) Accession 

No. ML101590098)

5/25/2010 License Renewal Application for Facility Operating License (Amend/Renewal), NextEra 

Energy Seabrook, LLC, Seabrook Station—License Renewal Application, Volume II (ADAMS 

Accession No. ML101590101)

5/25/2010 License Renewal Application for Facility Operating License (Amend/Renewal), NextEra 

Energy Seabrook, LLC, Seabrook Station—License Renewal Application, Volume III. 

(ADAMS Accession No. ML101590091)

6/10/2010 Letter from Holian, B.E., NRC, to Freeman, P., NextEra Energy Seabrook, LLC: Receipt and 

Availability of the License Renewal Application for the Seabrook Station Nuclear Power 

Plant(ADAMS Accession No. ML101320273)

6/10/2010 Federal Register Notice, from Holian, B.E., NRC: Notice of Receipt and Availability for 

Seabrook Station License Renewal Application—FRN (ADAMS Accession 

No. ML101330049)

7/13/2010 Letter from Holian B.E., NRC, to Freeman, P., NextEra Energy Seabrook, LLC: 

Determination of Acceptability and Sufficiency for Docketing, Proposed Review Schedule, 

and Opportunity for a Hearing Regarding the Application from NextEra Energy Seabrook, 

LLC, for Renewal of the Operating License for Seabrook Station, Unit 1 (ADAMS Accession 

No. ML101690417)

7/13/2010 Federal Register Notice, from Holian B.E., NRC: Notice of Acceptance for Docketing of the 

Application and Notice of Opportunity for Hearing Regarding Renewal of Facility Operating 

License No. NPF-086 for an Additional 20-year Period for License Renewal for Seabrook 

Station—FRN (ADAMS Accession No. ML101690449)

7/16/2010 Summary of Telephone Conference Call Held on June 24, 2010, Between NRC and NextEra 

Energy Seabrook, LLC, Concerning the Review of Acceptability of Docketing of the 

Seabrook Station, Unit 1, License Renewal Application (ADAMS Accession 

No. ML101800207) 

7/19/2010 Slides and Viewgraphs, from Plasse, R.A., NRC, Seabrook Station License Renewal 

Process Overview (ADAMS Accession No. ML101970370)

7/20/2010 Meeting Notice, from Plasse, R.A., NRC, to Pham, B.M., NRC, August 19, 2010, 

Forthcoming Meeting to Discuss the License Renewal Process and Environmental Scoping 

for Seabrook Station License Renewal Application Review (ADAMS Accession 

No. ML101900013)

8/4/2010 Press Release, NRC, Press Release-I-10-036: NRC to Discuss Process for Review of 

License Renewal Application for Seabrook Nuclear Plant, Seek Input on Environmental 

Review (ADAMS Accession No. ML102160633)
Appendix B

B-2

Date Subject

8/10/2010 Meeting Briefing Package/Handouts, from Susco, J.J., NRC, Seabrook Station License 

Renewal Process Overview and Environmental Impact Statement Scoping Public Meeting 

Slides (ADAMS Accession No. ML102220430)

8/10/2010 Slides and Viewgraphs, from Plasse, R.A., NRC, Seabrook Station License Renewal 

Process Overview and Scoping Public Meeting Slides (ADAMS Accession 

No. ML102220571)

9/20/2010 Memoranda, from Susco, J.J., NRC, to NextEra Energy Seabrook, LLC, Summary of Public 

License Renewal Overview and Environmental Scoping Meeting Related to the Review of 

the Seabrook Station License Renewal Application (TAC Nos. ME3959 and ME4028)

(ADAMS Accession No. ML102520222)

10/29/2010 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Seabrook Station—Supplement 

to License Renewal Application (ADAMS Accession No. ML103060022)

11/10/2010 Press Release, NRC, Press Release-10-206: Licensing Board to Hear Oral Argument Nov. 

