Safety Evaluation Report

Related to the License Renewal 

of Hope Creek Generating 

Station

Docket Number 50-354

PSEG Nuclear, LLC

Office of Nuclear Reactor Regulation

NUREG-2102
AVAILABILITY OF REFERENCE MATERIALS

IN NRC PUBLICATIONS

NRC Reference Material

As of November 1999, you may electronically access 

NUREG-series publications and other NRC records at 

NRC=s Public Electronic Reading Room at 

http://www.nrc.gov/reading-rm.html. 

Publicly released records include, to name a few, 

NUREG-series publications; Federal Register notices; 

applicant, licensee, and vendor documents and 

correspondence; NRC correspondence and internal 

memoranda; bulletins and information notices; 

inspection and investigative reports; licensee event 

reports; and Commission papers and their 

attachments.

NRC publications in the NUREG series, NRC 

regulations, and Title 10, Energy, in the Code of 

Federal Regulations may also be purchased from one 

of these two sources.

1. The Superintendent of Documents

 U.S. Government Printing Office

 Mail Stop SSOP

 Washington, DC 20402B0001

 Internet: bookstore.gpo.gov

 Telephone: 202-512-1800

 Fax: 202-512-2250

2. The National Technical Information Service

 Springfield, VA 22161B0002

 www.ntis.gov 

 1B800B553B6847 or, locally, 703B605B6000

A single copy of each NRC draft report for comment is 

available free, to the extent of supply, upon written 

request as follows:

Address: U.S. Nuclear Regulatory Commission 

 Office of Administration

 Publications Branch 

 Washington, DC 20555-0001

E-mail: DISTRIBUTION.SERVICES@NRC.GOV

Facsimile: 301B415B2289 

Some publications in the NUREG series that are 

posted at NRC=s Web site address 

http://www.nrc.gov/reading-rm/doc-collections/nuregs

are updated periodically and may differ from the last 

printed version. Although references to material found 

on a Web site bear the date the material was 

accessed, the material available on the date cited may 

subsequently be removed from the site.

Non-NRC Reference Material

Documents available from public and special technical 

libraries include all open literature items, such as 

books, journal articles, and transactions, Federal 

Register notices, Federal and State legislation, and 

congressional reports. Such documents as theses, 

dissertations, foreign reports and translations, and

non-NRC conference proceedings may be purchased 

from their sponsoring organization.

Copies of industry codes and standards used in a 

substantive manner in the NRC regulatory process are 

maintained atC

The NRC Technical Library 

Two White Flint North

11545 Rockville Pike

Rockville, MD 20852B2738 

These standards are available in the library for 

reference use by the public. Codes and standards are 

usually copyrighted and may be purchased from the 

originating organization or, if they are American 

National Standards, fromC

American National Standards Institute

11 West 42nd Street

New York, NY 10036B8002

www.ansi.org 

212B642B4900

Legally binding regulatory requirements are stated only 

in laws; NRC regulations; licenses, including technical 

specifications; or orders, not in 

NUREG-series publications. The views expressed in 

contractor-prepared publications in this series are not 

necessarily those of the NRC.

The NUREG series comprises (1) technical and 

administrative reports and books prepared by the staff 

(NUREGBXXXX) or agency contractors 

(NUREG/CRBXXXX), (2) proceedings of conferences 

(NUREG/CPBXXXX), (3) reports resulting from 

international agreements (NUREG/IABXXXX), (4) 

brochures (NUREG/BRBXXXX), and (5) compilations 

of legal decisions and orders of the Commission and 

Atomic and Safety Licensing Boards and of Directors=

decisions under Section 2.206 of NRC=s regulations 

(NUREGB0750).
Safety Evaluation Report

Related to the License Renewal 

of Hope Creek Generating 

Station

Docket Number 50-354

PSEG Nuclear, LLC

Manuscript Completed: June 2011

Date Published: June 2011

Office of Nuclear Reactor Regulation

NUREG-2102

 iii 

ABSTRACT 

This safety evaluation report (SER) documents the technical review of the Hope Creek 

Generating Station (HCGS), license renewal application (LRA) by the U.S. Nuclear Regulatory 

Commission (NRC) staff (the staff). By letter dated August 18, 2009, PSEG Nuclear, LLC 

(PSEG or 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.” PSEG requests renewal of the operating license (Facility Operating License 

Number NPF-57) for a period of 20 years beyond the current expiration at midnight April 11, 

2026. 

HCGS is located approximately 40 miles from Philadelphia, Pennsylvania, and 8 miles from 

Salem, New Jersey. The NRC issued the construction permit on November 4, 1974, and the 

operating license for HCGS on July 25, 1986. The unit is a Mark 1 boiling-water reactor design. 

General Electric Company supplied the nuclear steam supply system, and Bechtel Power 

Corporation and Bechtel Construction originally designed and constructed the balance of plant 

aspects. The licensed power output of the unit is 3,840 megawatt thermal with a gross electrical 

output of approximately 1,268 megawatt electric. 

This SER presents the status of the staff’s review of information submitted through 

May 19, 2011, the cutoff date for consideration in this SER. The staff did not identify any open 

items before the staff made a final determination. SER Section 6.0 provides the staff’s final 

conclusion of the LRA review. 

 v 

TABLE OF CONTENTS 

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

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

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

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

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

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

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

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

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

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

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

1.5 Summary of the Open Item ............................................................................... 1-7

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

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

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 Information Sources Used for Scoping and Screening ............................ 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 ............................... 2-6

2.1.3.3 Training ........................................................................................... 2-7

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

2.1.4 Plant Systems, Structures, and Components Scoping Methodology ...... 2-8

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) ............... 2-8

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) ............. 2-12

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) ............. 2-15

2.1.4.4 Plant-Level Scoping of Systems and Structures .......................... 2-18

2.1.4.5 Mechanical Component Scoping .................................................. 2-19

2.1.4.6 Structural Scoping ........................................................................ 2-21

2.1.4.7 Electrical Component Scoping ..................................................... 2-21

2.1.4.8 Scoping Methodology Conclusion ................................................ 2-22

2.1.5 Screening Methodology ......................................................................... 2-22

2.1.5.1 General Screening Methodology .................................................. 2-22

2.1.5.2 Mechanical Component Screening ............................................... 2-24

2.1.5.3 Structural Component Screening ................................................. 2-25

2.1.5.4 Electrical Component Screening .................................................. 2-26

2.1.5.5 Screening Methodology Conclusion ............................................. 2-27

2.1.6 Summary of Evaluation Findings ........................................................... 2-27

2.2 Plant-Level Scoping Results ............................................................................ 2-28

2.2.1 Introduction ............................................................................................ 2-28

2.2.2 Summary of Technical Information in the Application ........................... 2-28

2.2.3 Staff Evaluation ..................................................................................... 2-28
Table of Contents 

 vi 

2.2.4 Conclusion ............................................................................................. 2-29

2.3 Scoping and Screening Results: Mechanical Systems ................................... 2-30

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ...................... 2-31

2.3.1.1 Control Rods ................................................................................. 2-31

2.3.1.2 Fuel Assemblies ........................................................................... 2-32

2.3.1.3 Nuclear Boiler Instrumentation ..................................................... 2-32

2.3.1.4 Reactor Internals .......................................................................... 2-33

2.3.1.5 Reactor Pressure Vessel .............................................................. 2-34

2.3.1.6 Reactor Recirculation System ...................................................... 2-34

2.3.2 Engineered Safety Features .................................................................. 2-35

2.3.2.1 Automatic Depressurization System ............................................. 2-35

2.3.2.2 Containment Hydrogen Recombiner System ............................... 2-36

2.3.2.3 Core Spray System ...................................................................... 2-37

2.3.2.4 Filtration, Recirculation, and Ventilation System .......................... 2-38

2.3.2.5 High Pressure Coolant Injection System ...................................... 2-39

2.3.2.6 Hydrogen and Oxygen Analyzer System ...................................... 2-39

2.3.2.7 Reactor Core Isolation Cooling System ........................................ 2-40

2.3.2.8 Residual Heat Removal System ................................................... 2-41

2.3.2.9 Vacuum Relief Valve System ....................................................... 2-42

2.3.3 Auxiliary Systems .................................................................................. 2-43

2.3.3.1 Chilled Water System ................................................................... 2-44

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

2.3.3.3 Compressed Air System ............................................................... 2-46

2.3.3.4 Containment Inerting and Purging System ................................... 2-46

2.3.3.5 Control Area Chilled Water System .............................................. 2-47

2.3.3.6 Control Rod Drive System ............................................................ 2-49

2.3.3.7 Control Room and Control Area HVAC Systems ......................... 2-49

2.3.3.8 Cranes and Hoists ........................................................................ 2-50

2.3.3.9 Equipment and Floor Drainage System ........................................ 2-51

2.3.3.10 Fire Protection System ............................................................... 2-51

2.3.3.11 Fire Pump House Ventilation System ......................................... 2-61

2.3.3.12 Fresh Water Supply System ....................................................... 2-61

2.3.3.13 Fuel Handling and Storage System ............................................ 2-62

2.3.3.14 Fuel Pool Cooling and Cleanup System ..................................... 2-62

2.3.3.15 Hardened Torus and Vent System ............................................. 2-64

2.3.3.16 Hydrogen Water Chemistry System ........................................... 2-64

2.3.3.17 Leak Detection and Radiation Monitoring System ...................... 2-65

2.3.3.18 Makeup Demineralizer System ................................................... 2-66

2.3.3.19 Primary Containment Instrument Gas System ........................... 2-67

2.3.3.20 Primary Containment Leakage Rate Testing System ................. 2-67

2.3.3.21 Process and Post-Accident Sampling Systems .......................... 2-68

2.3.3.22 Radwaste System ....................................................................... 2-69

2.3.3.23 Reactor Building Ventilation System .......................................... 2-70

2.3.3.24 Reactor Water Cleanup System ................................................. 2-71

2.3.3.25 Remote Shutdown Panel Room HVAC System ......................... 2-72

2.3.3.26 Service Water Intake Ventilation System ................................... 2-72

2.3.3.27 Service Water System ................................................................ 2-73

2.3.3.28 Standby Diesel Generator Area Ventilation Systems ................. 2-73

2.3.3.29 Standby Diesel Generator and Auxiliary Systems ...................... 2-74

2.3.3.30 Standby Liquid Control System .................................................. 2-75

2.3.3.31 Torus Water Cleanup System .................................................... 2-75
Table of Contents 

 vii 

2.3.3.32 Traversing Incore Probe System ................................................ 2-76

2.3.4 Steam and Power Conversion Systems ................................................ 2-77

2.3.4.1 Condensate Storage and Transfer System .................................. 2-77

2.3.4.2 Feedwater System ........................................................................ 2-78

2.3.4.3 Main Condenser System .............................................................. 2-79

2.3.4.4 Main Steam System ..................................................................... 2-79

2.4 Scoping and Screening Results: Structures .................................................... 2-81

2.4.1 Auxiliary Boiler Building ......................................................................... 2-82

2.4.1.1 Summary of Technical Information in the Application .................. 2-82

2.4.1.2 Conclusion .................................................................................... 2-82

2.4.2 Auxiliary Building Control and Diesel Generator Area ........................... 2-82

2.4.2.1 Summary of Technical Information in the Application .................. 2-82

2.4.2.2 Staff Evaluation ............................................................................ 2-83

2.4.2.3 Conclusion .................................................................................... 2-83

2.4.3 Auxiliary Building Service and Radwaste Area ...................................... 2-84

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

2.4.3.2 Staff Evaluation ............................................................................ 2-84

2.4.3.3 Conclusion .................................................................................... 2-85

2.4.4 Component Supports Commodity Group .............................................. 2-85

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

2.4.4.2 Conclusion .................................................................................... 2-86

2.4.5 Fire Water Pump House ........................................................................ 2-86

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

2.4.5.2 Conclusion .................................................................................... 2-86

2.4.6 Piping and Component Insulation Commodity Group ........................... 2-86

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

2.4.6.2 Conclusion .................................................................................... 2-87

2.4.7 Primary Containment ............................................................................. 2-87

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

2.4.7.2 Staff Evaluation ............................................................................ 2-88

2.4.7.3 Conclusion .................................................................................... 2-91

2.4.8 Reactor Building .................................................................................... 2-91

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

2.4.8.2 Conclusion .................................................................................... 2-92

2.4.9 Service Water Intake Structures ............................................................ 2-92

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

2.4.9.2 Conclusion .................................................................................... 2-93

2.4.10 Shoreline Protection and Dike ............................................................. 2-93

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

2.4.10.2 Conclusion .................................................................................. 2-94

2.4.11 Switchyard ........................................................................................... 2-94

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

2.4.11.2 Conclusion .................................................................................. 2-94

2.4.12 Turbine Building .................................................................................. 2-95

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

2.4.12.2 Conclusion .................................................................................. 2-96

2.4.13 Yard Structures ................................................................................... 2-96

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

2.4.13.2 Conclusion .................................................................................. 2-99

2.5 Scoping and Screening Results: Electrical and Instrumentation and 

Controls Systems .................................................................................................. 2-100
Table of Contents 

 viii 

2.5.1 Electrical and Instrumentation and Controls Component 

Commodity Groups ............................................................................ 2-100

2.5.1.1 Summary of Technical Information in the Application ................ 2-100

2.5.1.2 Staff Evaluation .......................................................................... 2-101

2.5.1.3 Conclusion .................................................................................. 2-102

2.6 Conclusion for Scoping and Screening ......................................................... 2-102

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

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

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

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

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

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

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

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

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

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

3.0.3 Aging Management Programs ................................................................. 3-6

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

3.0.3.2 AMPs That Are Consistent with the GALL Report with 

Exceptions or Enhancements ....................................................... 3-69

3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in 

the GALL Report ........................................................................ 3-160

3.0.4 Quality Assurance Program Attributes Integral to Aging 

Management Programs ...................................................................... 3-198

3.0.4.1 Summary of Technical Information in Application ...................... 3-198

3.0.4.2 Staff Evaluation .......................................................................... 3-198

3.0.5 Conclusion ........................................................................................... 3-199

3.1 Aging Management of Reactor Vessel, Internals, and Reactor 

Coolant Systems ................................................................................................... 3-200

3.1.1 Summary of Technical Information in the Application ......................... 3-200

3.1.2 Staff Evaluation ................................................................................... 3-200

3.1.2.1 AMR Results That Are Consistent with the GALL Report .......... 3-220

3.1.2.2 AMR Results That Are Consistent with the GALL Report, 

for Which Further Evaluation is Recommended ......................... 3-232

3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed 

in the GALL Report ..................................................................... 3-250

3.1.3 Conclusion ........................................................................................... 3-253

3.2 Aging Management of Engineered Safety Features ...................................... 3-254

3.2.1 Summary of Technical Information in the Application ......................... 3-254

3.2.2 Staff Evaluation ................................................................................... 3-254

3.2.2.1 AMR Results That Are Consistent with the GALL Report .......... 3-264

3.2.2.2 AMR Results That Are Consistent with the GALL Report, 

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

3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed 

in the GALL Report ..................................................................... 3-281

3.2.3 Conclusion ........................................................................................... 3-285

3.3 Aging Management of Auxiliary Systems ...................................................... 3-286

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

3.3.2 Staff Evaluation ................................................................................... 3-287

3.3.2.1 AMR Results That Are Consistent with the GALL Report .......... 3-305
Table of Contents 

 ix 

3.3.2.2 AMR Results That Are Consistent with the GALL Report, 

for Which Further Evaluation is Recommended ......................... 3-327

3.3.2.3 AMR Results That Are Not Consistent with or Not Addressed 

in the GALL Report ..................................................................... 3-354

3.3.3 Conclusion ........................................................................................... 3-378

3.4 Aging Management of Steam and Power Conversion Systems .................... 3-379

3.4.1 Summary of Technical Information in the Application ......................... 3-379

3.4.2 Staff Evaluation ................................................................................... 3-379

3.4.2.1 AMR Results That Are Consistent with the GALL Report .......... 3-386

3.4.2.2 AMR Results That Are Consistent with the GALL Report, 

for Which Further Evaluation is Recommended ......................... 3-390

3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed 

in the GALL Report ..................................................................... 3-400

3.4.3 Conclusion ........................................................................................... 3-404

3.5 Aging Management of Containments, Structures, and Component 

Supports ................................................................................................................ 3-405

3.5.1 Summary of Technical Information in the Application ......................... 3-405

3.5.2 Staff Evaluation ................................................................................... 3-405

3.5.2.1 AMR Results That Are Consistent with the GALL Report .......... 3-419

3.5.2.2 AMR Results That Are Consistent with the GALL Report, 

for Which Further Evaluation Is Recommended ......................... 3-437

3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed 

in the GALL Report ..................................................................... 3-460

3.5.3 Conclusion ........................................................................................... 3-481

3.6 Aging Management of Electrical and Instrumentation and Control ............... 3-483

3.6.1 Summary of Technical Information in the Application ......................... 3-483

3.6.2 Staff Evaluation ................................................................................... 3-483

3.6.2.1 AMR Results That Are Consistent with the GALL Report .......... 3-487

3.6.2.2 AMR Results That Are Consistent with the GALL Report, 

for Which Further Evaluation is Recommended ......................... 3-488

3.6.2.3 AMR Results That Are Not Consistent with or Not Addressed 

in the GALL Report ..................................................................... 3-493

3.6.3 Conclusion ........................................................................................... 3-495

3.7 Conclusion for Aging Management Review Results ...................................... 3-495

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 ....................................................................................... 4-3

4.1.3 Conclusion ............................................................................................... 4-3

4.2 Neutron Embrittlement of the Reactor Pressure Vessel and Internals .............. 4-4

4.2.1 Neutron Fluence ...................................................................................... 4-5

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

4.2.1.2 Staff Evaluation .............................................................................. 4-5

4.2.1.3 UFSAR Supplement ....................................................................... 4-6

4.2.1.4 Conclusion ...................................................................................... 4-6

4.2.2 Reactor Pressure Vessel Materials Upper-Shelf Energy Reduction 

Due to Neutron Embrittlement ................................................................ 4-6

4.2.2.1 Summary of Technical Information in the Application .................... 4-6

4.2.2.2 Staff Evaluation .............................................................................. 4-6

4.2.2.3 UFSAR Supplement ....................................................................... 4-7
Table of Contents 

 x 

4.2.2.4 Conclusion ...................................................................................... 4-7

4.2.3 Adjusted Reference Temperature for Reactor Pressure Vessel 

Materials Due to Neutron Embrittlement ................................................ 4-7

4.2.3.1 Summary of Technical Information in the Application .................... 4-7

4.2.3.2 Staff Evaluation .............................................................................. 4-8

4.2.3.3 UFSAR Supplement ....................................................................... 4-8

4.2.3.4 Conclusion ...................................................................................... 4-8

4.2.4 Reactor Pressure Vessel Analyses: Pressure-Temperature Limits ......... 4-8

4.2.4.1 Summary of Technical Information in the Application .................... 4-8

4.2.4.2 Staff Evaluation .............................................................................. 4-9

4.2.4.3 UFSAR Supplement ....................................................................... 4-9

4.2.4.4 Conclusion ...................................................................................... 4-9

4.2.5 Reactor Pressure Vessel Circumferential Weld Examination Relief ..... 4-10

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

4.2.5.2 Staff Evaluation ............................................................................ 4-10

4.2.5.3 UFSAR Supplement ..................................................................... 4-11

4.2.5.4 Conclusion .................................................................................... 4-12

4.2.6 Reactor Pressure Vessel Axial Weld Failure Probability ....................... 4-12

4.2.6.1 Summary of Technical Information in the Application .................. 4-12

4.2.6.2 Staff Evaluation ............................................................................ 4-12

4.2.6.3 UFSAR Supplement ..................................................................... 4-12

4.2.6.4 Conclusion .................................................................................... 4-13

4.2.7 Reactor Pressure Vessel Core Reflood Thermal Shock Analysis ......... 4-13

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

4.2.7.2 Staff Evaluation ............................................................................ 4-13

4.2.7.3 UFSAR Supplement ..................................................................... 4-14

4.2.7.4 Conclusion .................................................................................... 4-14

4.2.8 Reactor Internals Components .............................................................. 4-14

4.2.8.1 Summary of Technical Information in the Application .................. 4-14

4.2.8.2 Staff Evaluation ............................................................................ 4-14

4.2.8.3 UFSAR Supplement ..................................................................... 4-15

4.2.8.4 Conclusion .................................................................................... 4-15

4.3 Metal Fatigue of the Reactor Pressure Vessel, Internals, and Reactor 

Coolant Pressure Boundary Piping and Components ............................................. 4-16

4.3.1 Reactor Pressure Vessel Fatigue Analyses .......................................... 4-16

4.3.1.1 Summary of Technical Information in the Application .................. 4-16

4.3.1.2 Staff Evaluation ............................................................................ 4-17

4.3.1.3 UFSAR Supplement ..................................................................... 4-23

4.3.1.4 Conclusion .................................................................................... 4-23

4.3.2 Reactor Pressure Vessel Internals Fatigue Analyses ........................... 4-23

4.3.2.1 Summary of Technical Information in the Application .................. 4-23

4.3.2.2 Staff Evaluation ............................................................................ 4-23

4.3.2.3 UFSAR Supplement ..................................................................... 4-25

4.3.2.4 Conclusion .................................................................................... 4-25

4.3.3 Reactor Coolant Pressure Boundary Piping and Component Fatigue 

Analyses ............................................................................................... 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 ..................................................................... 4-26

4.3.3.4 Conclusion .................................................................................... 4-26

4.3.4 Non-Class 1 Component Fatigue Analyses........................................... 4-27
Table of Contents 

 xi 

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

4.3.4.2 Staff Evaluation ............................................................................ 4-27

4.3.4.3 UFSAR Supplement ..................................................................... 4-28

4.3.4.4 Conclusion .................................................................................... 4-28

4.3.5 Effects of Reactor Coolant Environment on Fatigue Life of 

Components and Piping (Generic Safety Issue 190) ........................... 4-28

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

4.3.5.2 Staff Evaluation ............................................................................ 4-29

4.3.5.3 UFSAR Supplement ..................................................................... 4-38

4.3.5.4 Conclusion .................................................................................... 4-38

4.4 Environmental Qualification of Electrical Equipment ....................................... 4-39

4.4.1 Summary of Technical Information in the Application ........................... 4-39

4.4.2 Staff Evaluation ..................................................................................... 4-39

4.4.3 UFSAR Supplement .............................................................................. 4-40

4.4.4 Conclusion ............................................................................................. 4-40

4.5 Loss of Prestress in Concrete Containment Tendons ..................................... 4-41

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

4.5.2 Staff Evaluation ..................................................................................... 4-41

4.5.3 UFSAR Supplement .............................................................................. 4-41

4.5.4 Conclusion ............................................................................................. 4-41

4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analyses .................................................................................................................. 4-42

4.6.1 Fatigue Analysis of Primary Containment, Attached Piping, and 

Components ......................................................................................... 4-42

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

4.6.1.2 Staff Evaluation ............................................................................ 4-43

4.6.1.3 UFSAR Supplement ..................................................................... 4-43

4.6.1.4 Conclusion .................................................................................... 4-43

4.6.2 Primary Containment Process Penetrations and Bellows Fatigue 

Analysis ................................................................................................ 4-44

4.6.2.1 Summary of Technical Information in the Application .................. 4-44

4.6.2.2 Staff Evaluation ............................................................................ 4-44

4.6.2.3 UFSAR Supplement ..................................................................... 4-45

4.6.2.4 Conclusion .................................................................................... 4-45

4.6.3 Vent Line Bellows .................................................................................. 4-45

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

4.6.3.2 Staff Evaluation ............................................................................ 4-46

4.6.3.3 UFSAR Supplement ..................................................................... 4-46

4.6.3.4 Conclusion .................................................................................... 4-46

4.7 Other Plant-Specific Time Limited Aging Analyses ......................................... 4-47

4.7.1 Crane Load Cycle Limit ......................................................................... 4-47

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

4.7.1.2 Staff Evaluation ............................................................................ 4-47

4.7.1.3 UFSAR Supplement ..................................................................... 4-49

4.7.1.4 Conclusion .................................................................................... 4-49

4.7.2 Refueling Bellows Fatigue ..................................................................... 4-49

4.7.2.1 Summary of Technical Information in the Application .................. 4-49

4.7.2.2 Staff Evaluation ............................................................................ 4-50

4.7.2.3 UFSAR Supplement ..................................................................... 4-50

4.7.2.4 Conclusion .................................................................................... 4-50
Table of Contents 

 xii 

4.7.3 Neutron Fluence-Induced Bolt Stress Relaxation – Jet Pump 

Auxiliary Spring Wedges and Slip Joint Clamps ................................... 4-50