30 in Portsmouth, NH, on Seabrook Nuclear Power Plant License Renewal (ADAMS 

Accession No. ML103160148)

11/15/2010 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Seabrook Station—

Supplement 2 to License Renewal Application (ADAMS Accession No. ML103210330)

11/18/2010 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station, License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML103090308)

11/18/2010 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station, License Renewal Application—Aging 

Management Programs (ADAMS Accession No. ML103090558)

11/18/2010 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML103130159)

12/3/2010 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Seabrook Station: Response to 

Request for Additional Information NextEra Energy Seabrook License Renewal Application 

(ADAMS Accession No. ML103400259)

12/14/2010 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station, License Renewal Application (TAC 

No. ME4028)—Aging Management Programs (ADAMS Accession No. ML103260554)

12/14/2010 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of The Seabrook Station, License Renewal Application (TAC 

No. ME4028)—Aging Management Programs (ADAMS Accession No. ML103420273)

12/17/2010 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Aging 

Management Programs (ADAMS Accession No. ML103540534)

12/22/2010 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information Set 2 Related to the Review of the License Renewal Application

(ADAMS Accession No. ML103620313)

1/5/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML103420583)

1/5/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML103420585)
Appendix B

B-3

Date Subject

1/5/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML103420587)

1/13/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Aging 

Management Programs—Set 5 (ADAMS Accession No. ML110140587)

1/13/2011 Letter from Freeman P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Aging 

Management Programs—Set 4 (ADAMS Accession No. ML110140809)

1/13/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information, NextEra Energy License Renewal Application (ADAMS Accession 

No. ML110140810)

1/21/2011 Letter to Freeman, P., O'Keefe, M., NextEra Energy Seabrook, LLC: Request for Additional 

Information Related to the Review of the Seabrook Station License Renewal Application 

(TAC No. ME4028) (ADAMS Accession No. ML110070128)

2/3/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Sets 6, 7,

and 8 (ADAMS Accession No. ML110380081)

2/4/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Scoping and Screening Audit 

Summary Regarding the Seabrook Station License Renewal Application (TAC No. ME4028) 

(ADAMS Accession No. ML110270026)

2/18/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information, License Renewal Application, Request for Additional Information—

Set 9 (ADAMS Accession No. ML110530481)

2/24/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML110260266)

3/7/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of The Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML110550920)

3/17/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request for Additional Information 

Related to the Review of the Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML110350630)

3/21/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Audit Report Regarding the 

Seabrook Station License Renewal Application (ADAMS Accession No. ML110280424)

3/22/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information on License Renewal Application—Set 10 and Associated LRA 

Changes (ADAMS Accession No. ML110830045)

3/30/2011 Letter to Freeman, P., O'Keefe, M., NextEra Energy Seabrook, LLC: Request For Additional 

Information Related To The Review of The Seabrook Station License Renewal Application

(ADAMS Accession No. ML110700018)

4/5/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Request for 

Additional Information—Set 11 (ADAMS Accession No. ML110960647)

4/14/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Request for 

Additional Information—Set 13 (ADAMS Accession No. ML11108A131)
Appendix B

B-4

Date Subject

4/18/2011 Letter from Freeman, P., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information, NextEra Energy Seabrook License Renewal Application (ADAMS 

Accession No. ML11122A075)

4/22/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information—Set 12 and Associated License Renewal Application Changes

(ADAMS Accession No. ML11115A116)

5/12/2011 Letter from Holian, B.E., NRC, to Freeman, P., NextEra Energy Seabrook, LLC, Schedule 

Revision for the Environmental Review of the Seabrook Station License Renewal Application 

(ADAMS Accession No. ML110890319)

5/23/2011 Letter to Freeman, P., NextEra Energy Seabrook, LLC: Request For Additional Information 

Related To The Review Of The Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML11132A007)

6/2/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information, NextEra Energy Seabrook License Renewal Application, Request for 

Additional Information—Set 14 (ADAMS Accession No. ML11154A133)

6/10/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Supplement to Response to 

Request for Additional Information—April 18, 2011, License Renewal Application (ADAMS 

Accession No. ML11166A255)

6/29/2011 Letter to Freeman, P.O., NextEra Energy Seabrook, LLC: Request for Additional Information 

for the Review of the Seabrook Station, License Renewal Application (ADAMS Accession 

No. ML11178A338)

7/12/2011 Letter from Holian, B.E., NRC, to Freeman, P., NextEra Energy Seabrook, LLC: Schedule 

Revision for the Safety Review of the Seabrook Station License Renewal Application (TAC 

No. ME4028) (ADAMS Accession No. ML11178A365)

8/11/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information to License Renewal Application—Set 15 and LRA Changes (ADAMS 

Accession No. ML11227A023)

8/25/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: First Annual Update to License 