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

4.7.3.2 Staff Evaluation ............................................................................ 4-51

4.7.3.3 UFSAR Supplement ..................................................................... 4-52

4.7.3.4 Conclusion .................................................................................... 4-52

4.8 Conclusion for Time-Limited Aging Analyses .................................................. 4-52

SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

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

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

APPENDIX A HOPE CREEK GENERATING STATION LICENSE RENEWAL 

COMMITMENTS ........................................................................................................... A-1

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

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

APPENDIX D REFERENCES ..................................................................................... D-1
Table of Contents 

 xiii 

LIST OF TABLES 

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

Table 3.3.2-10 Fire Protection System ........................................................................ 2-54 

Table 2.3.3-10 Fire Protection System ........................................................................ 2-54 

Table 3.3.2-10 Fire Protection System ........................................................................ 2-55 

Table 2.3.3-7 Control Room and Control Area HVAC Systems .................................. 2-56 

Table 3.3.2-7 Control Room and Control Area HVAC Systems .................................. 2-57 

Table 2.3.3-10 Fire Protection System ........................................................................ 2-58 

Table 3.3.2-10 Fire Protection System ........................................................................ 2-58 

Table 3.3.2-10 Fire Protection System ........................................................................ 2-59 

Table 3.0.3-1 Hope Creek Generating Station Aging Management Programs ............. 3-7 

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

and Reactor Coolant System Components in the GALL Report ................................ 3-201 

Table 3.2-1 Staff Evaluation for Engineered Safety Features System 

Components in the GALL Report ............................................................................... 3-255 

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the 

GALL Report .............................................................................................................. 3-288 

Table 3.4-1 Staff Evaluation for Steam and Power Conversion System 

Components in the GALL Report ............................................................................... 3-380 

Table 3.5-1 Staff Evaluation for Containments, Structures, and Component 

Supports in the GALL Report ..................................................................................... 3-406 

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

in the GALL Report .................................................................................................... 3-484 

Table 4.3.5-1 Basis for Accepting Applicant EAF Analysis Locations ......................... 4-30 

 xv 

ABBREVIATIONS 

AC alternating current 

ACAR aluminum conductor, aluminum-alloyed reinforced 

ACI American Concrete Institute 

ACRS Advisory Committee on Reactor Safeguards 

ACSR aluminum conductor steel reinforced 

ADAMS Agencywide Document Access and Management System 

ADV atmospheric dump valve 

AERM aging effect requiring management 

AFW auxiliary feedwater 

AISC American Institute of Steel Construction 

AMP aging management program 

AMR aging management review 

ANSI American National Standards Institute 

ART adjusted reference temperature 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

ATWS anticipated transient without scram 

B&PV Boiler and Pressure Vessel 

B&W Babcock & Wilcox 

BMI bottom mounted instrumentation 

BOP balance of plant 

BTP branch technical position 

BWR boiling-water reactor 

BWRVIP Boiling Water Reactor Vessel and Internals Project 

CASS cast austenitic stainless steel 

CB&I Chicago Bridge and Iron 

CBF cycle-based fatigue 
Abbreviations 

 xvi 

CCW component cooling water 

CCCW closed-cycle cooling water 

CEA control element assembly 

CETNA core exit thermocouple nozzle assembly 

CFR Code of Federal Regulations 

CLB current licensing basis 

CMAA Crane Manufacturers Association of America 

CO2 carbon dioxide 

CRD control rod drive 

CRDM control rod drive mechanism 

CRGT control rod guide tube 

CS containment spray 

CST condensate storage tank 

Cu copper 

CUF cumulative usage factor 

CVCS chemical and volume control 

CVUSE Charpy upper-shelf energy 

CW circulating water 

DBA design-basis accident 

DBD design-basis document 

DBE design-basis event 

DC direct current 

EAF environmentally-assisted fatigue 

ECCS emergency core cooling system 

ECP electrochemical corrosion potential 

EDG emergency diesel generator 

EFPY effective full-power year 

EHC electro-hydraulic control 
Abbreviations 

 xvii 

EMA equivalent margin analysis 

EN shelter or protection 

EPRI Electric Power Research Institute 

EPU extended power uprate 

EQ environmental qualification 

ER Environmental Report (Applicant’s Environmental Report 

 Operating License Renewal Stage) 

ESF engineered safety features 

EVT enhanced visual testing 

FAC flow accelerated corrosion 

Fen environmental fatigue life correction factor 

FERC Federal Energy Regulatory Commission 

FLB flood barrier 

FLT filtration 

FMP Fatigue Monitoring Program 

FR Federal Register 

FRV feedwater regulating valve 

FRVS filtration, recirculation, and ventilation system 

ft-lb foot-pound 

FW feedwater 

FWST fire water storage tank 

GALL Generic Aging Lessons Learned Report 

GDC general design criteria or general design criterion 

GEIS Generic Environmental Impact Statement 

GL generic letter 

GSI generic safety issue 

H2 hydrogen 

HCGS Hope Creek Generating Station 
Abbreviations 

 xviii 

HELB high-energy line break 

HEPA high-efficiency particulate air 

HPCI high-pressure coolant injection

HPSI high-pressure safety injection 

HVAC heating, ventilation, and air conditioning 

HWC hydrogen water chemistry 

HX heat exchanger 

I&C instrumentation and controls 

IA instrument air 

IASCC irradiation-assisted stress-corrosion cracking 

ID inside diameter 

ID IGA inside diameter intergranular attack 

IEEE Institute of Electrical and Electronics Engineers 

IGA intergranular attack 

IGSCC intergranular stress-corrosion cracking 

ILRT integrated leak rate testing 

IN information notice 

INPO Institute of Nuclear Power Operations 

IPA integrated plant assessment 

ISG interim staff guidance 

ISI inservice inspection 

ISP integrated surveillance program 

ksi thousands of pounds per square inch 

KV or kV kilovolt 

LBB leak before break 

LCO Limited Condition Operation 

LLRT local leak-rate test 

LOCA loss of coolant accident 
Abbreviations 

 xix 

LPCI low-pressure coolant injection 

LPRM local power range monitor 

LRA license renewal application 

MB missile barrier 

MC metal containment 

MELB medium-energy line break 

MFW main feedwater 

Mg/L milligrams per liter 

MIC microbiologically-influenced corrosion 

MIRVSP master integrated reactor vessel surveillance program 

MOV motor-operated valve 

mph miles per hour 

MS main steam 

MSIP Mechanical Stress Improvement 

MSIV main steam isolation valve 

MWe megawatts-electric 

MWt megawatts-thermal 

n/cm2

 neutrons per square centimeter 

NDE nondestructive examination 

NEI Nuclear Energy Institute 

NESC National Electrical Safety Code 

NFPA National Fire Protection Association 

Ni nickel 

NMCA noble metals chemical addition 

NPS nominal pipe size 

NRC U.S. Nuclear Regulatory Commission 

NSAC Nuclear Safety Analysis Center 

NSSS nuclear steam supply system 
Abbreviations 

 xx 

NWC normal water chemistry 

O2 oxygen 

OBE operating basis earthquake 

OCCW open-cycle cooling water 

OD IGA outside-diameter intergranular attack 

ODSCC outside-diameter stress-corrosion cracking 

OI open item 

OTSG once-through steam generator 

P&ID piping and instrumentation diagram 

PAB primary auxiliary building 

PB pressure boundary 

PBD program basis document 

PDI Performance Demonstration Initiative 

pH potential of hydrogen 

PMH probable maximum hurricane 

PoF probability of failure 

PORV power-operated relief valve 

ppm parts per million 

PSEG PSEG Nuclear, LLC 

psi pounds per square inch 

PSPM periodic surveillance and preventive maintenance 

P-T pressure-temperature 

PTS pressurized thermal shock 

PUAR plant unique analysis report 

PVC polyvinyl chloride 

PW primary water makeup 

PWR pressurized water reactor 

PWSCC primary water stress-corrosion cracking 
Abbreviations 

 xxi 

QA quality assurance 

QAP quality assurance program 

RAI request for additional information 

RAMA Radiation Analysis Modeling Application 

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 

RI-ISI risk informed-inservice inspection 

RM radiation monitoring 

RO refueling outage 

RPV reactor pressure vessel 

RTNDT reference temperature nil-ductility transition 

RTPTS reference temperature for pressurized thermal shock 

RTD resistance temperature detector 

RV reactor vessel 

RVCH reactor vessel closure head 

RVI reactor vessel internal 

RVID Reactor Vessel Integrity Database 

RVLIS reactor vessel level indication system 

RW river water 

RWCU reactor water cleanup 

RWST refueling water storage tank 

SA stress allowable 

SACS safety auxiliaries cooling system 
Abbreviations 

 xxii 

Salem Salem Nuclear Generating Station 

SAP Systems, Applications, and Products in Data Processing 

SBF stress-based fatigue 

SBO station blackout 

SC structure and component 

SCC stress-corrosion cracking 

SE safety evaluation 

SER safety evaluation report 

SFP spent fuel pool 

SFPC spent fuel pit/pool cooling 

SG steam generator 

SGBD steam generator blowdown 

SHE standard hydrogen electrode 

SI safety injection 

SLC standby liquid control 

SMP structures monitoring program 

SO2 sulfur dioxide 

SOC statement of consideration 

SOV solenoid-operated valve 

SPU stretch power uprate 

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

 for Nuclear Power Plants 

SRV safety relief valve 

SSC system, structure, and component 

SSE safe-shutdown earthquake 

SSFS safety system function sheets 

SW service water 

TAN total acid number 

TBN total base number 

TIP transversing in-core probe 
Abbreviations 

 xxiii 

TLAA time-limited aging analysis 

TOC total organic carbon 

TS technical specification(s) 

TSC technical support center 

UFSAR updated final safety analysis report 

USE upper-shelf energy 

UT ultrasonic testing 

UV ultraviolet 

VCT volume control tank 

VFLD vessel flange leak detection 

VHP vessel head penetration 

VT visual testing 

Yr year 

Zn zinc 

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

 internal surface of the vessel 

 1-1 

SECTION 1 

INTRODUCTION AND GENERAL DISCUSSION 

1.1 Introduction 

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

Hope Creek Generating Station (HCGS), as filed by PSEG Nuclear, LLC (PSEG or the 

applicant). By letter dated August 18, 2009, PSEG submitted its application to the U.S. Nuclear 

Regulatory Commission (NRC) for renewal of the HCGS 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 Bennett M. 

Brady. Dr. Brady may be contacted by telephone at 301-415-2981 or by electronic mail at 

Bennett.Brady@nrc.gov. Alternatively, written correspondence may be sent to the following 

address: 

Division of License Renewal 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

Attention: Bennett M. Brady, Mail Stop O11-F1 

In its August 18, 2009, submission letter, the applicant requested renewal of the operating 

license issued under Section 103 (Operating License No. NPF-57) of the Atomic Energy Act 

of 1954, as amended, for a period of 20 years beyond the current expiration at midnight 

April 11, 2026. HCGS is located approximately 40 miles from Philadelphia, Pennsylvania, and 

8 miles from Salem, New Jersey. The NRC issued the construction permit on November 4, 

1974. The NRC issued the operating license for HCGS on July 25, 1986. The unit is a Mark 1 

boiling-water reactor (BWR) design. General Electric Company supplied the nuclear steam 

supply system, and Bechtel Power Corporation and Bechtel Construction originally designed 

and constructed the balance of plant aspects. The licensed power output of the unit is 

3,840 megawatt thermal with a gross electrical output of approximately 1,268 megawatt electric. 

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

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

issues and an environmental review. The NRC regulations in 10 CFR Part 54 and 

10 CFR Part 51, “Environmental Protection Regulations for Domestic Licensing and Related 

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

for the HCGS 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 in audits, meetings, and 

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

information submitted through May 19, 2011. 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), and at Salem Free Library, 112 West Broadway, Salem, 
Introduction and General Discussion 

 1-2 

NJ 08079. 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 

license. 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, and as part of the environmental review, the staff prepared 

a draft plant-specific supplement to NUREG-1437, “Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants (GEIS).” Issued separately from this SER, this 

supplement discusses the environmental considerations for the license renewal of HCGS along 

with those of Salem Nuclear Generating Station, Units 1 and 2. The staff issued the draft 

Supplement 45 to NUREG-1437 in October 2010. After considering comments on the draft, the 

staff published the final, plant-specific GEIS Supplement 45 in March 2011. 

1.2 License Renewal Background

Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating 

licenses for commercial power reactors are issued for 40 years and can be renewed for up to 20 

additional years. The original 40-year license term was selected on the basis of economic and 

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

equipment designs may have been engineered based on an expected 40-year service life. 

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

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

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

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

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

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

license renewal for nuclear power plants. 

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

page 64943, of the Federal Register (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 
Introduction and General Discussion 

 1-3 

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

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

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

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

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

on May 8, 1995, in Volume 60, page 22461, of the Federal Register (60 FR 22461), the 

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 (Volume 61, 

page 28467, of the Federal Register (61 FR 28467), dated 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 (NEPA). 

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 exception of 

the detrimental aging effects on the function 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 defines the scope of license renewal as 

including SSCs: (1) that are safety-related, (2) whose failure could affect safety-related 

functions, or (3) that are relied on to demonstrate compliance with NRC 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 are those which perform an intended function without moving parts or 

without a change in configuration or properties (i.e., are “passive”), and are not subject to 

replacement based on a qualified life or specified time period (i.e., are “long lived”). As required 

by 10 CFR 54.21(a), an applicant for a renewed license must demonstrate that aging effects will 

be managed in such a way that the intended function(s) of those SSCs will be maintained, 

consistent with the current licensing basis (CLB), for the period of extended operation; however, 

active equipment is considered adequately monitored and maintained by existing programs. In 

other words, detrimental aging effects that may affect active equipment are readily detectable 

and can be identified and corrected through routine surveillance, performance monitoring, and 
Introduction and General Discussion 

 1-4 

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), each LRA is required to include a UFSAR supplement that must 

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

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

operation. 

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

certain assumptions are made about the length of time the plant can operate. These 

assumptions are incorporated into design calculations for several plant SSCs. In accordance 

with 10 CFR 54.21(c)(1), the applicant must 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 effects of aging on these SSCs can be adequately managed for 

the period of extended operation. 

In 2005, the staff developed and issued 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 by the 

NEI. NEI 95-10 details an acceptable method of implementing the Rule. The staff also used 

the SRP-LR to review this application. 

In its LRA, the applicant stated that it used the process defined in NUREG-1801, “Generic Aging 

Lessons Learned (GALL) Report,” issued in July 2001 and subsequently revised in 

September 2005 and December 2010. The GALL Report provides a summary of staff-approved 

aging management programs (AMPs) for the aging of many SCs subject to an AMR. An 

applicant’s willingness to commit to implementing these staff-approved AMPs could potentially 

reduce the time, effort, and resources in reviewing an applicant’s LRA, and thereby, improve 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 SCs used throughout the industry. The report is also a reference for both 

applicants and staff reviewers to quickly identify AMPs and activities that can provide adequate 

aging management during the period of extended operation. 

1.2.2 Environmental Review 

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 the possible environmental impacts associated with renewing licenses of nuclear 

power plants. For certain types of environmental impacts, the GEIS establishes generic findings 

applicable to all nuclear power plants. These generic findings are codified in Appendix B to 

Subpart A of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), an applicant for license 

renewal may incorporate these generic findings in its environmental report. In accordance with 

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

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

In accordance with NEPA and the requirements of 10 CFR Part 51, the staff performed a 

plant-specific review of the environmental impacts of license renewal, including whether the 
Introduction and General Discussion 

 1-5 

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

staff held two public meetings on November 5, 2009, at the Salem County Emergency Services 

Building in Woodstown, New Jersey, to identify plant-specific environmental issues that might 

impact HCGS, or Salem Nuclear Generating Station, Units 1 and 2. The draft plant-specific 

GEIS Supplement 45, issued in October 2010, documents the results of the environmental 

review and includes a preliminary recommendation for the license renewal proposed action. 

Two public meetings were held on November 17, 2010, in Woodstown, New Jersey, to discuss 

the draft plant-specific GEIS Supplement 45. After considering comments on the draft, the staff 

published a final plant-specific GEIS supplement in March 2011. 

1.3 Principal Review Matters

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

plants. The staff performed its technical review of the LRA in accordance with NRC guidance 

and 10 CFR Part 54 requirements. Section 54.29 of 10 CFR sets forth the standards for 

renewing a license. This SER describes the results of the staff’s safety review. 

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

general information. The applicant provided this general information in LRA Section 1, which it 

submitted, by letter dated August 18, 2009. The staff reviewed LRA Section 1 and found that 

the applicant had submitted the information required by 10 CFR 54.19(a). 

In accordance with 10 CFR 54.19(b), the staff requires that each 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.” The applicant stated the following in LRA 

Section 1.1.10 on this issue: 

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

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

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

indemnity agreement (No. BX08-05) for Hope Creek states in Article VII that the 

agreement shall terminate at the time of expiration of that license specified in 

Item 3 of the Attachment to the agreement, which is the last to expire; provided 

that, except as may otherwise be provided in applicable regulations or orders of 

the Commission, the term of this agreement shall not terminate until all the 

radioactive material has been removed from the location and transportation of 

the radioactive material from the location has ended as defined in subparagraph 

5(b), Article I. Item 3 of the Attachment to the indemnity agreement includes 

license number NPR-57. Applicant requests that any necessary conforming 

changes be made to Article VII and Item 3 of the Attachment, and any other 

sections of the indemnity agreement as appropriate to ensure that the indemnity 

agreement continues to apply during both the terms of the current license and 

the terms of the renewed license. Applicant understands that no changes may 

be necessary for this purpose if the current license number is retained. 
Introduction and General Discussion 

 1-6 

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

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, the staff 

requires that each LRA contain: 

 (a) an integrated plant assessment (IPA) 

 (b) a description of any CLB changes during the staff’s review of the LRA 

 (c) an evaluation of TLAAs 

 (d) a UFSAR supplement 

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

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

10 CFR 54.21(d). 

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

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

applicant submit an LRA amendment identifying any CLB changes of the facility that materially 

affect the contents of the LRA, including the UFSAR supplement. The applicant fulfilled this 

requirement by a letter dated June 24, 2010 (Agencywide Document Access Management 

System (ADAMS) Accession No. ML101810073). 

In accordance with 10 CFR 54.22, the staff requires that an applicant’s LRA include changes or 

additions to the technical specifications necessary to manage aging effects during the period of 

extended operation. In LRA Section 1, the applicant stated the following: 

There were no Technical Specification Changes identified necessary to manage 

the effects of aging during the period of extended operation. 

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

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

document the staff’s evaluation of the technical information in the LRA. 

As required by 10 CFR 54.25, the ACRS will issue a report to document its evaluation of the 

staff’s LRA review and associated SER. SER Section 5 will incorporate the ACRS report once it 

is issued. SER Section 6 will document the findings required by 10 CFR 54.29. 

1.4 Interim Staff Guidance

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

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

address the NRC’s safety goal of ensuring adequate protection of public health and safety and 

the environment. Interim staff guidance (ISG) is documented for use by the staff, industry, and 

other interested stakeholders until incorporated into such license renewal guidance documents 

as the SRP-LR and the GALL Report. 

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

are addressed. 
Introduction and General Discussion 

 1-7 

Table 1.4-1 Current Interim Staff Guidance 

ISG Issue 

(Approved ISG No.)

Purpose SER Section

LR-ISG-2006-01 Plant-Specific Aging Management Program for 

Inaccessible Areas of Boiling Water Reactor 

Mark I Steel Containment Drywell Shell

3.0.3.2.14 and 3.5.2.2.1

LR-ISG-2007-02 Changes to Generic Aging Lessons Learned 

(GALL) Report Aging Management Program 

(AMP) XI.E6, “Electrical Cable Connections Not 

Subject to 10 CFR 50.49 Environmental 

Qualification Requirements”

3.0.3.2.18

LR-ISG-2009-01 Aging Management of Spent Fuel Pool 

Neutron-Absorbing Materials other than Boraflex 

3.0.3.3.5

1.5 Summary of the Open Item

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

May 19, 2011, the staff closed the one open item (OI), previously identified in the “Safety 

Evaluation Report with Open Items Related to the License Renewal of Hope Creek Generating 

Station” (ADAMS Accession No. ML102660148). This SER also reflects the closure of 

additional issues that arose since the issuance of the SER with OIs. 

During a refueling outage in October 2010, the applicant observed leakage in the drywell shell 

and found that the four air gap drains at the bottom of the drywell were blocked. Subsequent 

inspections by the applicant further discovered that the actual configuration of the air gap drains 

were unknown. This led the staff to issue a request for additional information (RAI) concerning 

the leakage and the applicant’s plans for resolving and repairing the blockage and leakage. The 

applicant addressed the staff’s concern as discussed in Section 3.0.3.2.14 of this SER. A 

license condition will also be issued for the applicant to establish drainage capability from the 

bottom of the drywell air gap. 

The staff also requested additional clarifications from the applicant regarding several programs. 

In response, HCGS provided additional information regarding the sampling sizes for the 

Selective Leaching of Materials, One-Time Inspection, and Small-Bore Class 1 Piping 

Inspection programs. The staff’s evaluations are documented in SER Sections 3.0.3.1.12, 

3.0.3.1.11, and 3.0.3.3.6, respectively. 

OI 3.0.3.2.12-1: (SER Section 3.0.3.2.12 - Buried Piping and Tanks Inspection Program) 

LRA Section B.2.1.24 describes the existing Buried Piping Inspection Program as consistent, 

with an enhancement, with GALL AMP XI.M34, “Buried Piping and Tanks Inspection.” The 

applicant stated that the program provides aging management of carbon steel, ductile cast iron, 

and gray cast iron buried piping susceptible to general corrosion, pitting, crevice corrosion, and 

microbiologically-influenced corrosion. The applicant also stated that the program relies on the 

visual inspection of excavated piping, including the associated coatings and wrappings. The 

applicant further stated that there are no buried tanks within the scope of license renewal. LRA 

Section B.2.2.4 describes the existing Buried Non-Steel Piping Inspection Program as a 

plant-specific program. The applicant stated that the Buried Non-Steel Piping Inspection 

Program is a condition monitoring program used to manage buried reinforced concrete piping 
Introduction and General Discussion 

 1-8 

and components in its service water system for cracking, loss of bond, increase in porosity and 

permeability, and loss of material. The Buried Non-Steel Piping Inspection Program also 

manages buried stainless steel piping and components in the condensate storage and transfer 

system and fire protection systems for loss of material. 

Given recent industry events involving leakage from buried or underground piping, the staff 

asked the applicant, by letter dated October 12, 2010, to address industry and plant-specific 

operating experience in its Buried Piping Inspection Program. In its October 29, 2010, 

response, the applicant provided the additional information to address the staff’s concern. The 

staff reviewed and accepted the applicant’s response, as documented in SER 

Sections 3.0.3.2.12 and 3.0.3.3.4. Open item OI 3.0.3.2.12-1 is closed. 

1.6 Summary of Confirmatory Items 

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

May 19, 2011, the staff closed two items that were previously confirmatory items (CIs) identified 

in the “Safety Evaluation Report with Open Items Related to the License Renewal of Hope 

Creek Generating Station” (ADAMS Accession No. ML102660148). An item is considered 

confirmatory if the staff and the applicant have reached a satisfactory resolution but the 

applicant has not yet formally submitted the resolution. 

CI 3.0.3.1.20-1: (SER Section 3.0.3.1.20 - Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements) 

LRA Section B.2.1.37 describes the new Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program as consistent with GALL 

AMP XI.E3, “Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements.” The applicant stated that its program manages inaccessible 

medium voltage cables that are exposed to significant moisture simultaneously with significant 

voltage. The applicant stated that significant moisture is defined as periodic exposure to 

moisture that lasts more than a few days (e.g., cable in standing water). The applicant also 

stated that significant voltage exposure is defined as being subject to system voltage for more 

than 25 percent of the time. 

During its review, the staff noted that recently identified industry operating experience has 

shown that the presence of water or moisture can be a contributing factor in inaccessible power 

cable failures at lower service voltages (480 volts (V) to 2 kilovolts (kV)). The applicant provided 

a commitment to expand the scope of the Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program to include cables at lower 

service voltages (480 V to 2 kV) and to eliminate the exclusion of cables not subject to system 

voltage for more than 25 percent of the time. In its responses dated September 7, 2010, and 

September 30, 2010, the applicant revised its Commitment No. 37 to expand the scope of this 

program to include cables at lower service voltages (480 V to 2 kV), to eliminate the exclusion of 

cables not subject to system voltage for more than 25 percent of the time and to conduct cable 

testing at least every 6 years and cable vault and manhole inspections at least every year. The 

staff reviewed and accepted the applicant’s response, as documented in SER Section 

3.0.3.1.20. Confirmatory item CI 3.0.3.1.20-1 is closed. 
Introduction and General Discussion 

 1-9 

CI 4.3.5.2-1: (SER Section 4.3.5 - Effects of Reactor Coolant Environment on Fatigue Life of 

Components and Piping (Generic Safety Issue 190)) 

LRA Section 4.3.5 summarizes the evaluation of the environmentally-assisted fatigue (EAF) 

analyses for the period of extended operation. This TLAA is based on the analysis in 

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components.” The applicant stated that the effects of the reactor coolant system 

environment on fatigue life were evaluated for certain representative components that are 

identified in NUREG/CR-6260 for newer vintage General Electric plants. 

As part of its analysis, the applicant identified plant-specific limiting locations per 

NUREG/CR-6260 and performed EAF calculations using guidance in NUREG/CR-6583, 

“Effects of LWR Coolant Environments on Fatigue Curves of Carbon and Low Alloy Steels,” for 

components made of carbon and low alloy steels and the guidance of NUREG/CR-5704, 

“Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless 

Steels,” for components made of austenitic stainless steel. The applicant dispositioned its TLAA 

for EAF analyses based on the criterion in 10 CFR 54.21(c)(1)(iii), with the intention to 

demonstrate that the effects of aging associated with the analysis will be adequately managed 

for the period of extended operation. 

During its review, the staff was concerned whether the applicant had verified that the limiting 

location per NUREG/CR-6260 were bounding as compared to other plant-specific locations 

(e.g., Feedwater Line No. AE-036, node 200/130) and requested confirmation from the 

applicant. 

By letter dated January 6, 2011, the applicant responded to Confirmatory item CI 4.3.5.2-1 to 

provide Commitment No. 54 and to address the staff’s concern. The staff reviewed and 

accepted the applicant’s response because the applicant will review its design-basis ASME 

Code Class 1 fatigue evaluations to determine whether 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. If more limiting locations are identified, the 

applicant will perform EAF analyses for the most limiting location. Also, Commitment No. 54 is 

consistent with the recommendations in SRP-LR Sections 4.3.2.2 and 4.3.3.2 and GALL 

AMP X.M1. Additional information is documented in SER Section 4.3.5. Confirmatory item 

CI 4.3.5.2-1 is closed. 

1.7 Summary of Proposed License Conditions

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

provided by the applicant, the staff identified four proposed license conditions. 

The first license condition requires the applicant to incorporate the UFSAR supplement required 

by 10 CFR 54.21(d) into the UFSAR following the issuance of the renewed license. 

The second license condition requires the applicant to complete the commitments in the UFSAR 

supplement and notify the NRC in writing when implementation of those activities required prior 

to the period of extended operation are complete and can be verified by NRC inspection. 
Introduction and General Discussion 

 1-10 

The third license condition requires the applicant to establish drainage capability from the 

bottom of the drywell air gap from all four quadrants. Until drainage is established, the applicant 

will perform boroscope examinations and ultrasonic thickness measurements during each 

refueling outage. The applicant will monitor penetration sleeve J13 daily for water leakage 

when the reactor cavity is flooded and will submit a report to the staff summarizing the results 

from the boroscope examinations, ultrasonic thickness measurements, and leakage detected 

from the penetration. 

The fourth license condition requires the applicant to submit a report when drainage has been 

established from the bottom of the air gap in all four quadrants. The applicant will also perform 

ultrasonic thickness measurements during the next three refueling outages and submit a report 

to the staff summarizing the results from the ultrasonic thickness measurements. 
 2-1 

SECTION 2 

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW 

2.1 Scoping and Screening Methodology

2.1.1 Introduction 

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

Regulations (10 CFR 54.21), requires that each license renewal application (LRA) must contain 

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 Hope Creek Generating Station (HCGS), that are 

within the scope of license renewal and the SCs that are subject to an AMR. The staff reviewed 

the scoping and screening methodology applied by PSEG Nuclear, LLC (the applicant) to 

determine whether 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 requirements of 10 CFR Part 54, “Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants” (the Rule), statements of consideration related to Nuclear 

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

of 10 CFR Part 54—The License Renewal Rule,” (NEI 95-10). Additionally, in developing this 

LRA methodology, the applicant stated that it considered the correspondence between the 

U.S. Nuclear Regulatory Commission (NRC), other applicants, and the NEI. 

2.1.2 Information Sources Used for Scoping and Screening 

In LRA Section 2, “Scoping and Screening Methodology for Identifying Structures and 

Components Subject to Aging Management Review, and Implementation Results,” and LRA 

Section 3, “Aging Management Review Results,” the applicant provides the technical 

information required by 10 CFR 54.4, “Scope,” and 10 CFR 54.21(a), “An Integrated Plant 

Assessment.” In LRA Section 2.1, the applicant described the process used to identify the 

SSCs that meet the license renewal scoping criteria as required by 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: 

 (a) LRA Section 2.2, “Plant Level Scoping Results” 

 (b) LRA Section 2.3, “Scoping and Screening Results: Mechanical” 
Structures and Components Subject to Aging Management Review 

 2-2 

 (c) LRA Section 2.4, “Scoping and Screening Results: Structures” 

 (d) LRA Section 2.5, “Scoping and Screening Results: Electrical and Instrumentation and 

Controls (I&C) Systems” 

In LRA Section 3.0, “Aging Management Review Results,” the applicant described its aging 

management results as follows: 

 (a) LRA Section 3.1, “Aging Management of Reactor Vessels, Internals, and Reactor 

Coolant System” 

 (b) LRA Section 3.2, “Aging Management of Engineered Safety Features” 

 (c) LRA Section 3.3, “Aging Management of Auxiliary Systems” 

 (d) LRA Section 3.4, “Aging Management of the Steam and Power Conversion System” 

 (e) LRA Section 3.5, “Aging Management of Containment, Structures and Component 

Supports” 

 (f) LRA Section 3.6, “Aging Management of Electrical and Instrumentation and Controls” 

In LRA Section 4.0, “Time-Limited Aging Analyses,” the applicant identified and described the 

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 (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) 
Structures and Components Subject to Aging Management Review 

 2-3 

● Section 2.2, to ensure that the applicant described a process for determining the SCs 

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

and (a)(2) 

In addition, the staff conducted a scoping and screening methodology audit at HCGS, located at 

the southern end of Artificial Island in Lower Alloways Creek Township, Salem County, New 

Jersey, during the week of January 11–20, 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 procedures and 

technical basis documents 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 LRA Appendix A, “Final Safety Analysis Report Supplement,” and 

Appendix B, “Aging Management Programs.” 

The staff selected the following systems for its review: the makeup demineralizer system, the 

radwaste system, the service water system, and the turbine building. For these systems, the 

staff reviewed the applicant’s scoping and screening process, including a review of the scoping 

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

reports. The purpose of the review was to verify that the applicant had appropriately 

implemented the methodology outlined in the administrative controls and that the scoping and 

screening 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 audit trip report, dated August 19, 2010 

(Agencywide Document Access and Management System (ADAMS) Accession 

No. ML102100544), to verify that the process used to identify SCs subject to an AMR was 

consistent with the SRP-LR. Additionally, the staff reviewed the CLB documentation sources 

scope 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 references for the license 

renewal scoping and screening process: 

● updated final safety analysis report (UFSAR) 

● fire hazards analysis report 

● environmental qualification master list 

● maintenance rule database 
Structures and Components Subject to Aging Management Review 

 2-4 

● configuration baseline documents 

● controlled plant component database 

● engineering drawings 

● engineering evaluations and calculations 

● licensing correspondence 

The applicant stated that it used this information to identify the functions performed by each 

applicable plant system and structure. It then compared these functions to the scoping criteria 

in 10 CFR 54.4(a) (1–3) to determine if the associated plant system or structure performed a 

license renewal intended function. These information sources were also used to develop the list 

of SCs subject to an AMR. 

2.1.3.1.2 Staff Evaluation 

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

and screening methodology implementing procedures, including license renewal guidelines, 

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

consistent with the requirements of the Rule, the SRP-LR, and NEI 95-10. The staff finds that 

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 NEI 95-10. 

The applicant’s implementing documents 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 documents, the staff focused on the 

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

applicant’s implementation of the staff’s position concerning the SSCs that meet the 

10 CFR 54.4(a) criteria, as documented in the SRP-LR. 

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

and screening methodology implementing procedures are consistent with the methodology 

described in LRA Section 2.1. The applicant’s methodology provides concise guidance on the 

scoping and screening implementation process to be followed during the implementation of the 

LRA. 

Sources of Current Licensing Basis Information. 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 any 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, and licensee commitments documented in NRC safety evaluations or licensee event 

reports. 

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

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

addition, the applicant’s license renewal process identified additional sources of plant 

information pertinent to the scoping and screening process, including the fire hazards analysis 
Structures and Components Subject to Aging Management Review 

 2-5 

report, the environmental qualification master list, the maintenance rule database, the 

configurations baseline documents, controlled plant component database, engineering 

drawings, engineering evaluations and calculations, and licensing correspondence. The staff 

confirmed that the applicant’s detailed license renewal program guidelines specified the use of 

the CLB source information in performance of the scoping and screening evaluations. 

The plant component database, UFSAR, quality classifications, and design-basis information 

were the applicant’s primary repository for system identification and component safety 

classification information used during performance of the scoping and screening evaluations. 

During the audit, the staff reviewed the applicant’s administrative controls for the plant 

component database, design-basis information, and other information sources used to verify 

system information. These controls are described in and implemented by plant administrative 

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

classification information contained in the applicable HCGS documentation, the staff concludes 

that the applicant has established adequate measures to control the integrity and reliability of 

HCGS system identification and safety classification data. Therefore, the staff concludes that 

the information sources used by HCGS 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 discussed the 

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

appropriately incorporated into the license renewal process. 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. 

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

results reports used to support the identification of SSCs 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 the scoping and screening evaluations. The staff finds 

these design documentation sources to be useful in ensuring that the initial scope of SSCs 

identified by the applicant was consistent with the plant’s CLB. 

2.1.3.1.3 Conclusion 

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 the CLB information in a manner 

consistent with the Rule, the SRP-LR, and NEI 95-10 guidance and, therefore, is acceptable. 
Structures and Components Subject to Aging Management Review 

 2-6 

2.1.3.2 Quality Controls Applied to LRA Development 

2.1.3.2.1 Staff Evaluation 

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

and screening methodologies used in the LRA were adequately implemented. The applicant 

applied the following quality assurance processes during the LRA development: 

● Written procedures were developed to govern the implementation of the scoping and 

screening methodology. 

● Scoping and screening summary reports and revisions were prepared, independently 

verified, and approved. 

● Process and procedure self-assessment was performed. 

● Scoping and screening self-assessment was performed. 

● The license renewal project team performed a self-assessment. 

● The LRA was reviewed by the applicant’s Challenge Board, the Plant Operations Review 

Committee, and the Nuclear Safety Review Board. 

● The LRA was benchmarked relative to recent applications. 

● License renewal management and staff participated in NEI license renewal activities. 

● License renewal management and staff participated in external industry reviews. 

The staff reviewed the applicant’s written procedures and documentation of assessment 

activities and determined that the applicant had developed adequate procedures to provide 

quality control for the LRA development and assess the results of the scoping and screening 

activities. 

2.1.3.2.2 Conclusion 

On the basis of its review of the pertinent LRA development guidance, discussion with the 

applicant’s license renewal staff, and a 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 meet the current regulatory requirements and provide assurance that LRA 

development activities were performed in accordance with the applicant’s license renewal 

program requirements. 
Structures and Components Subject to Aging Management Review 

 2-7 

2.1.3.3 Training 

2.1.3.3.1 Staff Evaluation 

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

methodology for the scoping and screening activities were applied in a consistent and 

appropriate manner. As outlined in the project procedures, the applicant requires training for all 

personnel participating in the development of the LRA and uses only trained and qualified 

personnel to prepare the scoping and screening implementing procedures. The training 

included the following activities: 

● License renewal staff received an initial qualification which consisted of training on the 

following topics: 

▪ License renewal process overview 

▪ License renewal project training and reference materials 

▪ Relevant industry documents 

● License renewal staff received additional classroom training on the following topics: 

▪ Site document overview 

▪ Systems and structures overview 

▪ System specific training 

▪ Database training 

● License renewal process overview training was conducted at department staff meetings. 

The staff reviewed the applicant’s written procedures and reviewed some completed 

qualification and training records for the applicant’s license renewal personnel. The staff 

determined that the applicant had 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 the staff’s review of selected documentation in 

support of the process, the staff concludes that the applicant’s personnel are adequately trained 

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

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 

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

renewal personnel, 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. 
Structures and Components Subject to Aging Management Review 

 2-8 

2.1.4 Plant Systems, Structures, and Components Scoping Methodology 

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

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

categorized the plant in terms of major systems and structures with respect to license renewal. 

According to the LRA, major systems and structures were evaluated against criteria provided in 

10 CFR Part 54.4(a)(1–3) to determine whether the item should be considered within the scope 

of license renewal. The LRA states that the scoping process identified the SSCs that: (1) are 

safety-related and perform or support an intended function for responding to a design-basis 

event (DBE); (2) are nonsafety-related but their failure could prevent accomplishment of a 

safety-related function; or (3) support a specific requirement for one of the five regulated events 

applicable to license renewal. LRA Section 2.0, “Scoping and Screening Methodology for 

Identifying Structures and Components Subject to Aging Management Review, and 

Implementation Results,” stated that the scoping methodology used by HCGS is consistent with 

the industry guidance contained in NEI 95-10, Revision 6. 

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) 

LRA Section 2.1.3.2, “Identification of Safety-Related Systems and Structures,” describes the 

applicant’s process for scoping safety-related systems and structures to be included within the 

scope of license renewal in accordance with 10 CFR 54.4(a)(1) scoping criterion. The process 

began with the HCGS plant components that have been classified as safety-related and 

identified as “Q” in the controlled quality classification data field in the Systems, Applications 

and Products in Data Processing (SAP) database. HCGS quality classification procedures were 

reviewed against the license renewal “safety-related” scoping criterion in 10 CFR 54.4(a)(1) to 

confirm that HCGS safety-related classifications are consistent with license renewal 

requirements. 

The HCGS quality classification procedure definition of safety-related is as follows: 

All safety-related structures, systems, and components required to assure: 

● integrity of reactor coolant boundary 

● capability to shut down the reactor and maintain it in a safe shutdown condition 

● capability to prevent or mitigate the consequences of an accident which could result in 

potential offsite exposure comparable to the guidelines of 10 CFR Part 100 

● retaining of fuel temperature within design limits by maintaining fuel coolant inventory 

and temperature within design limits 

● control of the concentration of combustible gases in the containment system within 

established limits 

This definition is technically equivalent to 10 CFR 54.4(a)(1) for the purposes of license renewal 

scoping. The wording differences are addressed as follows: 

Design Basis. The HCGS procedure definition does not specifically refer to DBEs, while 

10 CFR 54.4(a)(1) refers to DBEs as defined in 10 CFR 50.49(b)(1). For the HCGS license 
Structures and Components Subject to Aging Management Review 

 2-9 

renewal, an additional technical basis document was prepared to confirm that all applicable 

DBEs were considered. This includes confirming that design-basis internal and external events 

including design-basis accidents (DBAs), anticipated operational occurrences, and natural 

phenomena as described in the CLB are considered when scoping for license renewal. 

Exposure Limits. The HCGS quality classification procedure definition of safety-related refers to 

10 CFR 100 for accident exposure limits. The license renewal rule refers to 

10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as applicable. These different 

exposure limit requirements appear in three different Code sections to address similar accident 

analyses performed by licensees for different reasons. The exposure limit requirements in 

10 CFR 50.34(a)(1) is not applicable to HCGS license renewal. The UFSAR refers to both 

10 CFR 50.67 and 10 CFR 100 for accident exposure limits. HCGS alternate radiological 

source term methodology was applied (in accordance with Regulatory Guide (RG) 1.183) to the 

DBA analyses and, therefore, uses 10 CFR 50.67 dose acceptance criteria. The alternate 

radiological source term methodology for post-accident radiological analysis of certain events 

allows credit for some nonsafety-related components as plate-out surfaces or holdup volumes. 

Nonsafety-related components credited in post-accident radiological analyses for plate-out or 

holdup are included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

The HCGS definition of safety-related includes two additional criteria that are not included in 

10 CFR 54.4(a)(1). SSCs required to meet these additional criteria are included within the 

scope of license renewal for 10 CFR 54.4(a)(1). Therefore, the HCGS definition of 

safety-related is consistent with the 10 CFR 54.4(a)(1) definition for the purposes of identifying 

the safety-related SSCs that are within the scope of license renewal. 

2.1.4.1.1 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: (1) the 

integrity of the reactor coolant pressure boundary; (2) the capability to shut down the reactor 

and maintain it in a safe shutdown condition; or (3) the capability to prevent or mitigate the 

consequences of accidents that could result in potential offsite exposures comparable to those 

referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11. 

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

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, DBAs, external events, and natural phenomena) that 

were applicable to HCGS. 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 UFSAR and basis documents discussed events such as internal 
Structures and Components Subject to Aging Management Review 

 2-10 

and external flooding, tornados, and missiles. The staff concludes that the applicant’s 

evaluation of DBEs is consistent with the SRP-LR. 

The applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) criteria in accordance with 

its license renewal implementing procedures which provides guidance for the preparation, 

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

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

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

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

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

applicant’s personnel who were responsible for these evaluations. 

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

10 CFR 54.4(a)(1) and determined that the CLB definition of “safety-related” met the definition 

of “safety-related” specified in the Rule. The staff evaluated the applicant’s use of the alternate 

radiological source term methodology in the DBA analyses using the 10 CFR 50.67 dose 

acceptance criteria and found this to be acceptable. The staff also evaluated the two additional 

criteria in the applicant’s definition of safety-related and found them to be technically equivalent 

to 10 CFR 54.4(a)(1) and thus, acceptable. The staff reviewed the license renewal scoping 

results for the makeup demineralizer system, the radwaste system, the service water system, 

and the turbine building, to provide additional assurance that the applicant adequately 

implemented its scoping methodology with respect to 10 CFR 54.4(a)(1). The staff 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 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) criterion. 

During review of the LRA and performance of the scoping and screening methodology audit, 

performed onsite January 11–21, 2010, the staff determined that the scoping implementing 

documents discuss the use of the classification “SR,” listed in the component classification field 

in the SAP, as an initial identifier of safety-related systems. In addition, the classification “Q,” 

listed in the component classification field in the SAP, was also used to determine whether 

systems identified as safety-related in the SAP would be included within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(1). 

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

Request for additional information (RAI) 2.1-1 was issued by letter dated April 27, 2010, in 

which the staff requested that the applicant provide a detailed description of the use of all 

component classifications in the SAP, including “SR” and “Q,” that were used to identify 

safety-related systems to be included within the scope of license renewal or used to exclude 

systems from within the scope of license renewal. 

The applicant responded to RAI 2.1-1 by letter dated May 24, 2010, which stated that the “Q” 

classification was used to identify components in accordance with the classification procedure, 

to indicate that the requirements of 10 CFR 50, Appendix B, “Quality Assurance Criteria for 

Nuclear Power Plant and Fuel Reprocessing Plants,” apply. The “Quality Assurance 

Requirements” classification category, described in the SAP as “safety-related QA related,” is 

the only classification category used to designate safety-related “Q” components at HCGS, and 

is the only classification category used in the HCGS scoping methodology to confirm that all 
Structures and Components Subject to Aging Management Review 

 2-11 

safety-related systems were properly identified and included within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(1) criteria. This classification category includes 

safety-related components that are designated “Q” in accordance with the classification 

procedure, to indicate that the requirements of 10 CFR 50, Appendix B, “Quality Assurance 

Criteria for Nuclear Power Plant and Fuel.” The “SR” classification only applies to components 

at the Salem Nuclear Generating Station. In its response, the applicant stated: 

The component classification information contained in five of the SAP 

classification categories is determined in accordance with the Hope Creek 

component classification methodology procedure HC.DE-AP.ZZ-0060(Q), 

Functional Classification Methodology for Component Data Module Functional 

Locations within SAP/R3 for Hope Creek Generating Station. 

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

used information contained in the component database to identify safety-related components 

and the parent systems to be evaluated for inclusion within the scope of license renewal, in 

accordance with 10 CFR 54.4(a)(1). The applicant’s response indicated that the designations 

“safety-related QA related” and “Q” are defined by the HCGS component classification 

methodology procedure HC.DE-AP.ZZ-0060(Q), which was used to classify components 

meeting the safety-related criteria. 

In addition, during review of the LRA and performance of the scoping and screening 

methodology audit, performed onsite January 11–21, 2010, the staff determined that the 

10 CFR 54.4(a)(1) implementing document discusses incorrect or conservative SAP component 

data module (CDM) classifications. The implementing procedure provided the process and 

results of the applicant’s determination that certain systems do not perform safety-related 

functions as defined in 10 CFR 54.4(a)(1), and were, therefore, not included within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(1). RAI 2.1-1 also requested that the 

applicant provide a detailed description of the process used to conclude that the SAP CDM 

classifications were conservative or incorrect and that the systems or components do not 

perform safety-related functions as defined in 10 CFR 54.4(a)(1). The applicant stated in its 

response to RAI 2.1-1 by letter dated May 24, 2010, that as a result of the SAP component data 

review, some safety-related components were identified in several systems that were not 

identified as safety-related or identified as having safety-related intended functions in other CLB 

documents, such as the UFSAR and Maintenance Rule system scoping documents. 

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

described the process used to evaluate systems which contained components, identified as 

safety-related in the SAP, that were not included within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(1). The staff determined that the components were contained 

in systems that did not have safety-related functions, were 1E electrical components identified 

with mechanical systems that did not have safety-related functions and were subsequently 

evaluated with the 1E electrical systems, or were components incorrectly identified as 

safety-related in the component database. The staff’s concern described in RAI 2.1-1 is 

resolved. 

2.1.4.1.2 Conclusion 

On the basis of its review of a selection of systems, discussions with the applicant, review of the 

applicant’s scoping process, and the response to RAI 2.1-1, the staff concludes that the 

applicant’s methodology for identifying systems and structures is consistent with the SRP-LR 

and 10 CFR 54.4(a)(1) and, therefore, is acceptable. 
Structures and Components Subject to Aging Management Review 

 2-12 

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 2.1.3.3, “10 CFR 54.4(a)(2) Scoping Criteria,” describes the applicant’s scoping 

methodology as it relates to the nonsafety-related criteria in 10 CFR 54.4(a)(2). To identify all 

nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of any of the 

functions identified in accordance with 10 CFR 54.4(a)(1), the applicant considered the 

following: 

 (1) nonsafety-related SSCs required to support a safety-related 10 CFR 54.4(a)(1) function 

 (2) nonsafety-related systems connected to and providing structural support for a 

safety-related SSC 

 (3) nonsafety-related systems with a potential for spatial interaction with safety-related 

SSCs 

Functional Support for Safety-Related SSC 10 CFR 54.4(a)(1) Functions. LRA Section 2.1.5.2, 

“Nonsafety-Related Affecting Safety-Related – 10 CFR 54.4(a)(2),” states that nonsafety-related 

SSCs that are required to function in support of a safety-related SSC intended function are 

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

nonsafety-related SSCs that were included within the scope of license renewal under this 

review, to support a safety-related SSC in performing a 10 CFR 54.4(a)(1) intended function, 

are identified on the license renewal boundary drawings. 

Connected to and Providing Structural Support for Safety-Related SSCs. LRA Section 2.1.5.2 

states that for nonsafety-related piping connected to safety-related piping, the nonsafety-related 

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

confirmed by a review of the installation details. The applicant stated that the nonsafety-related 

piping was included within the scope of license renewal for 10 CFR 54.4(a)(2), from the 

safety-related/nonsafety-related interface, to one of the following: 

 (1) A seismic anchor. Only true anchors that ensure forces and moments are restrained in 

three orthogonal directions are credited. 

 (2) An anchored component (e.g., pump, heat exchanger, tank, etc.) that is designed not to 

impose loads on connecting piping. The anchored component is included within the 

scope of license renewal as it has a structural support function for the safety-related 

piping. 

 (3) A flexible connection that 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). 

 (4) A free end of nonsafety-related piping, such as a drain pipe that ends at an open floor 

drain. 

 (5) For nonsafety-related piping runs that are connected at both ends to safety-related 

piping, the entire run of nonsafety-related piping is included within the scope of license 

renewal. 
Structures and Components Subject to Aging Management Review 

 2-13 

 (6) A branch line off of a header where the moment of inertia of the header is greater than 

15 times the moment of inertia of the branch. The header is treated as an anchor. 

Potential for Spatial Interactions with Safety-Related SSCs. LRA Section 2.1.5.2 states that 

nonsafety-related systems that are not connected to safety-related piping or components, or are 

beyond the first seismic anchor past the safety/nonsafety interface, and have a spatial 

relationship such that their failure could adversely impact the performance of a safety-related 

SSC intended function, must be evaluated for license renewal scope in accordance with 

10 CFR 54.4(a)(2) requirements. The applicant used the preventive option described in 

NEI 95-10, Appendix F, to determine the scope of license renewal with respect to the protection 

of safety-related SSCs from spatial interactions. This scoping process, referred to as the 

“spaces” approach, involves an evaluation based on equipment location and the related SSCs 

and whether or not fluid-filled system components are located in the same space as 

safety-related equipment. A “space,” for the purposes of the review, was defined as a structure 

containing active or passive safety-related SSCs. 