Renewal Application and Changes to LRA Appendix A (ADAMS Accession 

No. ML11241A142)

10/7/2011 Letter to Freeman, P.O., NextEra Energy Seabrook, LLC: Requests for Additional 

Information for the Review of the Seabrook Station, License Renewal Application (ADAMS 

Accession No. ML11278A069)

11/2/2011 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information—Set 16 (ADAMS Accession No. ML11308A025)

11/4/2011 Summary of Telephone Conference Call Held on March 18, 2011, Between NRC and 

NextEra Energy Seabrook, LLC, Concerning Clarification of Information Pertaining to the 

Seabrook Station License Renewal Application (ADAMS Accession No. ML11304A002) 

12/12/2011 Letter to Freeman, P.O., NextEra Energy Seabrook, LLC: Requests for Additional 

Information for the Review of the Seabrook Station License Renewal Application (ADAMS 

Accession No. ML11341A162)

1/25/2012 Letter to Freeman, P.O., NextEra Energy Seabrook, LLC: Project Manager Change for the 

License Renewal of Seabrook Station (ADAMS Accession No. ML12009A007)

2/7/2012 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Request for 

Additional Information—Set 18, RAI B.2.1.11-2 (ADAMS Accession No. ML12041A054)
Appendix B

B-5

Date Subject

3/30/2012 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Supplemental 

Response—Alkali Silica Reaction (ADAMS Accession No. ML12094A364)

4/16/2012 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Confirmation of Information 

Provided to NRC Staff Regarding Seabrook Station License Renewal Application (ADAMS 

Accession No. ML12110A263)

4/18/2012 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Supplemental 

Response - (RAI) Follow-up B.2.1.31-1 Item 1 (ADAMS Accession No. ML12110A407)

4/26/2012 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Response to Request for 

Additional Information NextEra Energy Seabrook License Renewal Application Supplemental 

Response - RAI B.2.1.11-2 and B.2.1.12-6 (ADAMS Accession No. ML121220298)

5/10/2012 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: Confirmation of Information 

provided to NRC Staff regarding Seabrook Station License Renewal Application (ADAMS 

Accession No. ML12136A450)

5/16/2012 Letter from Freeman, P.O., NextEra Energy Seabrook, LLC: NextEra Energy Seabrook 

License Renewal Application, Structures Monitoring Program Supplement-Alkali-Silica 

Reaction (ASR) Monitoring (ADAMS Accession No. ML12142A323)

5/29/2012 Letter to Freeman, P.O., NextEra Energy Seabrook, LLC: Requests for Additional 

Information for the Review of the Seabrook Station, License Renewal Application - Set 17

(ADAMS Accession No. ML12144A441)

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.

Name Responsibility

Alley, David Reviewer—Mechanical

Armstrong, Garry Reviewer—Mechanical

Auluck, Raj Management Oversight

Brittner, Don Reviewer—Mechanical

Buford, Angela Reviewer—Structural

Casto, Greg Management Oversight

Cunanan, Arthur Management Oversight

Daily, John Management Oversight

Dennig, Robert Management Oversight

Doutt, Cliff Reviewer—Electrical

Dozier, Jerry Management Oversight

Erickson, Alice Reviewer—Structural

Foli, Adakou Reviewer—Electrical

Fu, Bart Reviewer—Mechanical

Gardner, William Management Oversight

Gardocki, Stanley Reviewer—Mechanical

Gavula, Jim Reviewer—Mechanical

Green, Kim Management Oversight

Hiser, Allen Management Oversight

Holian, Brian Management Oversight

Holston, Bill Reviewer—Mechanical

Hunt, Chris Reviewer—Mechanical

Iqbal, Naeem Reviewer—Fire Protection

Kalikian, Roger Reviewer—Mechanical

Khanna, Meena Management Oversight

Kichline, Michelle Reviewer—Mechanical

Klein, Alex Management Oversight

Klos, John Reviewer—Mechanical

Lehman, Bryce Reviewer—Structural
Appendix C

C-2

Name Responsibility

Li, Rui Reviewer—Electrical

Lupold, Tim Management Oversight

Manoly, Kamal Reviewer—Structural

Medoff, Jim Reviewer—Mechanical

Miller, Kenneth Reviewer—Electrical

Min, Seung Reviewer—Mechanical

Mitchell, Matt Management Oversight

Ng, Ching Reviewer—Mechanical

Nguyen, Duc Reviewer—Electrical

Obodoako, Alyoysius Reviewer—Mechanical

Parks, Benjamin Reviewer—Neutron Fluence

Pelton, Dave Management Oversight

Plasse, Rick Project Management

Prinaris, Andrew Reviewer—Structural

Rhow, Sang Reviewer—Electrical

Rogers, Bill Reviewer—Scoping & Screening Methodology

Sallman, Ahsan Reviewer—Mechanical

Sheikh, Abdul Reviewer—Structural

Smith, Ed Reviewer— Scoping & Screening Methodology

Sun, Robert Reviewer—Mechanical

Taylor, Robert Management Oversight

Torres, Roberto Reviewer—Mechanical

Ulses, Anthony Management Oversight

Uribe, Juan Reviewer—Mechanical

Vaucher, Rachel Reviewer—Mechanical

Wentzel, Mike Management Oversight

Wilson, George Management Oversight

Wise, John Reviewer—Mechanical

Wong, Albert Reviewer—Mechanical

Wong, Emma Reviewer—Mechanical

Wrona, Dave Management Oversight

Yee, On Reviewer—Mechanical

Contractors

Argonne National Laboratory Technical Review

Ian, Evan & Alexander Corporation 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 Seabrook Station Unit 1.

References

American Concrete Institute (ACI) ACI 201.2R-77, “Guide to Durable Concrete”

ACI 201.1R-2, “Guide for Making a Condition Survey of Concrete in Service”

ACI 224.R1, “Causes, Evaluation, and Repair of Cracks in Concrete Structures,” March 2007

ACI 301, “Specifications for Structural Concrete”

ACI 318, “Building Code Requirements for Structural Concrete,” 1963

ACI 349.3R, “Evaluation of Existing Nuclear Safety-Related Concrete Structures,” January 1996

Association of Iron and Steel Engineers (AISE) Standard No. 6, “Specification for Electric 

Overhead Traveling Cranes for Steel Mill Service” (currently known as AIST TR-06) 

ANSI B30.2, “Overhead and Gantry Cranes,” January 1976 (currently known as ASME B30.2)

ANSI B30.11, “Monorails and Underhung Cranes” (currently known as ASME B30.11)

ANSI B31.1, “Power Piping” (currently known as ASME B31.1)

ANSI B31.7, “Nuclear Power Piping” (withdrawn, but currently known as ASME B31.7)

ANSI/ANS-56.8-1994, “Containment System Leakage Testing Requirements”

USAS (ANSI) B16.5, “Pipe Flanges and Flanged Fittings NPS 1/2 Through NPS 24 Metric/Inch 

Standard” (currently known as ASME B16.5)

American Society of Civil Engineers (ASCE) 11-90, “Guideline for Structural Condition 

Assessment of Existing Buildings”

ANSI/AISC 360, “Specification for Structural Steel Buildings”

American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section 

III, “Rules for Construction of Nuclear Power Plant Components”

ASME Boiler and Pressure Vessel Code, Section XI, “Rules for Inservice Inspection of Nuclear 

Power Plant Components” 2001 Edition through the 2003 Addenda

ASME Code, Section XI, Appendix G, “Fracture Toughness Criteria for Protection Against 

Failure”

ASME Code Case N-416-2, “Alternative Pressure Test Requirements for Welded Repairs or 

Installation of Replacement Items by Welding, Class 1, 2, and 3, Section XI, Division 1,” May 

2000

ASME Code Case N-481, “Alternative Examination Requirements for Cast Austenitic Pump 

Casings, Section XI, Division 1,” March 2004

ASME Code Case N-514, “Low Temperature Overpressure Protection, Section XI, Division 1,” 

April 2002 
D-2

ASME Code Case N-652-1, “Alternative Requirements to Categorize B-G-1, B-G-2, and C-D 

Bolting Examination Methods and Selection Criteria, Section XI, Division 1,” February 2004

ASME Code Case N-722, “Additional Examinations for PWR Pressure Retaining Welds in Class 

1 Components Fabricated With Alloy 600/82/182 Materials, Section XI, Division1,” July 2005

ASME Code Case N-729-1, “Alternative Examination Requirements for PWR Reactor Vessel 

Upper Heads With Nozzles Having Pressure-Retaining Partial-Penetration Welds Section XI, 