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 of SSCs relied 

on to remain functional during and following a DBE to ensure: (1) the integrity of the reactor 

coolant pressure boundary; (2) the capability to shut down the reactor and maintain it in a safe 

shutdown condition; or (3) the capability to prevent or mitigate the consequences of accidents 

that could result in potential offsite exposures comparable to those referred to in 

10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11. 

RG 1.188, “Standard Format and Content for Applications to Renew Nuclear Power Plant 

Operating Licenses,” 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, including: 

(1) nonsafety-related SSCs typically identified in the CLB; (2) consideration of missiles, cranes, 

flooding, and high-energy line breaks (HELBs); (3) nonsafety-related SSCs connected to 

safety-related SSCs; (4) nonsafety-related SSCs in proximity to safety-related SSCs; and 

(5) mitigative and preventive options related to nonsafety-related and safety-related SSC 

interactions. 

As discussed in NEI 95-10, Revision 6, applicants should not consider hypothetical failures but 

rather, should base their evaluation on the plant’s CLB, engineering judgment and analyses, 

and relevant operating experience. NEI 95-10 further describes operating experience as all 

documented plant-specific and industry-wide experience that can be used to determine the 

plausibility of a failure. Documentation would include NRC generic communications and event 

reports, plant-specific condition reports, industry reports such as safety operational event 

reports, and engineering evaluations. The staff reviewed LRA Sections 2.1.3.3 and 2.1.5.2 in 

which the applicant described the scoping methodology for nonsafety-related SSCs pursuant to 

10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant’s implementing document and 

results report, which documented the guidance and corresponding 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. 
Structures and Components Subject to Aging Management Review 

 2-14 

Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC. 

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 Sections 2.1.3.3 and 2.1.5.2 and the applicant’s 10 CFR 54.4(a)(2) 

implementing document. The staff confirmed that the applicant had reviewed the UFSAR, plant 

drawings, plant component database, and other CLB documents to identify the 

nonsafety-related systems and structures that function to support a safety-related system whose 

failure could prevent the performance of a safety-related 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 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 the LRA and the applicant’s 10 CFR 54.4(a)(2) 

implementing document. Based on its review, the staff determined that the applicant had 

reviewed the safety-related to nonsafety-related interfaces for each mechanical system in order 

to identify the nonsafety-related components located between the safety-related to 

nonsafety-related interface and license renewal structural boundary. 

The staff determined that in order to identify the nonsafety-related SSCs connected to 

safety-related SSCs and for the nonsafety-related SSCs to be structurally sound to maintain the 

integrity of the safety-related SSCs, as required, 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: 

● seismic anchors 

● bounding conditions described in NEI 95-10, Revision 6, Appendix F, such as 

base-mounted component, flexible connection, free end of nonsafety-related piping, or 

inclusion of the entire nonsafety-related 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 LRA Section 2.1.5.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

procedure. LRA Section 2.1.5.2 and the applicant’s implementing document state that the 

applicant had 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 had 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 
Structures and Components Subject to Aging Management Review 

 2-15 

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 in an excluded space (i.e., a space with no 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 confirmed that those nonsafety-related SSCs determined to contain 

liquid or steam and located within a space containing safety-related SSCs 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 and discussions with the applicant, 

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 2.1.5.3, “Regulated Events–10 CFR 54.4(a)(3),” describes the methodology for 

identifying those systems and structures within the scope of license renewal in accordance with 

the NRC criteria for five regulated events: (1) 10 CFR 50.48, “Fire Protection”; 

(2) 10 CFR 50.49, “Environmental Qualification of Electric Equipment Important to Safety for 

Nuclear Power Plants”; (3) 10 CFR 50.61, “Fracture Toughness Requirements for Protection 

Against Pressurized Thermal Shock Events”; (4) 10 CFR 50.62, “Requirements for Reduction of 

Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear 

Power Plants”; and (5) 10 CFR 50.63, “Loss of All Alternating Current Power.” 

Fire Protection. LRA Section 2.1.3.4, “Scoping for Regulated Events,” subsection “Fire 

Protection” describes the scoping of all SSCs relied on in safety analyses or plant evaluations to 

perform a function that demonstrates compliance with the NRC regulations for fire protection 

(10 CFR 50.48). The applicant stated that this scope of systems and structures included: 

● systems and structures required to demonstrate post-fire safe shutdown capabilities 

● systems and structures required for fire detection and suppression 

● systems and structures required to meet commitments made to Appendix A of Branch 

Technical Position (BTP) (APCSB 9.5-1) 

Environmental Qualification (EQ). LRA Section 2.1.3.4, subsection “Environmental 

Qualification,” describes the scoping of systems and structures relied on in safety analyses or 

plant evaluations to perform a function in compliance with the EQ criterion. The LRA states that 

the HCGS EQ program includes safety-related electrical equipment, nonsafety-related electrical 

equipment whose failure under postulated environmental conditions could prevent satisfactory 

accomplishment of safety functions of the safety-related equipment, and certain post-accident 
Structures and Components Subject to Aging Management Review 

 2-16 

monitoring equipment, as defined in 10 CFR 50.49(b)(1), 10 CFR 50.49(b)(2), and 

10 CFR 50.49(b)(3), respectively. 

Pressurized Thermal Shock. LRA Section 2.1.5.3, subsection “Pressurized Thermal Shock,” 

states, “The regulation for pressurized thermal shock (10 CFR 50.61) is applicable to 

pressurized water reactors only, and is therefore not applicable [to] the HCGS boiling water 

reactor.” 

Anticipated Transient Without Scram. LRA Section 2.1.3.4, subsection “Anticipated Transients 

Without Scram,” describes the scoping of systems and structures relied on in safety analyses or 

plant evaluations to perform a function in compliance with the ATWS criterion. The LRA states 

that an ATWS is a postulated operational transient that generates an automatic scram signal, 

accompanied by a failure of the reactor protection system to shutdown the reactor. The LRA 

states that: 

Hope Creek has a Redundant Reactivity Control System (RRCS) that is 

designed to mitigate the potential consequences of an ATWS event. The system 

consists of remote control panels, their associated ATWS detection and actuation 

logic and the necessary interface logic to the reactor recirculation system, the 

feed water control system, the reactor water cleanup system, the standby liquid 

control (SLC) system, and the alternate rod insertion (ARI) components of the 

control rod drive system required to perform specific functions in response to an 

ATWS event. Hope Creek also has an adequately sized standby liquid control 

system that is initiated automatically by the RRCS logic when needed. 

The ATWS basis document provides a list of the systems required by 10 CFR 50.62 to reduce 

the risk from ATWS events. The basis document also provides a list of structures that provide 

physical support and protection for the ATWS systems. These systems and structures are 

included within the scope of license renewal under the 10 CFR 54.4(a)(3) scoping criteria. 

Station Blackout. LRA Section 2.1.3.4, subsection “Station Blackout,” describes the scoping of 

systems and structures relied on in safety analyses or plant evaluations to perform functions in 

compliance with the SBO criterion. HCGS satisfies the requirement of 10 CFR 50.63 as an 

alternating current independent, 4-hour coping plant. The NUREG-1800 guidance on scoping of 

equipment relied on to meet the requirements of the station blackout (SBO) rule (10 CFR 50.63) 

for license renewal has been incorporated into the HCGS scoping methodology. In accordance 

with the NUREG-1800 requirements, the SSCs required to recover from the SBO event are 

included within the scope of license renewal. Recovery is defined as the repowering of the plant 

AC distribution system from offsite sources or onsite emergency AC sources. 

2.1.4.3.2 Staff Evaluation 

The staff reviewed the applicant’s approach to identifying SSCs relied upon to perform functions 

meeting the requirements of the fire protection, EQ, ATWS, and SBO regulations. As part of 

this review, the staff discussed the methodology with the applicant, reviewed the documentation 

developed to support the approach, and evaluated selected mechanical systems and structures 

included within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). 

Fire Protection. The staff determined that the applicant’s implementing procedures indicated 

that it had included systems and structures within the scope of license renewal required for 

post-fire safe shutdown, fire detection suppression, and commitments made to Appendix A to 

BTP APCSB 9.5-1, “Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to 
Structures and Components Subject to Aging Management Review 

 2-17 

July 1, 1976,” issued May 1976. The applicant noted that it had considered CLB documents to 

identify systems and structures within the scope of license renewal. These documents included 

the 10 CFR 50, Appendix R, Fire Study and HCGS’s Fire Protection Plan; fire protection 

systems scoping and screening basis document; Fire Hazards Analysis Report; the fire 

protection program plan as required by 10 CFR 50.48; UFSAR; drawings; and other HCGS 

technical basis documents. The staff reviewed selected scoping results in conjunction with the 

LRA and the CLB information to validate the methodology for including the appropriate systems 

and structures within the scope of license renewal. Based on its review of the CLB documents 

and the sample review, the staff determined that the applicant’s scoping methodology was 

adequate for including SSCs credited in performing fire protection functions, in accordance with 

10 CFR 50.48, within the scope of license renewal. 

Environmental Qualification. The staff determined that the applicant’s implementing procedures 

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), (b)(2), and (b)(3). The staff reviewed 

the LRA, implementing procedures, the EQ systems scoping and screening basis document, 

and the EQ master component equipment list to verify that the applicant identified SSCs within 

the scope of license renewal that meet the LRA EQ requirements. Based on that review, the 

staff determined that the applicant’s scoping methodology is adequate for identifying SSCs that 

meet the requirements of 10 CFR 50.49 within the scope of license renewal. 

Pressurized Thermal Shock. The regulation for pressurized thermal shock (10 CFR 50.61) is 

applicable to pressurized water reactors only and is, therefore, not applicable to the HCGS 

boiling-water reactor. 

Anticipated Transient Without Scram. The staff determined that the applicant had generated a 

list of plant systems credited for ATWS mitigation based on review of the plant and the ATWS 

systems scoping and screening documents, the UFSAR, docketed correspondence, 

modifications, and the plant component database. The staff reviewed these documents and the 

LRA in conjunction with the scoping results to validate the methodology for identifying ATWS 

systems and structures that are within the scope of license renewal. The staff determined that 

the applicant’s scoping methodology was adequate for identifying SSCs that meet the 

requirements of 10 CFR 50.62 and are within the scope of license renewal. 

Station Blackout. The staff determined that the applicant identified those systems and 

structures associated with coping and safe shutdown of the plant following an SBO event by 

reviewing plant-specific SBO systems, scoping and screening basis document calculations, the 

UFSAR, drawings, modifications, the plant component database, and plant procedures. The 

staff reviewed (on a sampling basis) these documents and the LRA in conjunction with the 

scoping results to validate 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 that meet the requirements of 10 CFR 50.63 within the scope of 

license renewal. 

2.1.4.3.3 Conclusion 

On the basis of the selected reviews, discussion with the applicant, review of the LRA, and 

review of the implementing procedures and reports, the staff concludes that the applicant’s 
Structures and Components Subject to Aging Management Review 

 2-18 

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 

LRA Section 2.1, “Scoping and Screening Methodology,” documents the applicant’s 

methodology for performing the scoping of systems and structures in accordance with the 

requirements of 10 CFR 54.4(a) in the LRA, guidance documents, and scoping and screening 

reports. The initial step in the scoping process was to define the entire plant in terms of 

systems and structures. These systems and structures were evaluated against the scoping 

criteria in 10 CFR 54.4(a)(1), (a)(2), and (a)(3), to determine if they perform or support a 

safety-related intended function, or perform functions that demonstrate compliance with the 

requirements of one of the five license renewal regulated events. For the systems and 

structures determined to be in-scope, the intended functions that are the bases for including the 

systems and structures in-scope were also identified. If any portion of a system or structure met 

the scoping criteria of 10 CFR 54.4, the system or structure was included within the scope of 

license renewal. Mechanical systems and structures were then further evaluated to determine 

those mechanical and structural components that perform or support the identified intended 

functions. All electrical components within in-scope mechanical and electrical systems were 

included within the scope of license renewal as electrical commodities. 

LRA Section 2.1.2, “Information Sources Used for Scoping and Screening,” states that the 

UFSAR, fire hazards analysis report, environmental qualification master list, and maintenance 

rule database were primary sources of information used during the scoping process. 

LRA Section 2.1.6.3, “Stored Equipment,” states that equipment that is stored onsite for 

installation in response to a DBE is considered to be within the scope of license renewal. At 

HCGS, certain fire scenarios use stored equipment to facilitate repairs following the fire. The 

stored equipment credited is listed in controlled station procedures. These components are 

confirmed available and in good operating condition by periodic surveillance inspections. 

LRA Section 2.1.6.4, “Consumables,” states that the evaluation process for consumables is 

consistent with the guidance provided in NUREG-1800, Table 2.1-3. Consumables have been 

divided into the following four categories for the purpose of license renewal: (1) packing, 

gaskets, component seals, and O-rings; (2) structural sealants; (3) oil, grease, and component 

filters; and (4) system filters, fire extinguishers, fire hoses, and airpacks. 

2.1.4.4.2 Staff Evaluation 

The staff reviewed LRA Section 2.1 and the applicant’s methodology for performing the 

plant-level scoping of systems and structures to ensure it was consistent with 10 CFR 54.4. 

The methodology used to determine the systems and structures 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. 
Structures and Components Subject to Aging Management Review 

 2-19 

The staff reviewed the LRA Section 2.1.6.3 and applicable implementing procedures that 

addressed the process used to evaluate stored equipment, credited for response to a DBE, for 

inclusion within the scope of license renewal. The staff determined that the applicant had 

appropriately considered stored equipment and included it within the scope of license renewal. 

In addition, the staff reviewed the LRA Section 2.1.6.4 and applicable implementing procedures 

that addressed the process used to evaluate consumables for inclusion within the scope of 

license renewal. The applicant had divided consumables into the following four categories for 

the purpose of license renewal: (1) packing, gaskets, component seals, and O-rings; 

(2) structural sealants; (3) oil, grease, and component filters; and (4) system filters, fire 

extinguishers, fire hoses, and air packs. The staff determined that the applicant had 

appropriately determined the appropriate categories for consumables to be included within the 

scope of license renewal. 

The applicant documented the results of the plant-level scoping process in accordance with the 

implementing procedures. The results were provided in the systems and structures documents 

and reports which contained information including a description of the system or structure, a 

listing of functions performed by the system or structure, identification of intended functions, the 

10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the 

classification of the system or structure intended functions. During the audit, the staff reviewed 

a sampling of the 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 

Based on its review of the LRA, implementing procedures, reports, and a sampling of system 

scoping results reviewed during the audit, the staff concludes that the applicant’s methodology 

for identifying systems and structures within the scope of license renewal, and their intended 

functions, is in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.5 Mechanical Component Scoping 

2.1.4.5.1 Summary of Technical Information in the Application 

In addition to the information previously discussed in safety evaluation report (SER) 

Section 2.1.4.4.1, LRA Section 2.1.5, “Scoping Procedure,” describes the methodology for 

identifying license renewal evaluation boundaries. System and structure functions and intended 

functions were identified from a review of the source CLB documents. In-scope boundaries 

were established and documented in the scoping evaluations, based on the identified intended 

functions. The in-scope boundaries form the basis for identification of the in-scope components, 

which is the first step in the screening process. LRA Section 2.1.5.5, “Scoping Boundary 

Determination,” states that the mechanical components that support the system intended 

functions are included within the scope of license renewal and are depicted on the applicable 

system piping and instrumentation diagram. Mechanical system piping and instrumentation 

diagrams are marked up to create license renewal boundary drawings showing the in-scope 

components. Components that are required to support a safety-related function, or a function 

that demonstrates compliance with one of the license renewal regulated events, are identified 

on the system piping and instrumentation diagram. Nonsafety-related components that are 

connected to safety-related components and are required to provide structural support at the 

safety/nonsafety interface, or components whose failure could prevent satisfactory 

accomplishment of a safety-related function due to spatial interaction with safety-related SSCs, 

are identified on license renewal drawings. A computer sort and download of associated 
Structures and Components Subject to Aging Management Review 

 2-20 

system components from the SAP database were used to confirm the scope of components in 

the system. Plant walkdowns were performed when required for additional confirmation. 

2.1.4.5.2 Staff Evaluation 

The staff used the SRP-LR to evaluate LRA Sections 2.1.5 and 2.1.5.5 and the guidance in the 

implementing procedures and reports used by the applicant to perform the review of the 

mechanical scoping process. The implementing procedures and reports which the applicant 

used provided instructions for identifying the evaluation boundaries. Information related to 

system operations in support of the intended functions was necessary to determine the 

mechanical system evaluation boundary. Based on the review of the implementing procedures 

and the CLB documents associated with mechanical system scoping, the staff determined that 

the guidance and CLB source information noted above were consistent with the information in 

the LRA for identifying mechanical components and support structures in mechanical systems 

that are within the scope of license renewal. 

The staff conducted detailed discussions with the applicant’s license renewal project personnel 

and reviewed documentation pertinent to the scoping process. The staff assessed whether the 

applicant had appropriately applied the scoping methodology outlined in the LRA and 

implementing procedures and whether the scoping results were consistent with CLB 

requirements. The staff determined that the applicant’s procedure was consistent with the 

description provided in LRA Sections 2.1.5 and 2.1.5.5 and the guidance contained in SRP-LR 

Section 2.1, and was adequately implemented. 

The staff reviewed the applicant’s scoping reports for the makeup demineralizer system, the 

radwaste system, and the service water system for mechanical component types that met the 

scoping criteria of 10 CFR 54.4. The staff verified that the applicant had identified and used 

pertinent engineering and licensing information in order to determine the mechanical component 

types required to be within the scope of license renewal. As part of the review process, the staff 

evaluated: (1) each system’s intended functions identified for the makeup demineralizer system, 

the radwaste system, and the service water system; (2) the basis for inclusion of the intended 

function; and (3) the process used to identify each of the system component types. The staff 

verified that the applicant had identified and highlighted system drawings to develop the license 

renewal boundaries in accordance with the procedural guidance. Additionally, the staff 

determined that the applicant had performed an independent verification of the results in 

accordance with the governing procedures. The staff confirmed that the applicant had license 

renewal personnel knowledgeable about the system and that these personnel had performed 

independent reviews of the highlighted drawings to ensure accurate identification of system 

intended functions. The staff also confirmed that the applicant had performed additional 

cross-discipline verification and 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, the sample system 

review, and discussions with the applicant, the staff concludes that the applicant’s methodology 

for identifying mechanical systems within the scope of license renewal is in accordance with the 

requirements of 10 CFR 54.4 and, therefore, is acceptable. 
Structures and Components Subject to Aging Management Review 

 2-21 

2.1.4.6 Structural Scoping 

2.1.4.6.1 Summary of Technical Information in the Application 

LRA Section 2.1.5 identifies the scoping process for structures as stated in the previous section. 

LRA Section 2.1.5.5 states that the structural components that support the intended functions 

are included within the scope of license renewal. The structural components were identified 

from a review of applicable plant design drawings of the structure and plant walkdowns. 

2.1.4.6.2 Staff Evaluation 

The staff evaluated LRA Sections 2.1.5 and 2.1.5.5 and subsections, and the guidance 

contained in the applicant’s implementing procedures and reports to perform the review of the 

structural scoping process. 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 had 

identified and developed a list of plant structures and the structures’ intended functions through 

a review of the plant component database, the Structures Monitoring Program, UFSAR, 

controlled drawings, maintenance procedures, and walkdowns. Each structure the applicant 

identified was evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). 

The staff reviewed selected portions of the plant component database, UFSAR, drawings, 

procedures, and implementing procedures to verify the adequacy of the methodology. The staff 

reviewed source documentation for the turbine building to verify that the application of the 

methodology would provide the results as documented in the turbine building scoping report and 

in the LRA. The staff verified that the applicant had identified and used pertinent engineering 

and licensing information in order to determine that the turbine building was required to be 

included within the scope of license renewal. In addition, during the scoping and screening 

methodology audit, the staff performed walkdowns of selected areas of the turbine building to 

verify proper implementation of the scoping process. As part of the review process, the staff 

evaluated the intended functions identified for the turbine building and the structural 

components, 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 implementing procedures, and a 

sampling review of structural scoping results, the staff concludes that the applicant’s 

methodology for the scoping of the structures 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 2.1.5.5 describes the applicant’s process for scoping electrical and instrumentation 

and control (I&C) systems, and electrical components in mechanical systems within the scope 

of license renewal. A bounding scoping approach was used for electrical equipment. All 

electrical components within in-scope systems were included within the scope of license 
Structures and Components Subject to Aging Management Review 

 2-22 

renewal. In-scope electrical components were placed into commodity groups and were 

evaluated as commodities during the screening process. 

2.1.4.7.2 Staff Evaluation 

The staff evaluated LRA Sections 2.1.5 and 2.1.5.5 and subsections, and the applicant’s 

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, the plant component database, CLB documentation, drawings, 

and specifications. 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 had included electrical and I&C 

components, including components contained in the mechanical or structural systems, within 

the scope of license renewal on a commodity basis. 

2.1.4.7.3 Conclusion 

On the basis of its review of information contained in the LRA, implementing procedures and 

supporting documents, discussions with the applicant, and a review of selected electrical 

scoping results, the staff concludes that the applicant’s methodology for the identification of 

electrical and I&C SSCs within the scope of license renewal is in accordance with the 

requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.8 Scoping Methodology Conclusion 

On the basis of its review of the LRA, implementing procedures, and a review of selected 

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: (a) that are 

safety-related, (b) whose failure could affect safety-related functions, and (c) that are necessary 

to demonstrate compliance with the NRC regulations for fire protection, EQ, pressurized thermal 

shock, ATWS, and SBO. 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 2.1.6.1, “Identification of Structures and Components Subject to AMR,” describes 

the screening process that identifies the SCs within the scope of license renewal that are 

subject to an AMR. The screening procedure is the process used to identify the passive, 

long-lived SCs that are within the scope of license renewal and thus, subject to an AMR. The 

SRP-LR and NEI 95-10, Appendix B were used as the basis for the identification of passive 

SCs. Most passive SCs are long-lived. In the few cases where a passive component is 

determined not to be long-lived, such determination is documented in the screening evaluation 

and, if applicable, on the associated license renewal boundary drawing. 
Structures and Components Subject to Aging Management Review 

 2-23 

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 period (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 groups1

 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 2.1.6.1, the applicant discussed these screening activities as they relate to the 

component types and commodity groups within the scope of license renewal. 

The staff determined that the applicant’s 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”; LRA Section 2.4, “Scoping and Screening 

Results: Structures”; and LRA Section 2.5, “Scoping and Screening Results: Electrical and 

Instrumentation and Controls (I&C) Systems.” These LRA sections provide the results of the 

process used to identify component types and commodity groups subject to an AMR. 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 

staff also reviewed screening results reports for the makeup demineralizer system, the radwaste 

system, the service water system, and the turbine building. 

2.1.5.1.3 Conclusion 

On the basis of its review of the LRA, the implementing procedures, and selected screening 

results, the staff concludes that the applicant’s screening methodology was consistent with the 

guidance contained in the SRP-LR and was capable of identifying passive, long-lived 

components within the scope of license renewal that are subject to an AMR. The staff 

concludes that the applicant’s process for determining which component types and commodity 

groups subject to an AMR is in accordance with the requirements of 10 CFR 54.21 and, 

therefore, is acceptable. 

 

1

 For scoping, the applicant may also group like structures and components into commodity 

groups. The basis for grouping structures and components can be determined by such 

characteristics as similar function, similar design, similar materials of construction, similar aging 

management practices, or similar environments. If the applicant uses commodity groups, the 

reviewer verifies that the applicant has described the basis for the groups. 
Structures and Components Subject to Aging Management Review 

 2-24 

2.1.5.2 Mechanical Component Screening 

2.1.5.2.1 Summary of Technical Information in the Application 

LRA Section 2.1.6.1, “Identification of Structures and Components Subject to AMR,” describes 

the applicant’s process for identifying mechanical components within the scope of license 

renewal that were subject to an AMR. For in-scope mechanical systems, the completed 

scoping packages include written descriptions and marked up system piping and 

instrumentation diagrams that clearly identify the in-scope system boundary for license renewal. 

The marked up system piping and instrumentation diagrams are called boundary drawings for 

license renewal. These system boundary drawings were carefully reviewed to identify the 

passive, long-lived components, and the identified components were then entered into the 

license renewal database. Component listings from the SAP database were also reviewed to 

confirm that all system components were considered. In cases where the system piping and 

instrumentation diagram did not provide sufficient detail, such as for some large vendor supplied 

components (e.g., compressors, emergency diesel generators), the associated component 

drawings or vendor manuals were also reviewed. Plant walkdowns were performed when 

required for confirmation. Finally, the identified list of passive, long-lived system components 

was benchmarked against previous LRAs containing a similar system. 

2.1.5.2.2 Staff Evaluation 

The staff reviewed the mechanical screening methodology discussed and documented in LRA 

Section 2.1.6.1, implementing procedures, scoping and screening reports, and license renewal 

drawings. The staff determined that the mechanical system screening process used the results 

from the scoping process and that the applicant reviewed each system evaluation boundary as 

depicted on system drawings 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 a function within the system evaluation boundaries and 

determined those components that are subject to an AMR. The results of the review were 

documented in the scoping and screening reports, which contain the information sources 

reviewed and the component functions. 

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. 

The staff reviewed portions of the UFSAR, plant component database, CLB documentation, 

procedures, drawings, specifications, and selected scoping and screening reports. The staff 

conducted detailed discussions with the applicant’s license renewal team and reviewed 

documentation pertinent to the screening process. The staff assessed whether the mechanical 

screening methodology outlined in the LRA and implementing procedures was appropriately 

implemented and if the screening results were consistent with CLB requirements. During the 

scoping and screening methodology audit, the staff discussed the screening methodology with 

the applicant and reviewed the applicant’s screening reports for the makeup demineralizer 

system, the radwaste system, and the service water system, to verify proper implementation of 

the screening process. In addition, the staff performed walkdowns of selected portions of the 

systems as an example of the methodology and its implementation. Based on the review 
Structures and Components Subject to Aging Management Review 

 2-25 

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 component database, CLB documentation, procedures, drawings, 

specifications, selected scoping and screening reports, and selected results for selected 

systems, the staff concludes that the applicant’s methodology for identification of mechanical 

components 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 2.1.6.1, “Identification of Structures and Components Subject to AMR,” describes 

the applicant’s process of screening structural components that are subject to an AMR. The 

structure drawings for in-scope structures were carefully reviewed to identify the passive, 

long-lived SCs, and the identified SCs were then entered into the license renewal database. 

Component listings from the SAP database were also reviewed to confirm that all structural 

components were considered. Plant walkdowns were performed when required for 

confirmation. Finally, the identified list of passive, long-lived SCs was benchmarked against 

previous LRAs. 

2.1.5.3.2 Staff Evaluation 

The staff reviewed the structural screening methodology discussed and documented in LRA 

Section 2.1.6, the implementing procedures, and the license renewal drawings. The staff 

reviewed the applicant’s methodology for identifying structural components that are subject to 

an AMR, as required by 10 CFR 54.21(a)(1). The staff confirmed that the applicant had 

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, the Structures Monitoring Program, and 

scoping and screening reports, which the applicant used to perform the structural scoping and 

screening activities. The staff also reviewed, on a sampling basis, the structural drawings to 

document the SCs within the scope of license renewal and subject to an AMR. The staff 

conducted 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 were appropriately implemented and if the screening results were 

consistent with the CLB requirements. In addition, during the scoping and screening 

methodology audit, the staff reviewed the turbine building to verify proper implementation of the 

screening process and performed walkdowns of selected areas. Based on the review activities, 

the staff did not identify any discrepancies between the methodology documented and the 

implementation results. 
Structures and Components Subject to Aging Management Review 

 2-26 

2.1.5.3.3 Conclusion 

On the basis of its review of the LRA, implementation procedures, the UFSAR, CLB 

documentation, drawings, 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 

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 2.1.6.1, “Identification of Structures and Components Subject to AMR,” describes 

the screening of electrical and I&C components. The applicant used a bounding approach as 

described in NEI 95-10. The sequence of steps and special considerations for the identification 

of electrical components that require an AMR is as follows: 

 (1) Electrical and I&C components within in-scope systems at HCGS were identified and 

listed. The electrical and I&C component commodity groups were identified from a 

review of plant documents, controlled drawings, the plant component database (SAP), 

and interface with the parallel mechanical and civil/structural screening efforts. 

 (2) The criterion of 10 CFR 54.21(a)(1)(i) was applied to identify component commodity 

groups that perform their functions without moving parts or without a change in 

configuration or properties (referred to as “passive” components). These components 

were identified using the guidance of NEI 95-10 and the Electric Power Research 

Institute (EPRI) License Renewal Electrical Handbook. 

 (3) The 10 CFR 54.21(a)(1)(ii) screening criterion was applied to those components and 

commodity groups that were not previously eliminated by the application of the 

10 CFR 54.21(a)(1)(i) screening criterion. 

2.1.5.4.2 Staff Evaluation 

The staff reviewed the applicant’s methodology used for electrical screening in LRA 

Section 2.1.6.1 and subsections, implementing procedures, bases documents, and 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 had identified commodity groups which were found to 

meet the passive criteria in accordance with NEI 95-10. In addition, the staff determined that 

the applicant evaluated the identified, passive commodities to determine whether 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 

applicant had correctly determined that the remaining passive, long-lived components were 

determined to be subject to an AMR. 

The staff reviewed selected portions of the UFSAR, the plant component database, CLB 

documentation, documents, procedures, drawings, specifications, and selected scoping and 
Structures and Components Subject to Aging Management Review 

 2-27 

screening reports. The staff conducted discussions with the applicant’s license renewal team 

and reviewed documentation pertinent to the screening process. The staff assessed whether 

the electrical screening methodology outlined in the LRA and procedures was appropriately 

implemented and if the scoping results were consistent with CLB requirements. During the 

scoping and screening methodology audit, the staff discussed the screening methodology with 

the applicant and reviewed the applicant’s screening reports for selected systems 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. 

2.1.5.4.3 Conclusion 

On the basis of its review of the LRA, implementing procedures, selected portions of the 

UFSAR, plant component database, the 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 subject to an AMR is in accordance with 

the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable. 

2.1.5.5 Screening Methodology Conclusion 

On the basis of its review of the LRA, implementing procedures, discussions with the applicant’s 

staff, and a sample review of screening results, the staff concludes that the applicant’s 

screening methodology is consistent with the guidance contained in the SRP-LR, and the 

applicant identified those passive, long-lived components within the scope of license renewal 

that are subject to an AMR. The staff concludes that the applicant’s methodology is consistent 

with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable. 

2.1.6 Summary of Evaluation Findings 

On the basis of its review of the information presented in LRA Section 2.1, the supporting 

information in the scoping and screening implementing procedures and reports, the information 

presented during the scoping and screening methodology audit, discussions with the applicant, 

and the applicant’s response dated May 24, 2010, to the staff’s RAIs, the staff concludes that 

the applicant’s scoping and screening methodology, including the description and justification 

for its methodology, are consistent with the requirements of 10 CFR 54.4 and 

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. 
Structures and Components Subject to Aging Management Review 

 2-28 

2.2 Plant-Level Scoping Results

2.2.1 Introduction 

LRA Section 2.1 describes the methodology for identifying systems and structures within the 

scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to 

determine which systems and structures must be included within the scope of license renewal. 

2.2.2 Summary of Technical Information in the Application 

The staff reviewed the plant-level scoping results to determine whether the applicant has 

properly identified the following three groups: 

• Safety-related SSCs which are those relied upon to remain functional during and 

following DBEs, as required by 10 CFR 54.4(a)(1). 

• All nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of 

any safety-related functions, as required by 10 CFR 54.4(a)(2). 

• All SSCs relied on in safety analyses of plant evaluations to perform a function that 

demonstrates compliance with the NRC regulations for fire protection, pressurized 

thermal shock, ATWS, and SBO, as required by 10 CFR 54.4(a)(3). 

LRA Table 2.2-1 lists those mechanical systems, electrical and I&C systems, and structures that 

are within the scope of license renewal. Also in LRA Table 2.2-1, the applicant listed the 

systems and structures that do not meet the criteria specified in 10 CFR 54.4(a) and are 

excluded from the scope of license renewal. Based on the DBEs considered in the CLB, other 

CLB information relating to nonsafety-related systems and structures, and certain regulated 

events, the applicant identified plant-level systems and structures within the scope of license 

renewal as defined by 10 CFR 54.4. 

2.2.3 Staff Evaluation 

The purpose of the staff’s evaluation was to determine whether the applicant properly identified 

the systems and structures within the scope of license renewal in accordance with 10 CFR 54.4. 

In LRA Section 2.1, the applicant described its methodology for identifying systems and 

structures within the scope of license renewal and subject to an AMR. The staff reviewed the 

scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify 

that the applicant properly implemented its methodology, the staff’s review focused on the 

implementation results shown in LRA Table 2.2-1 to confirm that there were no omissions of 

plant-level systems and structures that should be 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 
Structures and Components Subject to Aging Management Review 

 2-29 

to determine whether the systems and structures have any intended functions requiring their 

inclusion within the scope of license renewal. The staff’s review of the applicant’s 

implementation was conducted in accordance with the guidance in SRP-LR Section 2.2, 

“Plant-Level Scoping Results.” The staff reviewed LRA Section 2.2 and the UFSAR supporting 

information to determine whether the applicant failed to identify any systems and structures 

within the scope of license renewal. 

2.2.4 Conclusion 

On the basis of its review, as discussed above, 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 and, therefore, is acceptable. 
Structures and Components Subject to Aging Management Review 

 2-30 

2.3 Scoping and Screening Results: Mechanical Systems

This section documents the staff’s review of the applicant’s scoping and screening results for 

mechanical systems. Specifically, this section describes the following mechanical systems: 

• reactor vessel, internals, and reactor coolant system 

• engineered safety features systems 

• auxiliary systems 

• steam and power conversion systems 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to 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 

took into account, where applicable, the system functions described in the UFSAR. The 

objective was to determine whether the applicant has identified, in accordance with 

10 CFR 54.4, components and supporting structures for mechanical systems that 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 only: (a) SCs that have functions performed with moving parts or a 

change in configuration or properties, or (b) 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 RAI(s). 
Structures and Components Subject to Aging Management Review 

 2-31 

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System 

LRA Section 2.3.1 describes the reactor vessel, internals, and reactor coolant system SCs 

subject to an AMR for license renewal. The applicant described the supporting SCs of the 

reactor vessel, internals, and reactor coolant system in the following LRA sections: 

• LRA Section 2.3.1.1, “Control Rods” 

• LRA Section 2.3.1.2, “Fuel Assemblies” 

• LRA Section 2.3.1.3, “Nuclear Boiler Instrumentation” 

• LRA Section 2.3.1.4, “Reactor Internals” 

• LRA Section 2.3.1.5, “Reactor Pressure Vessel” 

• LRA Section 2.3.1.6, “Reactor Recirculation System” 

2.3.1.1 Control Rods 

2.3.1.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.1 describes the control rods, which are replaceable, mechanical components 

consisting of cruciform-shaped stainless steel assemblies containing neutron-absorbing material 

designed to be used for flux shaping and for reactivity control during reactor startup, power level 

changes, and shutdown. 

The purpose of the control rods is to absorb neutrons in the reactor core, thereby providing the 

means to adjust core power shape, compensate for reactivity changes caused by fuel and 

burnable poison depletion, and fully shut down the nuclear reaction. 

The control rods are comprised of four stainless steel wings assembled in a cruciform 

configuration. Each wing assembly is constructed of stainless steel material with boron carbide 

and/or hafnium as absorbing material. Each control rod has a handle assembly and a velocity 

limiter. The velocity limiter restricts the free-fall velocity of the control rod to preclude system 

damage in the event of a rod drop casualty. 

Near the end of the operating cycle, all control rods are withdrawn to maintain rated reactor 

power until scheduled reactor shutdown for refueling. Control rod absorption of neutrons 

chemically depletes the absorber material, and control rod lifetime is monitored. Upon reaching 

prescribed thresholds, control rods are scheduled for replacement during refueling outages. 

LRA Table 2.3.1-1 identifies the component types within the scope of license renewal but has 

identified no component types subject to an AMR. 

2.3.1.1.2 Conclusion 

The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any 

SSCs within the scope of license renewal. The staff found no such omissions. In addition, the 

staff sought to determine whether the applicant failed to identify any components subject to an 

AMR. The staff found that because the control rods are active components, there are no 

components subject to an AMR. Based on its review, the staff concludes that the applicant has 

adequately identified the control rod mechanical components within the scope of license 
Structures and Components Subject to Aging Management Review 

 2-32 

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1). 

2.3.1.2 Fuel Assemblies 

2.3.1.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.2 describes the fuel assemblies, which are high integrity components 

containing the fissionable material that sustains the nuclear reaction when the reactor core is 

made critical. 

Each fuel assembly is comprised of a fuel bundle and a channel that surrounds it. The fuel rods 

of each bundle are spaced and supported in a square array. The assembly is held together by 

upper and lower tie plates that give it structural support in the reactor and facilitate removal of 

the assembly during refueling. 

The bundle channel is fabricated from Zircaloy and provides the flow path outer periphery for 

the bundle coolant flow, supplies structural stiffness to the bundle and transmits seismic 

loadings to the core internal structures, provides a heat sink during a loss of coolant accident 

(LOCA), and supplies a surface for control rod guidance within the reactor core. 

The purpose of the fuel assemblies is to allow efficient heat transfer from the nuclear fuel to the 

reactor coolant and to maintain structural integrity providing a controllable, coolable bundle 

geometry and fission product barrier. 

LRA Table 2.3.1-2 identifies the component types within the scope of license renewal but has 

identified no component types subject to an AMR. 

2.3.1.2.2 Conclusion 

The staff reviewed the LRA and UFSAR to determine whether the applicant failed to identify any 

SSCs within the scope of license renewal. The staff found no such omissions. In addition, the 

staff sought to determine whether the applicant failed to identify any components subject to an 

AMR. The staff found that because the fuel assemblies are active components, there are no 

components subject to an AMR. Based on its review, the staff concludes that the applicant has 

adequately identified the control rod mechanical 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). 

2.3.1.3 Nuclear Boiler Instrumentation 

2.3.1.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.3 describes the nuclear boiler instrumentation system, which is designed to 

provide the means to measure parameters of reactor vessel level, pressure, temperature, core 

flow, core plate differential pressure, primary containment (drywell) pressure, main condenser 

pressure, and main turbine first stage pressure. 

The purpose of the nuclear boiler instrumentation system is to provide signals to the reactor 

protection system and the various emergency core cooling system (ECCS) logic to initiate 
Structures and Components Subject to Aging Management Review 

 2-33 

protective system functions such as reactor scram, emergency core cooling, primary 

containment isolation, recirculation pump trip, and alternate rod insertion. 

Nuclear boiler instrumentation is comprised of sensing lines, flow restricting orifices, isolation 

valves, excess flow check valves, transmitters, condensing chambers, and instruments. 

Reactor vessel level is measured by comparing the actual water level in the reactor vessel 

(variable leg) to a constant height of water in the reference leg. Reactor vessel pressure is 

measured by pressure instruments using the same piping that is used to measure the pressure 

in the reactor vessel level instrument reference legs. Reactor vessel temperature is measured 

through a thermocouple mounted in specific locations throughout the reactor vessel. Core plate 

differential pressure is measured by instrumentation that compares pressure below and above 

the core plate. Core flow is measured by instrumentation that determines the total flow through 

the jet pumps. Primary containment pressure is measured by pressure transmitters connected 

to sensing lines open to the primary containment atmosphere. Main condenser pressure and 

main turbine first stage pressure are measured by pressure transmitters connected to sensing 

lines. 

LRA Table 2.3.1-3 identifies the component types within the scope of license renewal and 

subject to an AMR. 

2.3.1.3.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the nuclear boiler 

instrumentation mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.1.4 Reactor Internals 

2.3.1.4.1 Summary of Technical Information in the Application

LRA Section 2.3.1.4 describes the reactor internals system, which is a mechanical system 

whose components are contained within the reactor pressure vessel (RPV) and extend beyond 

the RPV to form a portion of the reactor coolant boundary. 

The purpose of the reactor internals system is to provide support for the core and other internal 

components, maintain the fuel in a coolable geometry during normal and accident conditions, 

provide proper distribution of the coolant delivered to the vessel, provide a floodable volume, 

and maintain the reactor coolant pressure boundary. 

The reactor internals consist of the core shroud, core plate, core spray lines and spargers, fuel 

supports, control rod drive assemblies, instrumentation dry tubes, jet pump assemblies, steam 

dryer assembly, and the top guide. 

LRA Table 2.3.1-4 identifies the component types within the scope of license renewal and 

subject to an AMR. 
Structures and Components Subject to Aging Management Review 

 2-34 

2.3.1.4.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the reactor internals 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.1.5 Reactor Pressure Vessel 

2.3.1.5.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.5 describes the RPV, which is designed to contain the reactor coolant and 

facilitate the transfer of heat from the core. The vessel provides a floodable volume to assure 

adequate core cooling in the event of a breach in the coolant boundary external to the RPV. 

The purpose of the RPV is to form part of the reactor coolant boundary and to serve as a 

radioactive material barrier during normal operations and following abnormal operational 

transients and accidents. 

The RPV contains the reactor core, the reactor internals, and reactor core coolant moderator. It 

consists of the following major components: the cylindrical shell and flange, the top head and 

flange, the bottom head, welds, nozzles, safe ends, closure studs, internal supports, and 

external supports, including the skirt assembly. 

LRA Table 2.3.1-5 identifies the component types within the scope of license renewal and 

subject to an AMR. 

2.3.1.5.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the RPV mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the system components subject to an AMR in accordance 

with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.1.6 Reactor Recirculation System 

2.3.1.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.6 describes the reactor recirculation system, which provides forced 

circulation of reactor coolant through the core for heat removal and the ability to maintain a 

reactor vessel floodable volume in the event of a piping integrity failure. 

The purpose of the reactor recirculation system is to provide a means to control reactor power 

within a limited range without the need for manipulation of the control rods. It delivers 

recirculated drive water flow to the reactor vessel through two separate pumped loops, each 

with an individually controllable variable speed pump, 5 jet pump risers, and 10 jet pumps. 

The reactor recirculation system consists of the reactor recirculation main loop piping, 

recirculation pumps and motors, recirculation motor generator sets, recirculation system flow 
Structures and Components Subject to Aging Management Review 

 2-35 

control, and recirculation pump trip logic. The path of coolant through each of these loops is as 

follows: reactor coolant enters the vessel annulus region and then exits the reactor vessel 

through the loop’s outlet nozzle and into the recirculation pump suction piping. The coolant then 

goes through the pump and out into the discharge piping, which feeds into five jet pump risers. 

These risers distribute the flow into the vessel, where it discharges the coolant into two jet 

pumps. The coolant flow mixes with coolant from the annulus region, and this mixture travels 

through the orifices at the bottom of the core and flows up through the core where the bulk 

boiling produces steam. This steam-water mixture enters the moisture separators and the 

steam dryers, where the water is separated from the steam. The water flows downward into the 

annulus region where the flow path is repeated. 

LRA Table 2.3.1-6 identifies the component types within the scope of license renewal and 

subject to an AMR. 

2.3.1.6.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the reactor 

recirculation system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.2 Engineered Safety Features 

LRA Section 2.3.2 describes the engineered safety features system SCs subject to an AMR for 

license renewal. The applicant described the supporting SCs of the engineered safety features 

system in the following LRA sections: 

• LRA Section 2.3.2.1, “Automatic Depressurization System (ADS)” 

• LRA Section 2.3.2.2, “Containment Hydrogen Recombiner System” 

• LRA Section 2.3.2.3, “Core Spray System” 

• LRA Section 2.3.2.4, “Filtration, Recirculation, and Ventilation System” 

• LRA Section 2.3.2.5, “High Pressure Coolant Injection (HPCI) System” 

• LRA Section 2.3.2.6, “Hydrogen and Oxygen Analyzer System” 

• LRA Section 2.3.2.7, “Reactor Core Isolation Cooling (RCIC) System” 

• LRA Section 2.3.2.8, “Residual Heat Removal (RHR) System”

• LRA Section 2.3.2.9, “Vacuum Relief Valve System” 

2.3.2.1 Automatic Depressurization System 

2.3.2.1.1 Summary of Technical Information in the Application

LRA Section 2.3.2.1 describes the ADS, which is a standby ECCS designed to automatically 

depressurize the RPV during a small break LOCA when the HPCI system is inoperable or 

cannot maintain water level in the vessel and pressure remains above the design capability of 

the low-pressure ECCSs. It accomplishes this by opening 5 out of 14 nuclear pressure relief 

system relief valves to depressurize the RPV to the suppression pool. 
Structures and Components Subject to Aging Management Review 

 2-36 

The purpose of the ADS is to provide automatic depressurization of the RPV in the event of a 

small break in the RPV pressure boundary where coolant inventory cannot be maintained and 

RPV pressure remains above the design capability of the low-pressure ECCSs. 

LRA Table 2.3.2-1 identifies the component types within the scope of license renewal but has 

identified no component types subject to an AMR. 

2.3.2.1.2 Conclusion 

Based on the results of the staff evaluation of the LRA and UFSAR, the staff concludes that the 

applicant has appropriately identified the ADS mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.2.2 Containment Hydrogen Recombiner System 

2.3.2.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.2 describes the containment hydrogen recombiner system, which is 

comprised of two separate and redundant trains, each capable of recombining hydrogen and 

oxygen at a rate in excess of their expected post-LOCA production. Each containment 

hydrogen recombiner train has a blower assembly, which provides the motive force to transport 

the drywell atmosphere to the recombiner reaction chamber for processing and then provides a 

return flow path to the torus. Each train also has a main heater that is used to raise the 

operating temperature to the reaction temperature required to allow spontaneous recombination 

of hydrogen and oxygen. The containment hydrogen recombiner system is designed to control 

hydrogen and oxygen concentrations in the primary containment postulated to be generated 

following a beyond DBA. 

The containment hydrogen recombiner system contains safety-related components relied upon 

to remain functional during and following DBEs. In addition, the system is relied upon in safety 

analyses or plant evaluations to perform a function that demonstrates compliance with the NRC 

regulations for EQ (10 CFR 50.49). 

LRA Table 2.3.2-2 identifies the components subject to an AMR for the containment hydrogen 

recombiner system by component type and intended function. 

2.3.2.2.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.2, LRA Table 2.3.2-2, and UFSAR Sections 6.2.5 and 

7.3.1.1.6 using the evaluation methodology described in SER Section 2.3 and the guidance in 

SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has not omitted from the scope of license renewal any components with 

intended functions required by 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). 
Structures and Components Subject to Aging Management Review 

 2-37 

The staff’s review of LRA Section 2.3.2.2 identified areas where additional information was 

necessary in order to complete its review of the applicant’s scoping and screening results. 

By letter dated March 22, 2010, the staff issued RAI 2.3.2.2-1 which notes that the component 

type “Fan Housing” on the license renewal drawing is enclosed by another housing made of 

carbon steel. The staff requested that the applicant provide the purpose of the enclosure 

around the fan and state whether it is within the scope of license renewal, in accordance with 

10 CFR 54.4(a), and if it is subject to an AMR, in accordance with 10 CFR 54.21(a)(1). 

By letter dated April 6, 2010, the applicant stated that: 

The blower unit (Blower AV-215) as shown on license Renewal Drawing 

LR-M-58, Sheet 1 Rev. 0 is comprised of an inner blower/motor unit and an outer 

carbon steel housing. The purpose of the outer blower unit housing is to provide 

a leak tight pressure boundary enclosure around the blower/motor assembly to 

eliminate any potential for hydrogen gas mixture leak to the surrounding 

environment. Both the outer housing and the inner fan housing provide a 

pressure boundary function, are within scope of license renewal, and are subject 

to aging management review. They are both captured as component type “Fan 

Housing” in Tables 2.3.2-2 and 3.2.2-1. 

The staff’s review found the applicant’s response to RAI 2.3.2.2-1 acceptable because the 

response provided the purpose of the enclosure around the fan and stated that it is within the 

scope of license renewal and subject to an AMR. 

2.3.2.2.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the containment hydrogen recombiner system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1). 

2.3.2.3 Core Spray System 

2.3.2.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.3 describes the core spray system, which is a low-pressure ECCS designed 

to provide cooling water for removal of decay heat from the reactor core following a postulated 

LOCA. Large to intermediate pipe breaks in the reactor coolant system relieve sufficient 

pressure to permit the core spray system to operate to limit fuel cladding maximum temperature. 

Core spray also functions in conjunction with the ADS during intermediate to small pipe breaks 

in the reactor coolant system to limit fuel cladding maximum temperature. 

The purpose of the core spray system is to provide for the post-LOCA removal of decay heat 

from the reactor core so that fuel clad temperature limits are maintained for the entire spectrum 

of postulated LOCAs. The core spray system achieves its purpose by delivering a low-pressure 

spray pattern over the fuel following a LOCA, which limits the cladding temperature. The core 

spray system can be initiated automatically by either reactor low water level, or high drywell well 
Structures and Components Subject to Aging Management Review 

 2-38 

level, or it can be initiated manually. The core spray system delivers cooling water independent 

of other engineered safety systems, and it can also be operated on emergency power. 