Division 1,” March 2006

ASME Code Case N-770, “"Alternative Examination Requirements and Acceptance Standards 

for Class 1 PWR Piping and Vessel Nozzle Butt Welds Fabricated with UNS N06082 or UNS 

W86182 Weld Filler Material With or Without Application of Listed Mitigation Activities, Section 

XI, Division 1," December 2009

ASM Handbook, Volume 13B: Corrosion: Materials

ASM Handbook, Volume 13C: Corrosion: Environments and Industries

American Society for Testing and Materials (ASTM) E185-70, “Standard Practice for Design of 

Surveillance Programs for Light-Water Moderated Nuclear Power Reactor Vessels”

ASTM E185-73, “Standard Practice for Design of Surveillance Programs for Light-Water 

Moderated Nuclear Power Reactor Vessels”

ASTM E185-82, “Standard Practice for Design of Surveillance Programs for Light-Water 

Moderated Nuclear Power Reactor Vessels”

ASTM C33, “Standard Specification for Concrete Aggregates,” 2007

ASTM C227, “Standard Test Method for Potential Alkali Reactivity of Cement-Aggregate 

Combinations (Mortar-Bar Method)”

ASTM C295, “Standard Guide for Petrographic Examination of Aggregates for Concrete”

ASTM D1796, “Standard Test Method for Water and Sediment in Fuel Oils by the Centrifuge 

Method (Laboratory Procedure)” 

ASTM D2709, “Standard Test Method for Water and Sediment in Middle Distillate Fuels by 

Centrifuge” 

ASTM D2276, “Standard Test Method for Particulate Contaminant in Aviation Fuel by Line 

Sampling”

ASTM D4057, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products”

ASTM D4176, “Standard Test Method for Free Water and Particulate Contamination in Distillate 

Fuels”

ASTM D6217, “Standard Test Method for Particulate Contamination in Middle Distillate Fuels by

Laboratory Filtration”

Branch Technical Position (BTP) APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear 

Power Plants"

BS 8007, Design of Concrete Structures for Retaining Aqueous Fluids,” British Standards 

Institution, London, 1987

Bulletin 80-11, “Masonry Wall Design,” May 1980

Bulletin 88-08, “Thermal Stresses in Piping Connected to Reactor Cooling Systems,” June 1988
D-3

Bulletin 88-09, “Thimble Tube Thinning in Westinghouse Reactors,” July 1988

Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification,” December 1988

Chemical Resistance of Plastics and Elastomers (3rd Electronic Edition), Plastics Design 

Library Staff

Combustion Engineering Owner’s Group (CEOG) Report CE NPSD 1039, Revision 2, “Best 

Estimate Cu and Ni Values in CE Fabricated Reactor Vessel Welds.” 

Crane Manufacturers Association of America, Inc. Specification No. 70, “Specifications for 

Electric Overhead Traveling Cranes”

Derun, et al, “Utilization of Boric Acid Wastes as an additive in Lightweight Concrete,” 

Proceedings of the 8th International Conference on Environmental Science and Technology, 

Lemnos Island, Greece, September 8–10, 2003Electric Overhead Crane Institute (EOCI) 

Design Specification No. 61, “Electric Overhead Crane Institute (EOCI) Specification for Electric 

Overhead Traveling Cranes,”

Environmental Protection Agency (EPA) Publication 20T-2003, “Managing Asbestos in Place –

A Building Owner’s Guide to Operations and Maintenance Programs for Asbestos-Containing 

Materials,” July 1990”

EPRI NP-5067, “Good Bolting Practices, A Reference Manual for Nuclear Power Plant 

Personnel,” Volumes 1 and 2

EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants”

EPRI TR-104213, ““Nuclear Maintenance Applications Center: Assembling Gasketed, Flanged 

Bolted Joints,” December 2007

EPRI TR-105714, Revision 6, “PWR Primary Water Chemistry Guidelines”

EPRI TR-102134, Revision 7, “PWR Secondary Water Chemistry Guidelines”

EPRI TR-103834-P1-2, “Effects of Moisture on the Life of Power Plant Cables, Electric Power,”

August 1994

EPRI TR-106092, “Evaluation of Thermal Aging Embrittlement for Cast Austenitic Stainless 

Steel Components in LWR Reactor Coolant Systems,” January 1998

EPRI TR-107514, “Age-Related Degradation Inspection Method and Demonstration: In Behalf 

of Calvert Cliffs Nuclear Power Plant License Renewal Application”