The core spray system is comprised of two independent cooling loops, each of which contain 

two centrifugal pumps, spray sparger, and associated valves and piping. The main flow path for 

each core spray loop takes suction from the suppression pool through two core spray pumps, 

continuing through the two outboard motor isolation valves, through the inboard air operated 

stop check valve, and into the reactor vessel for discharge onto the core through the associated 

spray sparger. The core spray system can also take suction from the condensate storage tank. 

LRA Table 2.3.2-3 identifies the components subject to an AMR for the core spray system by 

component type and intended function. 

2.3.2.3.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the core spray 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.2.4 Filtration, Recirculation, and Ventilation System 

2.3.2.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.4 describes the filtration, recirculation, and ventilation system, which consists 

of two subsystems, the recirculation system and the ventilation system, that are required to 

perform post-accident, safety-related functions simultaneously. The recirculation system, 

located inside the reactor building, is designed to recirculate and filter the air in the reactor 

building following a LOCA, or other high radioactivity accident, to reduce offsite doses 

significantly below 10 CFR Part 100 guidelines. The ventilation system, also located inside the 

reactor building, maintains the building at a negative pressure with respect to the outdoors. The 

system takes suction from the discharge duct of the recirculation system and discharges the air 

through filters to the outdoors via a vent at the top of the reactor building. 

The filtration, recirculation, and ventilation system contains safety-related components relied 

upon to remain functional during and following DBEs. In addition, the filtration, recirculation, 

and ventilation system performs functions that support EQ and SBO. 

LRA Table 2.3.2-4 identifies the components subject to an AMR for the filtration, recirculation, 

and ventilation system by component type and intended function. 

2.3.2.4.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the filtration, 

recirculation, and ventilation system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-39 

2.3.2.5 High Pressure Coolant Injection System 

2.3.2.5.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.5 describes the HPCI system, which is part of the ECCS. The main function 

of the HPCI system is to protect the core in the case of a small break in the reactor coolant 

pressure boundary which does not cause rapid depressurization. This permits the plant to be 

safely shut down, by maintaining sufficient reactor vessel water inventory while the reactor 

vessel is depressurized. Initiation of HPCI occurs upon receipt of a high drywell pressure or 

low-low reactor water level signal. The HPCI system can be operated on direct current (DC) 

emergency power. 

The primary purpose of the HPCI system is to provide sufficient coolant to the reactor vessel to 

prevent excessive fuel clad temperatures in the event of a small break LOCA that does not 

result in rapid depressurization of the reactor vessel. The HPCI system accomplishes this 

purpose by delivering sufficient high pressure flow to maintain reactor vessel inventory and 

ensures that the reactor core is not uncovered. The HPCI system operation is initiated 

automatically by either reactor low-low water level, high drywell pressure, or can be initiated 

manually. 

The HPCI system contains a turbine driven pump. Steam is extracted from the main steam 

lines to run the pump. The turbine exhaust is routed to the suppression pool. Because of this, it 

is capable of supplying water even during an SBO. Water suction can be aligned to the 

condensate storage tank or to the suppression pool. The water then gets pumped to the suction 

of the HPCI pump. The HPCI pump discharges to the RPV through the core spray sparger 

connected to core spray pumps “A” and “C.” The pump also discharges to the reactor vessel 

through the feedwater line “A” header. There is also a lube oil system for HPCI which provides 

oil to the main pump bearings, the turbine stop and control valve, and multiple other 

components. 

LRA Table 2.3.2-5 identifies the components subject to an AMR for the HPCI system by 

component type and intended function. 

2.3.2.5.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the HPCI system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.2.6 Hydrogen and Oxygen Analyzer System 

2.3.2.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.6 describes the hydrogen and oxygen analyzer system, which is a gas 

sampling system, consisting of two identical redundant trains, designed to monitor the hydrogen 

and oxygen concentration in the primary containment during accident conditions. The hydrogen 

and oxygen analyzer system includes a permanently connected torus supplementary oxygen 

analyzer panel in the “A” train between the torus sample incoming and return lines. Additionally, 

the hydrogen and oxygen analyzer system includes a portable drywell supplementary oxygen 
Structures and Components Subject to Aging Management Review 

 2-40 

analyzer panel that can be connected through the leak detection and radiation monitoring 

system. 

The purpose of the hydrogen and oxygen analyzer system is to monitor the primary containment 

atmosphere to ensure that oxygen and hydrogen levels do not approach flammability limits. 

The hydrogen and oxygen analyzer system accomplishes this purpose post-accident and during 

normal power operations. During post-accident operation, the hydrogen and oxygen analyzer 

system processes a drywell atmosphere sample through one of two redundant hydrogen and 

oxygen analyzer loops. During normal power operation, the hydrogen and oxygen analyzer 

system is in the standby mode, except for calibration of maintenance, and the supplementary 

oxygen monitoring portion of the hydrogen and oxygen analyzer system is in service to monitor 

the oxygen concentration of the atmosphere in the drywell and torus areas. The purpose of the 

supplementary oxygen analyzers is to provide an alternate method of monitoring torus and 

drywell oxygen concentration. 

LRA Table 2.3.2-6 identifies the components subject to an AMR for the hydrogen and oxygen 

analyzer system by component type and intended function. 

2.3.2.6.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the hydrogen and 

oxygen analyzer system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.2.7 Reactor Core Isolation Cooling System 

2.3.2.7.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.7 describes the RCIC system, which is a high pressure, safety-related 

system designed to ensure sufficient reactor water inventory is maintained in the reactor vessel 

to allow for adequate core cooling. The primary purpose of the RCIC system is to provide 

sufficient coolant to the reactor vessel to prevent excessive fuel cladding temperatures during a 

reactor shutdown in which feedwater flow is not available. The RCIC can be activated 

automatically by reactor low-low water level or manually initiated. RCIC can be operated on DC 

emergency power. 

The purpose of the RCIC system is to provide sufficient coolant to the reactor vessel to prevent 

excessive fuel clad temperatures during a reactor shutdown in which feedwater flow is not 

available. The RCIC system accomplishes this purpose by delivering sufficient high pressure 

flow to maintain reactor vessel inventory and to ensure that the reactor core is not uncovered. 

The RCIC system operation is initiated automatically by reactor low-low water level or can be 

initiated manually. 

The RCIC system has a steam-driven turbine pump and normally takes suction from the 

condensate storage tanks. It can also take suction from the suppression pool. The water is 

injected into the reactor vessel via a feedwater line. The steam to run the pump is extracted 

from the main steam lines. The steam is discharged to the suppression pool, which allows the 

pump to run during an SBO. 
Structures and Components Subject to Aging Management Review 

 2-41 

LRA Table 2.3.2-7 identifies the components subject to an AMR for the RCIC system by 

component type and intended function. 

2.3.2.7.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the RCIC system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.2.8 Residual Heat Removal System 

2.3.2.8.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.8 describes the RHR system, which is a low-pressure ECCS designed to 

provide cooling water for the removal of fission product heat from the reactor core and primary 

containment following a postulated DBE or normal operation. 

The RHR system has three primary and two secondary functions of operation. The first two 

primary functions of the RHR system are to provide for the post-DBEs fission product heat 

removal from the reactor core so that the fuel clad temperature limit is not exceeded and heat is 

removed from the primary containment to ensure structural pressure and temperature limits are 

not exceeded. The RHR system accomplishes the two primary purposes by the low-pressure 

coolant injection and containment spray modes which deliver low-pressure coolant to the 

reactor vessel and to primary containment, which limits peak clad temperature to less than the 

maximum allowable limit, and to primary containment, maintaining the structure temperature 

and pressure less than its maximum design limit. Fission product decay heat is removed from 

the core and primary containment by the RHR system and is transported to the torus. The RHR 

heat exchangers remove the heat from the torus and transfer the heat to the safety auxiliary 

cooling system, which is evaluated in the closed-cycle cooling water system. 

The third primary function of the RHR system is to remove the decay and sensible heat from the 

reactor primary system to permit cold shutdown for refueling. The RHR system accomplishes 

this purpose in the shutdown cooling mode by manually opening valves that have piping 

interconnections with reactor recirculation system suction piping, directing flow through the RHR 

heat exchangers which removes heat from the reactor and returns the flow to reactor 

recirculation discharge piping, therefore, allowing shutdown. 

The two secondary functions of the RHR system are to augment fuel pool cooling by removing 

decay heat of the spent fuel and to provide an alternate source of water from a non-nuclear 

steam supply system (NSSS) intertie between the station service water system and the RHR 

system piping, which allows water to flood the reactor containment during the period following a 

LOCA. 

The RHR system consists of four main pumps, two heat exchangers, associated piping, and 

valves. There are two physically separated loops each consisting of two pumps and one heat 

exchanger. The two separated loops prevent a single failure from causing both loops to be 

inoperable and thus the entire system being inoperable. The RHR system can: (1) restore and 

maintain the coolant inventory in the reactor vessel to cool the core in the case of a LOCA, 

(2) provide drywell and suppression pool cooling in post-LOCA situations, and (3) provide RHR 
Structures and Components Subject to Aging Management Review 

 2-42 

when the main heat sink is unavailable, such as during normal shutdown. The RHR system can 

operate in six modes: (1) ECCS low-pressure coolant injection, (2) primary containment spray, 

(3) torus cooling, (4) shutdown cooling, (5) fuel pool cooling, and (6) alternate injection. 

LRA Table 2.3.2-8 identifies the components subject to an AMR for the RHR system by 

component type and intended function. 

2.3.2.8.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the RHR system 

mechanical components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.2.9 Vacuum Relief Valve System 

2.3.2.9.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.9 describes the vacuum relief valve system, which consists of two 

independent subsystems: the torus to drywell pressure relief subsystem and the reactor building 

to torus pressure relief subsystem. 

The primary containment is provided with a vacuum relief valve system to equalize the pressure 

between the drywell and the torus, and between the torus and the reactor building. The vacuum 

relief valve system assures that the external design pressure limits of the two chambers are not 

exceeded. The DBA is the complete instantaneous circumferential break of one of the 

recirculation suction lines while the reactor is at rated power. The air-stream mixture is vented 

to the torus. Within the first few seconds, drywell air is swept into the torus water space. 

Because of the high velocity steam within the vents, the air cannot diffuse back into the drywell 

and it is effectively forced into the torus water space. After blowdown is complete, steam is 

present in the drywell. As the steam condenses on various surfaces and the drywell spray is 

activated, the drywell pressure drops. This allows the torus to drywell vacuum breakers to open 

and admit the gas from the torus air space into the drywell, thus equalizing the pressures. 

The torus to drywell pressure relief subsystem is designed to prevent torus water from backing 

up into the drywell during various reactor leakage and suppression condensation modes. The 

purpose of the torus to drywell pressure relief subsystem is to prevent the drywell pressure from 

dropping significantly below the pressure in the torus airspace, and to prevent exceeding design 

external pressures of the drywell. The torus and drywell pressure relief subsystem is comprised 

of vacuum breakers that accomplish their purpose by automatically venting non-condensable 

gas (carryover to the torus during an accident) back to the drywell from the torus. 

The reactor building to torus pressure relief subsystem limits the torus negative pressure 

relative to the reactor building pressure. This subsystem limits drywell negative pressures 

relative to the reactor building pressure and permits gas flow only inward from the reactor 

building to the primary containment. The reactor building to torus pressure relief subsystem is 

comprised of vacuum breakers that accomplish their purpose by opening automatically at a 

predetermined differential pressure. 
Structures and Components Subject to Aging Management Review 

 2-43 

LRA Table 2.3.2-9 identifies the components subject to an AMR for the vacuum relief valve 

system by component type and intended function. 

2.3.2.9.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the vacuum relief 

valve system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3 Auxiliary Systems 

LRA Section 2.3.3 identifies the auxiliary system SCs subject to an AMR for license renewal. 

The applicant described the supporting SCs of the auxiliary systems in the following LRA 

sections: 

● LRA Section 2.3.3.1, “Chilled Water System” 

● LRA Section 2.3.3.2, “Closed Cycle Cooling Water System” 

● LRA Section 2.3.3.3, “Compressed Air System” 

● LRA Section 2.3.3.4, “Containment Inerting and Purging System” 

● LRA Section 2.3.3.5, “Control Area Chilled Water System” 

● LRA Section 2.3.3.6, “Control Rod Drive System” 

● LRA Section 2.3.3.7, “Control Room and Control Area HVAC Systems” 

● LRA Section 2.3.3.8, “Cranes & Hoists” 

● LRA Section 2.3.3.9, “Equipment and Floor Drainage System” 

● LRA Section 2.3.3.10, “Fire Protection System” 

● LRA Section 2.3.3.11, “Fire Pump House Ventilation System” 

● LRA Section 2.3.3.12, “Fresh Water Supply System” 

● LRA Section 2.3.3.13, “Fuel Handling and Storage System” 

● LRA Section 2.3.3.14, “Fuel Pool Cooling and Cleanup System” 

● LRA Section 2.3.3.15, “Hardened Torus Vent System” 

● LRA Section 2.3.3.16, “Hydrogen Water Chemistry System” 

● LRA Section 2.3.3.17, “Leak Detection and Radiation Monitoring System” 

● LRA Section 2.3.3.18, “Makeup Demineralizer System” 

● LRA Section 2.3.3.19, “Primary Containment Instrument Gas System” 

● LRA Section 2.3.3.20, “Primary Containment Leakage Rate Testing System” 

● LRA Section 2.3.3.21, “Process and Post-Accident Sampling Systems” 

● LRA Section 2.3.3.22, “Radwaste System” 

● LRA Section 2.3.3.23, “Reactor Building Ventilation System” 

● LRA Section 2.3.3.24, “Reactor Water Cleanup System” 

● LRA Section 2.3.3.25, “Remote Shutdown Panel Room HVAC System” 

● LRA Section 2.3.3.26, “Service Water Intake Ventilation System” 

● LRA Section 2.3.3.27, “Service Water System” 

● LRA Section 2.3.3.28, “Standby Diesel Generator Area Ventilation Systems” 

● LRA Section 2.3.3.29, “Standby Diesel Generators and Auxiliary Systems” 

● LRA Section 2.3.3.30, “Standby Liquid Control System” 

● LRA Section 2.3.3.31, “Torus Water Cleanup System” 

● LRA Section 2.3.3.32, “Traversing Incore Probe System” 
Structures and Components Subject to Aging Management Review 

 2-44 

Auxiliary Systems Generic Requests for Additional Information. In a letter dated April 15, 2010, 

the staff issued RAI 2.3-01 and noted instances where it was unable to identify the license 

renewal boundary because: (1) continuations were not provided or are incorrect, or (2) the 

continuation drawing was not provided. The applicant was requested to provide additional 

information on the continuations of the license renewal boundary. 

In a response dated May 11, 2010, the applicant provided sufficient additional information to 

locate the license renewal boundaries. When drawings do not exist, the applicant stated that 

there were no additional component types within the license renewal boundary that are subject 

to an AMR. 

Based on its review, the staff finds the applicant’s response to RAI 2.3-01 acceptable because 

the applicant provided the continuation locations or stated that there are no additional 

component types subject to an AMR within the license renewal boundary. Therefore, the staff’s 

concern described in RAI 2.3-01 is resolved. 

2.3.3.1 Chilled Water System 

2.3.3.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.1 describes the chilled water system, which is a closed-loop system designed 

to provide demineralized cooling water to plant air handling and cooling units during normal 

operation in the reactor, auxiliary, and turbine buildings. 

The purpose of the chilled water system is to remove heat from the plant’s cooling coils and 

coolers during various modes of reactor operation. The chilled water system accomplishes this 

purpose by transferring heat from the plant’s cooling coils and coolers to the chiller units, which 

reject the heat from the chilled water to the turbine auxiliary cooling system portion of the 

closed-cycle cooling water system. 

LRA Table 2.3.3-1 identifies the components subject to an AMR for the chilled water system by 

component type and intended function. 

2.3.3.1.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the chilled 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 the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.2 Closed-Cycle Cooling Water System 

2.3.3.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.2 describes the closed-cycle cooling water system, which is a normally 

operating closed-loop mechanical system designed to provide demineralized cooling water to 

various safety-related and nonsafety-related equipment within the plant. The closed-cycle 

cooling water system consists of the following two independent plant systems: the safety and 

turbine auxiliary cooling plant system and the reactor auxiliary cooling plant system. 
Structures and Components Subject to Aging Management Review 

 2-45 

The safety and turbine auxiliary cooling plant system is designed to provide a heat sink for 

engineering safety features equipment and turbine generator auxiliary equipment by circulating 

cooling water in a closed-loop system. The purpose of the safety auxiliary cooling plant system 

is to remove heat from safety-related loads located within the reactor building and auxiliary 

building during various modes of reactor operation. The purpose of the turbine auxiliary cooling 

plant system is to remove heat from nonsafety-related loads within the turbine building to meet 

the turbine generator auxiliary cooling requirements during normal operation and normal 

shutdown conditions. The safety and turbine auxiliary cooling plant system accomplishes its 

purpose by transferring heat from these nonsafety-related loads to the service water system, 

through the safety auxiliary cooling plant system heat exchangers. 

The purpose of the reactor auxiliary cooling plant system is to remove heat from non-essential 

(non-engineering safety feature) loads located in the reactor building, auxiliary building, 

radwaste building, and turbine building that carry radioactive fluids. The reactor auxiliary 

cooling plant system accomplishes its purpose by transferring heat from these loads to the 

service water system, through the reactor auxiliary cooling plant system heat exchangers. 

LRA Table 2.3.3-2 identifies the components subject to an AMR for the closed-cycle cooling 

water system by component type and intended function. 

2.3.3.2.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.2, UFSAR Sections 9.2.2 and 9.2.8, 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 necessary to complete the review of the applicant’s scoping and 

screening results. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.2-01 and noted that license renewal 

drawing LR-M-13-1, sheet 1, at locations D-3 and D-5, shows lines 4”-HBB-024 and 

4”-HBB-023, designated as 10 CFR 54.4(a)(1), connected to lines 6”-HBD-003 and 4”-HBD-018, 

designated as 10 CFR 54.4(a)(2). The applicant was requested to provide additional 

information to locate the anchors for the 6”-HBD-003 and 4”-HBD-018 lines between the end of 

the (a)(2) scoping boundary and the safety-nonsafety interface. 

The applicant’s response, dated May 11, 2010, described the location of the anchors, which are 

within the existing (a)(2) scoping boundary. This conforms to the applicant’s methodology and 

did not result in the inclusion of any additional components within the scope of license renewal. 

Therefore, the staff’s concern described in RAI 2.3.3.2-01 is resolved. 

2.3.3.2.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the closed-cycle 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 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-46 

2.3.3.3 Compressed Air System 

2.3.3.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.3 describes the compressed air system, which is a normally operating 

system designed to provide clean and dry compressed air in support of plant operation. 

The compressed air system consists of the service and instrument air plant system. The 

purpose of the service and instrument air plant system is to provide clean and dry compressed 

air to pneumatically-operated instruments and valves. To accomplish this purpose, the system 

takes air from outside of the turbine building and processes the air through air compressors, 

intercoolers, aftercoolers, moisture separators, air receivers, and air dryers for distribution to 

components in support of plant operation. 

LRA Table 2.3.3-3 identifies the components subject to an AMR for the compressed air system 

by component type and intended function. 

2.3.3.3.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the compressed 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 the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.4 Containment Inerting and Purging System 

2.3.3.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.4 describes the containment inerting and purging system, which is a 

pressurized gas system designed to maintain an inert atmosphere within the primary 

containment during plant operations to preclude energy releases from a possible 

hydrogen-oxygen reaction following a postulated LOCA. The inert environment also precludes 

the possibility of an exposure fire within the primary containment. 

The purpose of the containment inerting and purging system is to provide a means of reducing 

the oxygen concentration in the containment for normal power operations and a means of 

reestablishing oxygen concentration to normal life supporting levels to allow access to the 

primary containment. To ready the primary containment for power operation, the containment 

inerting and purging system accomplishes inerting by introducing nitrogen from the liquid 

nitrogen vaporizer to displace the oxygen from the free volume in the primary containment. The 

containment inerting and purging system depends on the drywell air cooling system to provide 

effective containment atmosphere mixing, since the containment inerting and purging system 

does not have any fans. Also, the containment inerting and purging system depends on the 

torus to drywell portion of the vacuum relief valve system for effective mixing of the torus 

atmosphere. 

To ready the primary containment for shutdown, the containment inerting and purging system 

accomplishes purging and de-inerting through interfacing with the containment prepurge 

cleanup system portion of the reactor building ventilation system. 
Structures and Components Subject to Aging Management Review 

 2-47 

LRA Table 2.3.3-4 identifies the components subject to an AMR for the containment inerting and 

purging system by component type and intended function. 

2.3.3.4.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.4, LRA Table 2.3.3-4, and UFSAR Section 6.2.5.2.1 using 

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has not omitted from the scope of license renewal any components with 

intended functions required by 10 CFR 54.4(a). The staff then reviewed those components that 

the applicant has identified as within the scope of license renewal to verify that the applicant has 

not omitted any passive and long-lived components subject to an AMR, in accordance with the 

requirements of 10 CFR 54.21(a)(1). 

The staff’s review of LRA Section 2.3.3.4 identified areas where additional information was 

necessary in order to complete its review of the applicant’s scoping and screening results. 

In a letter dated March 22, 2010, the staff issued RAI 2.3.3.4-1 requesting that the applicant 

clarify if valve numbers V024, V025, and V026 shown on license renewal drawings LR-M-57-1, 

sheet 1 and LR-M-76-1, sheet 1 are the same and if they are within the scope of license 

renewal. 

By letter dated April 6, 2010, the applicant stated that the valves are the same and within the 

scope of license renewal. 

The staff’s review found the applicant’s response to RAI 2.3.3.4-1 acceptable because the 

applicant provided the requested clarification and stated that the subject valves are within the 

scope of license renewal. The staff’s concern described in RAI 2.3.3.4-1 is resolved. 

2.3.3.4.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the containment inerting and purging system mechanical components within the scope 

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1). 

2.3.3.5 Control Area Chilled Water System 

2.3.3.5.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.5 describes the control area chilled water system, which is a normally 

operating mechanical system designed to provide chilled water to plant ventilation cooling coils. 

The control area chilled water system consists of two plant systems: control room chilled water 

system and the safety-related panel room chilled water system. 

The purpose of the control area chilled water system is to provide cooling water to the 

safety-related and nonsafety-related ventilation systems for the control room, control area 
Structures and Components Subject to Aging Management Review 

 2-48 

heating ventilation and air conditioning (HVAC) system, and the standby diesel generator area 

ventilation system. 

The control area chilled water system accomplishes this by providing a continuous supply of 

chilled water to the cooling coils in the control room, control area ventilation system, and the 

standby diesel generator area ventilation system during normal and accident conditions. 

Each of the control area chilled water plant systems consists of two independent and fully 

redundant chilled water loops. The redundant trains will start on one of the following conditions: 

low flow conditions indicated on in-service train, or either high or low chilled water supply 

temperatures for the operating loop. 

LRA Table 2.3.3-5 identifies the components subject to an AMR for the control area chilled 

water system by component type and intended function. 

2.3.3.5.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.5, UFSAR Section 9.2.7.2, 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 necessary to complete the review of the applicant’s scoping and screening 

results. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.5-01 and noted that license renewal 

drawing LR-M-90-1, sheet 3, locations C-5 and H-5, shows a portion of piping within scope for 

10 CFR 54.4(a)(1) up to valves V9990 and V9982. The drawing indicates that downstream of 

the valves, the piping is within scope for 10 CFR 54.4(a)(2) but is still Q-listed and seismic 

Category 1. This appears to be safety-related piping within scope for (a)(2), which would 

conflict with the scoping procedure described in the application. The applicant was requested to 

provide additional information to clarify the scoping classification. 

In its response dated May 11, 2010, the applicant stated that valves V9990 and V9982 are 

within scope for 10 CFR 54.4(a)(1) and the Q-flags are incorrectly shown on the downstream 

piping, instead of on the downstream edge of the respective valves. 

Based on its review and the applicant’s explanation of the Q-flags, the staff finds the applicant’s 

response to RAI 2.3.3.5-01 acceptable because the applicant clarified the scoping classification 

of the pipe sections in question. Therefore, the staff’s concern described in RAI 2.3.3.5-01 is 

resolved. 

2.3.3.5.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the control area chilled 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 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-49 

2.3.3.6 Control Rod Drive System 

2.3.3.6.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.6 describes the control rod drive system, which is a high-pressure, low-flow 

system designed to rapidly insert all control rods into the core in response to manual action or 

an automatic signal from the reactor protection system. It also incrementally positions control 

rods in response to signals from the reactor manual control system. 

The control rod drive system consists of the control rod drive hydraulic system and control rod 

drive removal and cleaning system. 

The purpose of the control rod drive hydraulic system is to rapidly insert negative reactivity to 

shut down the reactor under accident or transient conditions and to manage reactivity in the 

reactor core by inserting or withdrawing control rods for power level control and flux shaping 

during normal operation. The control rod drive hydraulic system accomplishes this by providing 

water at the required operating pressures to the control rod drives for cooling and for all types of 

control rod motion in response to inputs from the reactor manual control system, redundant 

reactivity control system, and reactor protection system. 

The secondary purpose of the control rod drive system is to provide a water source for pump 

seal operation and makeup. This includes providing reactor recirculation pump seal purge and 

makeup water to the reactor water level reference leg condensing chambers. 

LRA Table 2.3.3-6 identifies the components subject to an AMR for the control rod drive system 

by component type and intended function. 

2.3.3.6.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the control rod drive 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.7 Control Room and Control Area HVAC Systems

2.3.3.7.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.7 describes the control room and control area HVAC systems, which are 

mechanical systems designed to provide normal and emergency ventilation to the control room 

and associated areas in the auxiliary building. 

The purpose of the control room and control area HVAC systems is to maintain habitability 

conditions within the control room envelope, maintain area temperatures within acceptable 

limits, maintain hydrogen concentrations for all battery rooms below 2 percent and remove 

smoke and noxious gases in the event of a fire. The control area ventilation system 

accomplishes this purpose by regulating temperature, humidity, and pressure during normal and 

accident conditions, and by providing adequate ventilation flow capacity. 
Structures and Components Subject to Aging Management Review 

 2-50 

LRA Table 2.3.3-7 identifies the components subject to an AMR for the control room and control 

area HVAC systems by component type and intended function. 

2.3.3.7.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the control room and 

control area HVAC systems mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.8 Cranes and Hoists 

2.3.3.8.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.8 describes the cranes and hoists, which consist of load handling bridge 

cranes, jib cranes, lifting devices, and hoists provided throughout the facility to support 

operation and maintenance activities. Cranes and hoists include those required to comply with 

the requirements of NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants, 

Resolution of Generic Technical Activity A36,” and hoists for handling light loads. Major cranes 

include the reactor building polar crane and the turbine building crane. 

The reactor building polar crane services the operating floor and is used to lift heavy loads such 

as the reactor closure head. The crane is also used to handle new fuel and transport the spent 

fuel cask. The reactor building polar crane main hoist and auxiliary hoist are designed to be 

single failure proof in conformance with NUREG-0554, “Single Failure-Proof Cranes for Nuclear 

Power Plants,” and NUREG-0612. The crane is designed to include seismic loading for the 

operating basis earthquake (OBE) and safe-shutdown earthquake (SSE) seismic events and is 

classified as seismic Category I. 

The turbine building crane services the operating floor and is used to lift loads to support turbine 

repairs or maintenance. The crane is designed as seismic Category II. 

The purpose of cranes and hoists is to safely move material and equipment as required in order 

to support operations and maintenance activities. The cranes and hoists accomplish this 

through compliance with NUREG-0612 and the use of written procedures so damage resulting 

from a heavy load drop will not prevent safe shutdown of the reactor. 

LRA Table 2.3.3-8 identifies the components subject to an AMR for the cranes and hoists by 

component type and intended function. 

2.3.3.8.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the cranes and 

hoists mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-51 

2.3.3.9 Equipment and Floor Drainage System 

2.3.3.9.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.9 describes the equipment and floor drainage system, which is a normally 

operating mechanical system designed to collect and transfer radioactive and nonradioactive 

liquid waste for processing or discharge to the cooling tower basin or the Delaware River. 

The purpose of the equipment and floor drainage system is to collect plant effluents and transfer 

them for appropriate processing or discharge to the cooling tower basin or the Delaware River. 

The equipment and floor drainage system accomplishes this purpose through the use of gravity 

drain lines, sumps, and pumps used to separate waste discharge based on the source point of 

discharge. The equipment and floor drainage system is designed to accommodate the volumes 

of fluids resulting from maintenance activities, system flushing, rinsing operations, and other 

plant work and is sized to minimize the potential for plant flooding. 

LRA Table 2.3.3-9 identifies the components subject to an AMR for the equipment and floor 

drainage system by component type and intended function. 

2.3.3.9.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the equipment and 

floor drainage system mechanical components within the scope of license renewal, as required 

by 10 CFR 54.4(a), and that the applicant has adequately identified the equipment and floor 

drains subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.10 Fire Protection System 

2.3.3.10.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.10 describes the fire protection system, which is a normally operating 

mechanical system designed to provide for the rapid detection and suppression of a fire at the 

plant. 

The purpose of the fire protection system is to prevent fires from starting, promptly detect and 

suppress fires to limit damage, and in the event of a fire allow for safe shutdown to occur. The 

fire protection system accomplishes this purpose by providing fire protection equipment in the 

form of detectors, alarms, fire barriers, and suppression for selected areas of the plant. 

The fire protection system consists of the fire protection water systems, carbon dioxide (CO2) 

systems, Halon system, foam system, portable fire extinguishers, and fire detection and 

signaling systems. These systems work in conjunction with the design of the physical plant 

design features to provide for overall protection for HCGS. The physical plant features consist 

of fire barriers, fire doors, and fire rated enclosures. LRA Table 2.3.3-10 identifies the 

components subject to an AMR for the fire protection system by component type and intended 

function. 
Structures and Components Subject to Aging Management Review 

 2-52 

2.3.3.10.2 Staff Evaluation 

The staff reviewed the license renewal drawings; Section 9.5.1, “Fire Protection Program,” of 

the UFSAR; and the fire protection CLB documents listed in NUREG-1048, “Safety Evaluation 

Report related to the operation of Hope Creek Generating Station,” dated October 1984, and 

NUREG-1048, Supplement Nos. 1 through 6. 

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 required by 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 had 

not omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1). 

The staff’s review of LRA Section 2.3.3.10 identified areas in which additional information was 

necessary to complete the review of the applicant’s scoping and screening results. 

In a letter dated March 22, 2010, the staff issued RAI 2.3.3.10-1 and stated that LRA drawing 

LR-M-22-0, sheet 1 showed the following fire protection system components as out of scope 

(i.e., not colored in green on the license renewal drawing): the deep well water pumps and 

associated components to fire water storage tanks OAT508 and OBT508. 

The staff requested that the applicant verify whether the deep well water pumps and associated 

components to fire water storage tanks OAT508 and OBT508 are within the scope of license 

renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). The staff further requested that, if these components are 

excluded from the scope of license renewal and are not subject to an AMR, the applicant 

provide justification for the exclusion. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-1 and stated that the fire 

water storage tanks (OAT508, OBT508) provide separate sources of water to the electric motor 

driven and diesel engine driven fire pumps. The fire water storage tanks and their associated 

components (colored green on license renewal boundary drawing LR-M-22-0, sheet 1) are 

within the scope of license renewal and subject to an AMR. The deep well water pumps and 

associated demineralized water system piping and components are not required to function in 

the event of a fire. These components do not provide structural support for safety-related 

components and do not have the potential for spatial interaction because they are not located in 

an area containing safety-related components. The deep well water pumps and associated 

demineralized water system piping and components (colored black on license renewal boundary 

drawing LR-M-22-0, sheet 1) are not within the scope of license renewal and are not subject to 

an AMR. 

The staff reviewed the applicant’s response to RAI 2.3.3.10-1. The staff verified that fire water 

storage tanks OAT508, OBT508, and associated components are colored in green on 

LR-M-22-0, sheet 1 and are, therefore, within the scope of license renewal and subject to an 

AMR. 

The staff also reviewed the applicant’s response to RAI 2.3.3.10-1 regarding the deep well 

water pumps. The staff found that, since the deep well water pumps are not required to function 

in the event of a fire, they are not within the scope of license renewal and are not subject to an 

AMR. Based on its review, the staff finds the applicant’s response to RAI 2.3.3.10-1 acceptable. 
Structures and Components Subject to Aging Management Review 

 2-53 

In a letter dated March 22, 2010, the staff issued RAI 2.3.3.10-2 and requested that the 

applicant determine whether LRA Tables 2.3.3-10 and 3.3.2-10 should include the following fire 

protection components: 

● hose racks 

● passive components in diesel engines for fire water pumps 

● fire retardant coating for structural steel 

● sight glasses (foam storage tank) 

● spray nozzles (iodine removal filter) 

If the applicant determined that LRA Tables 2.3.3-10 and 3.3.2-10 should not include these 

components, the staff requested that the applicant provide justification for the exclusion of these 

components from the scope of license renewal. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-2 in regards to the hose 

racks and stated: 

Hose rack assemblies consist of valves, piping and fittings. These components 

are included in the “Valve Body” and “Piping and Fittings” component type in LRA 

Tables 2.3.3-10 and 3.3.2-10. Fire hoses are evaluated as consumables, as 

described in LRA Section 2.1.6.4. Fire hoses are periodically inspected in 

accordance with NFPA standards and replaced as required, and are therefore 

not long-lived and not subject to an AMR. 

The staff verified that LRA Tables 2.3.3-10 and 3.3.2-10 list valve body and piping and fittings. 

Based on its review, the staff finds the applicant’s response to this portion of RAI 2.3.3.10-2 

acceptable. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-2 with regard to the 

passive components in diesel engines for fire water pumps and stated that the diesel driven fire 

water pump and diesel engine driver are mounted together on the vendor supplied equipment 

base plate, which is anchored and grouted to the fire water pump house foundation slab. These 

equipment supports and supporting structural components are subject to an AMR and are 

included in the applicable tables in the LRA Sections 2.4 and 3.5. The diesel engine and its 

components are part of the active engine and are not subject to an AMR. In its response, the 

applicant stated: 

The piping and components that provide the external cooling water to and from 

the diesel engine are included in LRA Tables 2.3.3-10 and 3.3.2-10. The 

component types are Piping and Fittings, Strainer Body and Valve Body. 

Fuel oil components that are not part of the active diesel engine assembly are 

included in LRA Tables 2.3.3-10 and 3.3.2-10. This includes the outdoor fuel oil 

storage tank, the fuel inlet and return piping and components from the tank up to 

and including the flexible metal hose connections to the diesel engine assembly. 

The fuel oil prefilter mounted on the engine assembly is also included in LRA 

Tables 2.3.3-10 and 3.3.2-10. The component types are Filter Housing, Hoses, 

Piping and Fittings and Valve Body. 

It was discovered that the flexible metal hose components were inadvertently 

identified with an Air – Outdoor environment. These hoses are located indoor. 
Structures and Components Subject to Aging Management Review 

 2-54 

Table 3.3.2-10 Component Type “Hoses” (LRA page 3.3-181) is revised as 

follows: 

 Table 3.3.2-10 Fire Protection System 

(Changes are highlighted with bold for inserted text and strikethroughs for deleted text.) 

Component 

Type

Intended 

Function

Material Environment Aging Effect 

Requiring 

Management

Aging 

Management 

Programs

NUREG1801 Vol. 

2 Item

Table 1 

Item

Notes

Hoses Pressure 

Boundary

Copper 

Alloy with 

less than 

15% Zinc

Air – Outdoor 

(External)

Air – Indoor 

(External)

Loss of 

Material/Pitting 

and Crevice 

Corrosion

None

Fire Protection

None

V.F-3 3.2.1-53 G, 11

A

In its April 6, 2010, response to RAI 2.3.3.10-2, the applicant stated that the passive 

components in diesel engines for fire water pumps are included in LRA Tables 2.3.3-10 and 

3.3.2-10 under the following passive component types as appropriate: Filter Housing, Hoses 

Piping and Fittings, Strainer Body and Valve Body. These passive components include: (1) the 

piping and components that provide the external cooling water to and from the diesel engine, 

(2) the outdoor fuel oil storage tank, (3) the fuel inlet and return piping and components from the 

tank up to and including the flexible metal hose connections to the diesel engine assembly, and 

(4) the fuel oil prefilter mounted on the engine assembly. 

The staff reviewed the applicant’s response and confirmed that the passive components in 

diesel engines for fire water pumps listed by the applicant are included in LRA Tables 2.3.3-10 

and 3.3.2-10. Active components that are part of the diesel engine assembly are in the scope of 

license renewal but are not subject to an AMR Based on its review, the staff found the 

applicant’s response to this portion of RAI 2.3.3.10-2 acceptable. 

The staff notes that the applicant, during its review of RAI 2.3.3.10-2, identified the following 

error in its LRA: Table 3.3.2-10 showed the environment for flexible metal hoses as “Air – 

Outdoor.” The applicant revised LRA Table 3.3.2-10 to show the environment for these hoses 

as “Air – Indoor.” The staff concurs with this correction. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-2 with regards to fire 

retardant coating for structural steel and stated: 

Fire retardant coatings are present on structural steel in various buildings at 

Hope Creek, including the reactor, auxiliary and turbine buildings. These 

coatings are in scope for license renewal and are subject to an AMR. Table 

2.3.3-10 (LRA page 2.3-141) is revised to add the component type Fire Barriers 

(Fire Retardant Coating for Structural Steel) as follows: 

Table 2.3.3-10 Fire Protection System 

Components Subject to Aging Management Review 

Component Type Intended Function 

Fire Barriers (Fire Retardant Coating for 

Structural Steel) 

Fire Barrier 
Structures and Components Subject to Aging Management Review 

 2-55 

Table 3.3.2-10 (LRA page 3.3-177) is revised to add the component type Fire 

Barriers (Fire Retardant Coating for Structural Steel) as follows: 

Table 3.3.2-10 Fire Protection System 

Component 

Type 

Intended 

Function 

Material Environment Aging Effect 

Requiring 

Management 

Aging Management 

Programs 

NUREG1801 Vol. 

2 Item 

Table 1 

Item 

Notes 

Fire Barrier (Fire 

Retardant 

Coating for 

Structural Steel) 

Fire Barrier Cementitious Fire 

Proofing 

Air – Indoor Loss of Material/ 

Cracking 

Fire Protection F, 19 

Table 3.3.2-10 Plant Specific Notes (LRA Page 3.3-196) is revised to add note 

19, as follows: 

19. Based on industry standards and guidelines, cementitious fireproofing is 

susceptible to loss of material/cracking in this environment. This aging effect will 

be monitored and managed with the fire protection program. 

In its April 6, 2010, response to RAI 2.3.3.10-2, the applicant stated that fire retardant coatings 

for structural steel are within the scope of license renewal and subject to an AMR. The 

applicant revised LRA Tables 2.3.3-10 and 3.3.2-10 to add fire retardant coatings for structural 

steel as a fire barrier that is within the scope of license renewal and subject to an AMR and 

added Note 19 to LRA Table 3.3.2-10. This note justifies the inclusion of fire retardant coating 

for structural steel in the Fire Protection Program. Therefore, the staff finds the applicant’s 

response to this portion of RAI 2.3.3.10-2 acceptable. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-2 with regards to sight 

glasses (foam storage tank) and stated: 

A foam fire suppression system is provided for the fuel oil storage tank, as shown 

on boundary drawing LR-M-22-0, Sheet 6. In the original design, foam was 

supplied from a foam storage tank and associated piping and components, 

including a tank site glass, located in the Fuel Oil Foam House. This foam 

supply system has been removed from service, disconnected and replaced by an 

onsite portable foam supply. The sight glass has also been removed from 

service, and is therefore not in the scope of license renewal and not subject to an 

AMR. 

In its April 6, 2010, response to RAI 2.3.3.10-2, the applicant stated that the foam storage tank 

is no longer in use and that, therefore, the sight glass located on the foam storage tank is not 

within the scope of license renewal and is not subject to an AMR. Therefore, the staff finds the 

applicant’s response to this portion of RAI 2.3.3.10-2 acceptable. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-2 with regards to the 

spray nozzles (iodine removal filter) and stated: 

Fire protection water spray systems are installed for ventilation systems that 

contain charcoal adsorber beds for iodine removal. These ventilation systems 

and associated charcoal filter units are identified below: 

● control room emergency filter units (AVH400, BVH400) 
Structures and Components Subject to Aging Management Review 

 2-56 

● technical support center (TSC) emergency filter unit (0VH313) 

● filtration, recirculation and ventilation system (FRVS) recirculation units 

(AVH213, BVH213, CVH213, DVH213, EVH213, FVH213) 

● FRVS ventilation filter units (AVH206, BVH206) 

● containment prepurge filter unit (0VH200) 

● radwaste tank filter units (AVH306, BVH306) 

The fire protection spray systems associated with these filter units are identified 

on Boundary Drawing LR-M-22-0, Sheet 3, as 1D1, 1D2, 1PD3, 1PD4, 1PD5, 

1PD6, 1PD7, 1PD8, 1PD9, 1PD10, 1PD11, 0D3, 0D4 and 0D5. 

The Control Room Emergency Filter Units (AVH400, BVH400) and TSC 

Emergency Filter Unit (0VH313) charcoal adsorber bed deluge is accomplished 

by flooding the associated charcoal bed through stainless steel distribution piping 

located within the filter unit housing. Fire suppression water is discharged to the 

charcoal bed through holes drilled in the distribution piping at appropriate 

locations to flood the bed. Spray nozzles are not used in these units. The 

distribution piping located inside the HVAC filter unit is evaluated with Piping and 

Fittings for an AMR in the Fire Protection System, shown on LRA Tables 2.3.3-10 

and 3.3.2-10. 

It was discovered that the Control Room and Control Area HVAC System 

incorrectly identified spray nozzles associated with the charcoal bed fire 

suppression system Tables 2.3.3-7 and 3.3.2-7. Table 2.3.3-7 (LRA page 2.3-

125) is revised to delete the component type Nozzle as follows: 

 Table 2.3.3-7 Control Room and Control Area HVAC Systems 

Components Subject to Aging Management Review 

(Changes are highlighted with strikethroughs for deleted text.) 

Component Type Intended Function 

Nozzle Spray
Structures and Components Subject to Aging Management Review 

 2-57 

Table 3.3.2-7 (LRA page 3.3-162) is revised to delete the component type Nozzle 

as follows: 

 Table 3.3.2-7 Control Room and Control Area HVAC Systems 

(Changes are highlighted with strikethroughs for deleted text.) 

Boundary Drawing LR-M-89-1, Sheet 1, Note 5, is replaced with the following: 

5. Charcoal deluge spray piping consists of water distribution piping with 

drilled holes to flood the carbon beds, and is evaluated as Piping and 

Fittings with the Fire Protection System for an AMR. 

The Filtration, Recirculation and Ventilation System (FRVS) Recirculation Units 

(AVH213, BVH213, CVH213, DVH213, EVH213, FVH213) charcoal adsorber 

bed deluge arrangement is the same as the Control Room and Control Area 

HVAC System described above. Charcoal adsorber bed fire suppression is 

accomplished by flooding the associated charcoal bed through stainless steel 

distribution piping located within the filter unit housing. Fire suppression water is 

discharged to the charcoal bed through holes drilled in the distribution piping at 

appropriate locations to flood the bed. Spray nozzles are not used in these units. 

The distribution piping located inside the HVAC filter unit is evaluated with Piping 

and Fittings for an AMR in the Fire Protection System, shown on LRA Tables 

2.3.3-10 and 3.3.2-10. 

It was discovered that Boundary Drawing LR-M-83-1, Sheet 1, Note 8, incorrectly 

describes the charcoal bed deluge as having spray nozzles. This note is 

replaced with the following: 

8. Charcoal deluge spray piping consists of water distribution piping with 

drilled holes to flood the carbon beds, and is evaluated as Piping and 

Fittings with the Fire Protection System for an AMR. 

The FRVS Ventilation Filter Units (AVH206, BVH206), Containment Prepurge 

Filter Unit (0VH200) and Radwaste Tank Filter Units (AVH306, BVH306) 

charcoal adsorber bed deluge is accomplished by spraying the associated 

charcoal bed through galvanized steel distribution piping and brass spray nozzles 

Component 

Type 

Intended 

Function 

Material Environment Aging Effect 

Requiring 

Management 

Aging 

Management 

Program 

NUREG1801 Vol. 2 

Item 

Table 1 

Item 

Notes 

Nozzle Spray Copper 

Alloy with 

15% Zinc 

or More

Air/Gas –

Wetted 

(External)

Loss of 

Material/Pitting 

and Crevice 

Corrosion

Periodic 

Inspection

VII.F1-16 3.3.1-25 E, 2, 5

Nozzle Spray Copper 

Alloy with 

15% Zinc 

or More

Air/Gas –

Wetted 

(Internal)

Loss of 

Material/Pitting 

and Crevice 

Corrosion

Periodic 

Inspection

VII.F1-16 3.3.1-25 E, 2
Structures and Components Subject to Aging Management Review 

 2-58 

located within the filter unit housing. Fire suppression water is discharged to the 

charcoal bed through the spray nozzles at appropriate locations to cool the bed. 

The distribution piping and spray nozzles are evaluated for an AMR in the Fire 

Protection System. These charcoal bed spray nozzles were inadvertently 

omitted from LRA Tables 2.3.3-10 and 3.3.2-10. Table 2.3.3-10 (LRA page 2.3-

141) is revised to include component type Spray Nozzles (Charcoal Filter) as 

follows: 

Table 2.3.3-10 Fire Protection System 

Components Subject to Aging Management Review 

Component Type Intended Function 

Spray Nozzles (Charcoal Filter) Spray 

Table 3.3.2-10 (LRA page 3.3-187) is revised to include component type Spray 

Nozzles (Charcoal Filter) as follows: 

Table 3.3.2-10 Fire Protection System 

Component Type Intended 

Function 

Material Environment Aging Effect 

Requiring 

Management 

Aging 

Management 

Programs 

NUREG1801 Vol. 

2 Item 

Table 1 

Item 

Notes 

Spray Nozzles 

(Charcoal Filter)

Spray Copper Alloy 

with 15% 

Zinc or More

Air - Indoor 

(External)

None None V.F-3 3.2.1-53 A

Spray Nozzles 

(Charcoal Filter)

Spray Copper Alloy 

with 15% 

Zinc or More

Air - Indoor 

(Internal)

None None V.F-3 3.2.1-53 A

Based on its review and the addition of spray nozzles to LRA Tables 2.3.3-10 and 3.3.2-10, the 

staff finds the applicant’s response to this portion of RAI 2.3.3.10-2 acceptable. 

The staff notes that the applicant, during its review of RAI 2.3.3.10-2, identified and corrected 

some errors in its LRA as follows: spray nozzles are not used in the fire protection spray 

systems associated with iodine removal filter units in the control room and control area HVAC 

systems. The applicant deleted “Nozzle” from the column “Component Type” under “Control 

Room and Control Area HVAC Systems” in LRA Tables 2.3.3-7 and 3.3.2-7. The applicant also 

replaced drawing notes that incorrectly described the charcoal bed deluge systems as having 

spray nozzles. 

In a letter dated March 22, 2010, the staff issued RAI 2.3.3.10-3 and requested that the 

applicant verify whether the Halon 1301 total flooding fire suppression systems located in the 

quality assurance vault in the administration building and underneath the raised floor of room 1 

in the guardhouse are within the scope of license renewal in accordance with 10 CFR 54.4(a) 

and whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The staff 

further requested that, if they are excluded from the scope of license renewal and not subject to 

an AMR, the applicant provide justification for the exclusion. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-3 and stated that the 

Halon total flooding fire suppression system in the quality assurance vault in the administrative 

building and the Halon total flooding fire suppression system underneath the raised floor of 
Structures and Components Subject to Aging Management Review 

 2-59 

room 1 in the guardhouse are not within the scope of license renewal in accordance with 

10 CFR 54.4(a) and are not subject to an AMR in accordance with 10 CFR 54.21(a)(1). These 

systems are not safety-related, and failure of these systems cannot prevent accomplishment of 

safety-related functions. These systems are not credited to demonstrate compliance with any of 

the regulated events in accordance with 10 CFR 54.4(a)(3). Therefore, these systems do not 

have any intended functions for license renewal and are not within scope. 

The staff reviewed the applicant’s response to RAI 2.3.3.10-3. Since the room in the 

administration building called the quality assurance vault is no longer used as a quality 

assurance vault, the Halon total flooding fire suppression system in that room is not required to 

protect safety-related SSCs and is, therefore, not within the scope of license renewal and not 

subject to an AMR. Since the Halon total flooding fire suppression system in the guardhouse is 

not required to protect safety-related SSCs, it is not within the scope of license renewal and not 

subject to an AMR. Based on its review, the staff finds the applicant’s response to 

RAI 2.3.3.10-3 acceptable. 

In a letter dated March 22, 2010, the staff issued RAI 2.3.3.10-4 and quoted the following 

excerpts from Section 9.5.1.4 of NUREG-1048, Supplement No. 5, “...the staff also questioned 

the fire rating of certain panels used in the control rooms. The applicant provided the staff with 

a letter from the manufacturer certifying that these panels were fabricated from the same type of 

materials and in a configuration used in 3-hour-rated fire doors...” 