EPRI TR-109619, “Guideline for the Management of Adverse Localized Equipment 

Environments”

EPRI TR-112657, “Revised Risk Informed Inservice Evaluation Procedure”

EPRI TR-1000701, “Interim Thermal Fatigue Management Guideline (MRP-24),” January 2001

EPRI TR-1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR107396, Closed Cooling Water Chemistry Guideline” April 2004

EPRI TR-1008224, “Pressurized Water Reactor Secondary Water Chemistry Guidelines –

Revision 6”, December 2004

EPRI TR-1010087, “Materials Reliability Program: Primary System Piping Butt Weld Inspection 

and Evaluation Guideline (MRP-139),” August 2005

EPRI TR-1011955, “Materials Reliability Program: Management of Thermal Fatigue in Normally 

Stagnant Non-Isolable Reactor Coolant System Branch Lines,” June 2005
D-4

EPRI TR-1012017, “Materials Reliability Program: Guidelines for Addressing Fatigue 

Environmental Effects in a License Renewal Application (MRP-47 Revision 1),”September 2005

EPRI TR-1016456, “Recommendations for an Effective Program to Control the Degradation of 

Buried Pipe,” December 2008

EPRI TR-1019168, “Boric Acid Attack of Concrete and Reinforcing Steel in PWR Fuel 

Buildings,” June 2009

EPRI 1007820, “Closed Cooling Water Chemistry Guideline, Revision 1”

EPRI 1007932, “Identification and Detection of Aging Issues,”

EPRI 100793, “Aging Assessment Field Guide,”

EPRI 1009743, “Aging Identification and Assessment Checklists for Mechanical Components.”

Generic Letter (GL) 84-24, “Certification of Compliance to 10 CFR 50.49, Environmental 

Qualification of Electric Equipment Important to Safety for Nuclear Power Plants,” December 27, 

1984

GL 88-14, “Instrument Air Supply System Problems Affecting Safety-Related Equipment,” 

August 8, 1988

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 18, 1989

GL 91-17, “Generic Safety Issue 29, ‘Bolting Degradation or Failure in Nuclear Power Plants’," 

October 17, 1991

GL 97-06, “Degradation of Steam Generator Internals”

GL 98-04, “Potential for Degradation of the Emergency Core Cooling System and the 

Containment Spray System After a Loss-of-Coolant Accident Because of Construction and 

Protective Coating Deficiencies and Foreign Material in Containment,” July 14, 1998

GL 2007-01, “Inaccessible or Underground Power Cable Failures that Disable Accident 

Mitigation Systems or Cause Plant Transients” 

Generic Safety Issue 29, “Bolting Degradation or Failure in Nuclear Power Plants”

General Safety Issue 190, “Fatigue Evaluation of Metal Components for 60-Year Plant Life”

Hu, et al, “Factors Contributing to the Failure of Asbestos Cement Water Mains,” Canadian 

Journal of Civil Engineering, May 1, 2007

Huo, et al, “Study on the Behavior and Durability of Reinforced Concrete in Boric Acid 

Environment,” in Advances in Concrete and Structures, Key Engineering Materials, online 

October, 2008

Institute of Electrical and Electronic Engineers (IEEE) Std P1205, “IEEE Guide for Assessing, 

Monitoring and Mitigating Aging Effects on Class IE Equipment Used in Nuclear Power 

Generating Stations”

IEEE 344 1975 “Recommended Practice for Seismic Qualification of Class 1E Equipment for 

Nuclear Power Generating Stations”

Information Notice 86-99, “Degradation of Steel Containments,” December 8, 1986

IN 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response to IE 

Bulletin 80-11,” December 31, 1987
D-5

IN 88-82, “Torus Shells with Corrosion and Degraded Coatings in BWR Containments,” 

May 2, 1989

IN 89-79, “Degraded Coatings and Corrosion of Steel Containment Vessels,” December 1, 1989

IN 90-04, “Cracking of the Upper Shell-to-Transition Cone Girth Welds in Steam Generators,” 

January 26, 1990

IN 91-19, “Steam Generator Feedwater Distribution Piping Damage,” March 12, 1991

IN 94-59, “Accelerated De-alloying of Cast Aluminum-Bronze Valves Caused by 

Microbiologically-Induced Corrosion,” August 17, 1994

IN 97-10, “Liner Plate Corrosion in Concrete Containments,” March 13, 1997

IN 2004-09, “Corrosion of Steel Containment and Containment Liner,” April 27, 2004

IN 2009-02, “Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine Performance”

IN 2009-04, “Age-Related Constant Support Dedgradation,” February 18, 2009

IN 2010-12, “Containment Liner Corrosion,” June 18, 2010

License Renewal Application, Seabrook Station Plant, Unit 1, May 25, 2010.

License Renewal Interim Staff Guidance (LR-ISG)-19B, “Nickel-Alloy Components in the 

Reactor Coolant Pressure Boundary”

LR-ISG-2007-02, “Changes to Generic Aging Lesson Learned (GALL) Report Aging 

Management Program (AMP) XI.E6, ‘Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements’”

LR-ISG-2009-01, “Aging Management of Spent Fuel Pool Neutron-Absorbing Materials Other 

Than Boraflex”

LR-ISG-2011-05, “Ongoing Review of Operating Experience.”

Materials Reliability Program (MRP)-146, “Materials Reliability Program: Management of 

Thermal Fatigue in Normally Stagnant Non-Isolable Reactor Coolant System Branch Lines.”

MRP-227, “Material Reliability Program: Pressurized Water Reactor Internals Inspection and 

Evaluation Guidelines.”

MRP-24, “Interim Thermal Fatigue Management Guideline.”

Metha, H. S. and Goeeslin, S. R., “Environmental Factor Approach to Account for Water Effects 

in Pressure Vessel and Piping Fatigue Evaluations,” Nuclear Engineering and Design, 1998

MSS SP 66, “Pressure-Temperature Ratings for Steel Butt-Welding End Valves ,” January 1964 

(Withdrawn- Replaced by ASME B16.34)

National Fire Protection Association (NFPA) 25, “Standard for the Inspection, Testing, and 

Maintenance of Water-Based Fire Protection Systems,” January 2008

NFPA 780,“ Standard for the Installation of Lightning Protection Systems” January 2008

NFPA Standard 1962, “Standard for the Inspection, Care, and Use of Fire Hose, Couplings, and 

Nozzles and the Service Testing of Fire Hose,” December 2007

National Institute for Building Science, “Guidance Manual, Asbestos Operations & Maintenance 

Work Practices,” 2nd Edition
D-6

Nuclear Energy Institute (NEI) 94-01, “Industry Guideline for Implementing Performance-Based 

Option of 10 CFR Part 50 Appendix J”

NEI 95-10, Revision 6, “Industry Guideline for Implementing the Requirements of 10 CFR Part 

54 - The License Renewal Rule” 

NEI 97-06, “Steam Generator Program Guidelines”

NEI 03-08, “Guideline for the Management of Materials Issues”

Nuclear Safety Analysis Center (NSAC)-202L-R2, “Recommendations for an Effective FlowAccelerated Corrosion Program,” April 1999

NSAC-202L-R3, “Recommendations for an Effective Flow-Accelerated Corrosion Program,” 

May 2006

NUMARC 93-01, “Industry Guidelines for Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants,” Revision 2

NUREG-0313, “Technical Report on Material Selection And Processing Guidelines for BWR 

Coolant Pressure Boundary Piping,” August 1977

NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants,” July 1980

NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, Units 1 

and 2,” dated March 1983

NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, Units 1 

and 2,” Supplement 4, dated May 1986

NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, Units 1 

and 2,” Supplement 5, dated July 1986

NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, Units 1 

and 2,” Supplement 6, dated October 1986

NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, Units 1 

and 2,” Supplement 7, dated October 1987

NUREG-0896, “Safety Evaluation Report related to the operation of Seabrook Station, Units 1 

and 2,” Supplement 8, dated May 1989

NUREG-0800, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear 

Power Plants,” November 1975

NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants,” June 1990

NUREG-1431, “Standard Technical Specifications for Westinghouse Pressurized Water 

Reactors”

NUREG-1800, Revision 1, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants,” September 2005

NUREG-1801, Revision 1, “Generic Aging Lessons Learned (GALL) Report, “September 2005

NUREG/CR-5643, “Insights Gained From Aging Research,” March 1992

NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of 

Austenitic Stainless Steels,” April 1999
D-7

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components,” February 1995

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