The staff requested that the applicant verify whether the panels are within the scope of license 

renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). The staff further requested that, if they are excluded from 

the scope of license renewal and not subject to an AMR, the applicant provide justification for 

the exclusion. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-4 and stated: 

Panels are installed in control room walls. Additionally, the wall in the control 

room viewing area has a ... glass window. 

Steel wall panels and [the glass] window are in the scope of License Renewal 

and are subject to AMR. Review of Table 3.3.2-10 of the Hope Creek LRA 

determined that the steel and glass fire barrier materials were inadvertently 

omitted from this table. Table 3.3.2-10 is revised to add these materials to the 

existing component type Fire Barrier (Walls, Ceilings, and Floors) as shown 

below: 

Table 3.3.2-10 Fire Protection System 

Component 

Type

Intended 

Function

Material Environment Aging Effect 

Requiring 

Management

Aging 

Management 

Programs

NUREG1801 

Vol.2 

Item

Table 1 

Item

Notes

Fire Barrier 

(Walls, Ceilings 

and Floors)

Fire Barrier Carbon 

Steel

Air – Indoor Loss of Material/ 

corrosion

Fire Protection F.11

Fire Barrier 

(Walls, Ceilings 

and Floors)

Fire Barrier Glass Air – Indoor None None VII.J-8 3.3.1-93 C
Structures and Components Subject to Aging Management Review 

 2-60 

Additionally, LRA Section 3.3.2.1.10, Fire Protection System, is revised to include 

glass material. 

The staff reviewed the applicant’s response to RAI 2.3.3.10-4. The addition of steel and glass 

fire barrier materials to LRA Table 3.3.2-10 confirms that the steel wall panels and glass window 

located in the control room are within the scope of license renewal and are subject to an AMR. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.10-4 acceptable. 

In its letter dated March 22, 2010, the staff issued RAI 2.3.3.10-5 and quoted the following 

excerpt from Section 9.5.1.4 of NUREG-1048, Supplement No. 5, “In the SER the staff identified 

12 locations were the applicant committed to install automatic sprinkler systems to protect areas 

containing high concentrations of cables and cable trays...” 

The staff requested that the applicant verify whether these automatic sprinkler systems are 

within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are 

subject to an AMR in accordance with 10 CFR 54.21(a)(1). The staff further requested that, if 

they are excluded from the scope of license renewal and not subject to an AMR, the applicant 

provide justification for the exclusion. 

In a letter dated April 6, 2010, the applicant responded to RAI 2.3.3.10-5 and stated: 

The automatic preaction sprinkler systems described in NUREG-1048, 

Supplement No. 5, Section 9.5.1.4, “General Plant Guidelines,” have been 

installed and are described in the Hope Creek UFSAR Section 9.5.1.1.14. These 

automatic sprinkler systems are included 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). These preaction sprinkler systems are designated as 1PS6, 

1PS7, 1PS8, 1PS9, 1PS10, 1PS11, 1PS12, 1PS13, 1PS14, 1PS15 and 1PS16, 

and are shown as in scope on license renewal boundary drawing LR-M-22-0, 

sheet 3. The typical detail for these systems is Detail V, shown on license 

renewal boundary drawing LR-M-22-0, sheet 6. 

The staff reviewed the applicant’s response to RAI 2.3.3.10-5 which confirmed that the 

automatic sprinklers had been installed and that they were included within the scope of license 

renewal and subject to an AMR. However, the staff noticed that the applicant, in its response to 

RAI 2.3.3.10-5, had listed only 11 preaction sprinkler systems while Section 9.5.1.4 of 

NUREG-1048, Supplement No. 5 stated that the applicant committed to install automatic 

sprinkler systems in 12 locations. The staff requested a clarification for the discrepancy with the 

number of sprinkler systems. In a telephone conference call held on April 14, 2010, the 

applicant clarified the discrepancy as follows: the number of automatic sprinkler systems in the 

UFSAR (10 sprinklers systems); in NUREG-1048, Supplement No. 5 (12 sprinklers); and in the 

applicant’s response to RAI 2.3.3.10-5 (11 sprinklers systems) are different because of the 

difference in grouping these automatic sprinkler systems by fire area or by room. Based on its 

review and on the clarification received during the April 4, 2010, conference call that there are 

actually 11 sprinkler systems that are located so as to cover 14 areas (3 grouped pairs), the 

staff finds the applicant’s response to RAI 2.3.3.10-5 acceptable. 

2.3.3.10.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the fire protection system mechanical components within the scope of license renewal, 
Structures and Components Subject to Aging Management Review 

 2-61 

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.11 Fire Pump House Ventilation System

2.3.3.11.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.11 describes the fire pump house ventilation system, which is an automatic 

air ventilation system designed to supply sufficient combustion air for the diesel driven fire pump 

engine. It is also designed to maintain the fire water pump house room air flow and temperature 

in the building compartments within an acceptable range by the use of louvers, heaters, and 

roof exhaust fans. 

The purpose of the fire pump house ventilation system is to supply sufficient combustion air for 

the diesel fire pump. In addition, it maintains building room air temperature above freezing and 

will limit the rise of room temperature during the summer and maintain the equipment 

environment within the design temperature limits. The fire pump house ventilation system 

accomplishes this by using ventilation louvers, electric unit heaters, exhaust fans, and 

associated controls. 

2.3.3.11.2 LRA Table 2.3.3-11 identifies the components subject to an AMR for the fire pump 

house ventilation system by component type and intended function.Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the fire pump house 

ventilation system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.12 Fresh Water Supply System 

2.3.3.12.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.12 describes the fresh water supply system, which is a normally operating 

mechanical system designed to send fresh water and domestic water to plumbing fixtures, 

laundry rooms, safety showers, eye washes, and washing stations. 

The purpose of the fresh water supply system is to supply water in sufficient quantities to satisfy 

the demand for station potable and makeup water, safety showers, eye washes, and sanitary 

water. The fresh water supply system accomplishes this by using wells, pumps, piping, piping 

components, plumbing fixtures, tanks, and valves. 

LRA Table 2.3.3-12 identifies the components subject to an AMR for the fresh water supply 

system by component type and intended function. 

2.3.3.12.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings as described in Section 2.3, the staff concludes that the applicant has appropriately 

identified the fresh water supply system mechanical components within the scope of license 
Structures and Components Subject to Aging Management Review 

 2-62 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.13 Fuel Handling and Storage System 

2.3.3.13.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.13 describes the fuel handling and storage system, which consists of the 

spent fuel storage pool and racks, new fuel storage vault and racks, cask loading pit and spent 

fuel cask, and fuel handling equipment. 

The purpose of the fuel handling and storage system is to support, transfer, and provide for 

storage of nuclear fuel in a manner that precludes inadvertent criticality and maintains shielding 

and cooling of spent fuel. The fuel handling and storage system accomplishes this through the 

spent fuel storage rack design. The spent fuel storage racks are designed to maintain fuel in a 

subcritical configuration having a keff less than or equal to 0.95. To preclude the possibility of 

raising spent fuel assemblies out of the water, the hoist incorporates redundant electrical limit 

switches and interlocks that prevent hoisting above the preset limit. In addition, the cables on 

the auxiliary hoist incorporate adjustable mechanical stops that jam the hoist cable against the 

hoist structure, which prevents further hoisting, if the limit switch interlock system fails. 

LRA Table 2.3.3-13 identifies the components subject to an AMR for the fuel handling and 

storage system by component type and intended function. 

2.3.3.13.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the fuel handling 

and storage system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.14 Fuel Pool Cooling and Cleanup System 

2.3.3.14.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.14 describes the fuel pool cooling and cleanup system, which is a normally 

operating closed-loop system designed to remove heat from the fuel storage pool and maintain 

fuel storage pool water clarity. 

The purpose of the fuel pool cooling and cleanup system is to remove decay heat from the 

spent fuel assemblies that are stored within the fuel storage pool during all modes of operation, 

to remove decay heat from the water inventory contained within the reactor well and 

dryer-separator storage pool during refueling outages, to minimize thermal stresses within the 

floor and walls of the fuel storage pool, and maintain the chemistry of the fuel storage pool water 

inventory within acceptable EPRI guidelines. 

The fuel pool cooling and cleanup system accomplishes this by delivering recirculating water 

from the fuel pool during normal operation as well as from the reactor well, fuel cask storage pit, 

and dryer-separator storage pool during refueling outages, which is pumped through the fuel 
Structures and Components Subject to Aging Management Review 

 2-63 

pool cooling and cleanup system heat exchangers and filter-demineralizer system. The fuel 

pool cooling and cleanup system heat exchangers then remove heat from the pools and transfer 

it to the closed-cycle cooling water system. The filter-demineralizer system maintains pool 

water purity and clarity by a combination of filtration and ion exchange. 

The fuel pool cooling and cleanup system operation is a manually initiated system for spent fuel 

and cooling and cleanup functions. 

LRA Table 2.3.3-14 identifies the components subject to an AMR for the fuel pool cooling and 

cleanup system by component type and intended function. 

2.3.3.14.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.14, UFSAR Section 9.1.3, 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 necessary to complete the review of the applicant’s scoping and screening 

results. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.14-01 and noted that license renewal 

drawing LR-M-53-1, sheet 1, locations B-7 and B-8, shows starter strainers (TS 182 and TS 

181) in 10 CFR 54.4(a)(1) lines 8”-HBC-042 and 8”-HBC-047, respectively, that are not included 

as a component type in LRA Table 2.3.3-14. The applicant was requested to provide additional 

information to explain why these in-scope strainers are not included as a component type with 

their intended function in LRA Table 2.3.3-14. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.14-02 and noted that license renewal 

drawing LR-M-53-1, sheet 1 shows 13 locations of 10 CFR 54.4(a)(2) pipelines connected to 

10 CFR 54.4(a)(1) pipelines. The applicant was requested to provide additional information to 

locate the anchors for the pipelines between the end of the (a)(2) scoping boundary and the 

safety-nonsafety interfaces. 

The applicant’s response, dated May 11, 2010, described the location of the anchors, which are 

within the existing (a)(2) scoping boundary. This conforms to the applicant’s methodology and 

did not result in the inclusion of any additional components within the scope of license renewal. 

Therefore, the staff’s concerns described in RAI 2.2.3.14-01 and RAI 2.3.3.14-02 are resolved. 

2.3.3.14.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the fuel pool cooling and cleanup system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-64 

2.3.3.15 Hardened Torus and Vent System

2.3.3.15.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.15 describes the hardened torus and vent system, which is a hard-piped vent 

system designed for the mitigation of severe accident sequences that are beyond the DBAs in 

which decay heat removal capability is unavailable. 

The purpose of the hardened torus and vent system is to vent the primary containment from the 

torus during severe accident sequences that involve loss of normal decay heat removal 

capability. The hardened torus and vent system accomplishes this by providing a vent path 

from the torus to the environment through the containment prepurge cleanup system return 

header from the torus. The hardened torus vent system is only used for conditions beyond the 

DBEs. LRA Table 2.3.3-15 identifies the components subject to an AMR for the hardened torus 

and vent system by component type and intended function. 

2.3.3.15.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the hardened torus 

vent system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.16 Hydrogen Water Chemistry System 

2.3.3.16.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.16 describes the hydrogen water chemistry system, which is designed to 

inject hydrogen at the suction of the secondary condensate pumps to lower recirculation and 

reactor water oxygen concentration, and inject oxygen at the suction of the primary condensate 

pumps to increase oxygen concentration in the condensate and feedwater to reduce 

flow-assisted corrosion. 

The purpose of the hydrogen water chemistry system is to reduce the potential for intergranular 

stress-corrosion cracking (IGSCC) and flow-assisted corrosion. It accomplishes this by injecting 

hydrogen to reduce the potential for IGSCC, injecting oxygen to reduce flow-assisted corrosion, 

and monitoring for the concentration of dissolved hydrogen and oxygen in the reactor 

recirculation system. 

The addition of hydrogen reduces the oxygen content in the reactor water and reduces the 

corrosion potential of the water. Although the hydrogen concentration is reduced in the steam, 

the hydrogen/oxygen ratio increases. To ensure that sufficient oxygen is present in the gaseous 

radwaste system to combine with the excess hydrogen, air is injected upstream of the off-gas 

recombiners to maintain the stoichiometric balance of oxygen and hydrogen. In order to 

maintain the desired dissolved oxygen level in the feedwater, a supplemental oxygen injection 

system (oxygen gas bottles) is also installed to inject oxygen, on an as needed basis, upstream 

of the primary condensate pumps. 

LRA Table 2.3.3-16 identifies the components subject to an AMR for the hydrogen water 

chemistry system by component type and intended function. 
Structures and Components Subject to Aging Management Review 

 2-65 

2.3.3.16.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the hydrogen water 

chemistry system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.17 Leak Detection and Radiation Monitoring System 

2.3.3.17.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.17 describes the leak detection and radiation monitoring system, which is a 

normally operating instrumentation system that detects leaks from the reactor coolant pressure 

boundary and other plant systems, and assesses overall plant radiological conditions at the 

facility. In addition, this system also detects the radiation level and the release of radioactivity in 

key locations throughout the plant. The leak detection and radiation monitoring system consists 

of the following two plant systems: leak detection plant system and radiation monitoring plant 

system. 

The purpose of the leak detection plant system is to detect leaks and provide alarms at 

established leakage rate limits so that the affected system can be isolated if necessary. To 

accomplish this, the system directly monitors the drywell for reactor coolant pressure boundary 

leakage as required by RG 1.45, and indirectly detects leakage from the reactor coolant 

pressure boundary and from other systems by monitoring the process variables. 

The purpose of the radiation monitoring plant system is to detect the release of radioactivity, 

monitor radiation levels, and provide alarms so that the general public and plant personnel can 

be protected from exposure in excess of those allowed by the applicable regulations. The 

system accomplishes this by using radiation detector and associated instrumentation to monitor 

and indicate the radiation levels. 

LRA Table 2.3.3-17 identifies the components subject to an AMR for the leak detection and 

radiation monitoring system by component type and intended function. 

2.3.3.17.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the leak detection 

and radiation monitoring system mechanical components within the scope of license renewal, 

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-66 

2.3.3.18 Makeup Demineralizer System 

2.3.3.18.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.18 describes the makeup demineralizer system, which is a normally 

operating mechanical system. 

The purpose of the makeup demineralizer is to demineralize fresh water from the station wells, 

store the demineralized water, and deliver it to plant services, as required. The makeup 

demineralizer accomplishes this purpose by pumping fresh water through trains, consisting of a 

cation exchanger, an anion exchanger, and a mixed bed exchanger. The resulting effluent 

through the trains is demineralized water. 

LRA Table 2.3.3-18 identifies the components subject to an AMR for the makeup demineralizer 

system by component type and intended function. 

2.3.3.18.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.18, UFSAR Section 9.2.3, 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 necessary to complete the review of the applicant’s scoping and screening 

results. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.18-01 and noted that license renewal 

drawing LR-M-11-1, sheet 1 shows two 10 CFR 54.4(a)(1) lines (2”-HCC-111 and 2”-HCC-112) 

continue to 10 CFR 54(a)(2) lines AN-2”-HCD-001. The applicant was requested to provide 

additional information to locate the anchor for the two AN-2”-HCD-001 lines between the end of 

the (a)(2) scoping boundary and the safety-nonsafety interface. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.18-02 and noted that license renewal 

drawing LR-M-90-1, sheet 3, locations D-6 and E-6, shows 10 CFR 54.4(a)(1) lines 

18”-HCC-187, 18”-HCC-188, and 18”-HCC-189 continue to 10 CFR 54.4(a)(2) lines 

2”-HCD-022, 2”-HBD-133, and 2”-HBD-132. License renewal drawing LR-M-90-1, sheet 2, 

location D-6, shows 10 CFR 54.4(a)(1) head tank BT 410 connected to 10 CFR 54(a)(2) line 

2”-HCD-024. The applicant was requested to provide additional information to locate the 

anchors for these lines. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.18-03 and noted that license renewal 

drawing LR-30-1, sheet 2, locations G-2, G-3, G-5, and G-7, shows 10 CFR 54.4(a)(1) lines 

1”-HBC-098, 1”-HBC-096, 1”-HBC-097, and 1”-HBC-095 continue to 10 CFR 54.4(a)(2) lines 

1”-HCD-232, 1”-HCD-230, 1”-HCD-231, and 1”-HCD-229. The applicant was requested to 

provide additional information to locate the anchors for these lines. 

The applicant’s response, dated May 11, 2010, described the location of the anchors, which are 

within the existing (a)(2) scoping boundary. This conforms to the applicant’s methodology and 

did not result in the inclusion of any additional components within the scope of license renewal. 

Based on its review, the staff finds the applicant’s responses to RAI 2.3.3.18-01, 

RAI 2.3.3.18-02, and RAI 2.3.3.18-03 acceptable because the applicant provided the location of 
Structures and Components Subject to Aging Management Review 

 2-67 

the seismic anchors for the lines in question. Therefore, the staff’s concerns described in 

RAI 2.3.3.18-01, RAI 2.3.3.18-02, and RAI 2.3.3.18-03 are resolved. 

2.3.3.18.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, The applicant’s RAI responses, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the makeup demineralizer system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.19 Primary Containment Instrument Gas System 

2.3.3.19.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.19 describes the primary containment instrument gas system, which is a 

safety-related system designed to provide a continuous supply of dried, oil-free, filtered 

compressed gas to pneumatic components inside the primary containment during normal 

operations. 

The purpose of the primary containment instrument gas system is to provide clean and dried 

compressed gas to pneumatically-operated instruments and valves. To accomplish this, the 

system takes gas from inside the primary containment or reactor building, and processes the 

gas through intake screen, filters, gas compressors, intercoolers, aftercoolers, moisture 

separators, thermo-siphons, gas dryers, gas receivers, and gas headers for distribution to 

components in support of plant operations. 

LRA Table 2.3.3-19 identifies the components subject to an AMR for the primary containment 

instrument gas system by component type and intended function. 

2.3.3.19.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the primary 

containment instrument gas system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.20 Primary Containment Leakage Rate Testing System 

2.3.3.20.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.20 describes the primary containment leakage rate testing system, which is 

designed to provide a means to measure the leakage from the primary containment. 

The primary containment leakage rate testing system consists of the following subsystems: 

Type A testing subsystem, Type B testing subsystem, and Type C testing subsystem. The 

Type A testing subsystem is used to pressurize the primary containment to a test pressure so 

that the integrated leakage rate of the containment can be determined and compared with the 
Structures and Components Subject to Aging Management Review 

 2-68 

appropriate acceptance criteria. The determination of primary containment leakage is 

accomplished with a data acquisition center. The Type B testing subsystem is used to 

pressurize and measure local leakage across pressure or leakage limiting boundaries other 

than valves. Similarly, the Type C testing subsystem is used to pressurize and measure local 

leakage rates across containment isolation valves. 

LRA Table 2.3.3-20 identifies the components subject to an AMR for the primary containment 

leakage rate testing system by component type and intended function. 

2.3.3.20.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the primary 

containment leakage rate testing system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.21 Process and Post-Accident Sampling Systems

2.3.3.21.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.21 describes the process and post-accident sampling system, which is a 

normally operating system that consists of the process sampling plant system and the 

post-accident plant sampling system. 

The process sampling plant system is designed to permit a representative sample to be taken 

from all process streams related to plant power operation and liquid radwaste processing. The 

sample is in a form which can be used in the laboratory and which safeguards against change in 

the constituents to be examined, minimizes the contamination and radiation at the sample point, 

and reduces decay and sample line plateout as much as possible. 

The purpose of the process sampling plant system is to monitor the operation of equipment and 

supply information for making operating decisions where these are influenced by water 

chemistry. It accomplishes this by collecting steam, gaseous, and liquid samples throughout the 

facility. 

The post-accident plant sampling system is designed to obtain representative liquid and gas 

grab samples from the reactor coolant system and from the primary containment and reactor 

building atmospheres for radiological and chemical analysis under accident conditions. 

The purpose of the post-accident plant sampling system is to permit collection and processing 

of liquid and gaseous samples. The post-accident plant sampling system accomplishes this by 

providing piping to collect these samples during normal and post-accident conditions, and a 

system to analyze the samples during post-accident conditions. 

LRA Table 2.3.3-21 identifies the components subject to an AMR for the process and 

post-accident sampling system by component type and intended function. 
Structures and Components Subject to Aging Management Review 

 2-69 

2.3.3.21.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.21, UFSAR Section 9.3.2, 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 necessary to complete the review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAI as discussed below. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.21-01 and noted that license renewal 

drawing LR-M-38-0, sheet 1, location B-7, shows line 1”-DBB-006 within the scope of license 

renewal for 10 CFR 54.4(a)(1) attached to tubing that is not within scope. The applicant was 

requested to provide additional information to locate the anchor after the safety-nonsafety 

interface. 

The applicant’s response, dated May 11, 2010, described the location of the anchors, which are 

within the existing (a)(2) scoping boundary. This conforms to the applicant’s methodology and 

did not result in the inclusion of any additional components within the scope of license renewal. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.21-01 acceptable 

2.3.3.21.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the process and post-accident sampling system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1). 

2.3.3.22 Radwaste System 

2.3.3.22.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.22 describes the radwaste system, which is a normally operating mechanical 

system designed to process liquid radioactive waste for reuse by the plant or for discharge to 

the Delaware River. The radwaste system also processes and packages solid radioactive 

waste for shipment to an offisite repository. 

The purpose of the radwaste system is to provide for the collection and processing of potentially 

radioactive liquid and solid waste generated by the plant. The radwaste system accomplishes 

this through the use of tanks, demineralizers, filters, coolers, piping, valves, and pumps required 

to process the liquid radwaste, and waste containers and drums to process solid radwaste. 

LRA Table 2.3.3-22 identifies the components subject to an AMR for the radwaste system by 

component type and intended function. 

2.3.3.22.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.22, UFSAR Sections 11.2 and 11.4, 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 
Structures and Components Subject to Aging Management Review 

 2-70 

information was necessary to complete the review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAIs as discussed below. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.22-01 and noted that license renewal 

drawing LR-M-61-1, sheet 1, locations G-6 and G-7, shows a 3 inch 10 CFR 54.4(a)(1) line 

(3”-HBB-014) connected to 10 CFR 54.4(a)(2) lines (3”-HBD+-013 and 3”-HBD+-017). The 

applicant was requested to provide additional information to locate the seismic anchors or 

anchored components for the 3”-HBD+-013 and 3”-HBD+-017 lines between the end of the 

(a)(2) scoping boundary and the safety-nonsafety interface. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.22-02 and noted that license renewal 

drawing LR-M-61-1, sheet 2, locations G-6 and G-7, shows a 3 inch 10 CFR 54.4(a)(1) line 

(3”-HBB-023) connected to 10 CFR 54.4(a)(2) lines (3”-HBD+-022 and 3”-HBD+-019). The 

applicant was requested to provide additional information to locate the seismic anchors or 

anchored components for the 3”-HBD+-022 and 3”-HBD+-019 lines between the end of the 

(a)(2) scoping boundary and the safety-nonsafety interface. 

The applicant’s response, dated May 11, 2010, described the location of the anchors, which are 

within the existing (a)(2) scoping boundary. This conforms to the applicant’s methodology and 

did not result in the inclusion of any additional components within the scope of license renewal. 

Based upon its review, the staff finds the applicant’s responses to RAI 2.3.22-01 and 

RAI 2.3.22-02 acceptable. Therefore, the staff’s concerns described in RAI 2.3.22-01 and 

RAI 2.3.22-02 are resolved. 

2.3.3.22.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, The applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the radwaste system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.23 Reactor Building Ventilation System

2.3.3.23.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.23 describes the reactor building ventilation system, which is a continuously 

operating mechanical system with containment prepurge capability, heating and cooling 

capability, and an isolation mode. The system is designed to provide filtering, cooling, and 

heating to the reactor building compartments during startup, full power, shutdown, and for some 

portions during DBAs. 

The purpose of the reactor building ventilation system is to maintain compartment temperatures 

at acceptable limits; it regulates the static pressure within the reactor building to maintain air 

flow from areas of lesser contamination to areas of greater contamination, and provides for safe 

disposal of airborne contaminants. The reactor building ventilation system accomplishes this by 

maintaining the reactor building pressure at a slightly negative pressure with respect to outdoor 

pressure while ventilating the reactor building with filtered air and exhausting outdoors through a 

high-efficiency particulate air (HEPA) filter. 
Structures and Components Subject to Aging Management Review 

 2-71 

LRA Table 2.3.3-23 identifies the components subject to an AMR for the reactor building 

ventilation system by component type and intended function. 

2.3.3.23.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the reactor building 

ventilation system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.24 Reactor Water Cleanup System

2.3.3.24.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.24 describes the reactor water cleanup system, which is a filtration and 

demineralization system that maintains the purity of the water in the reactor coolant system. 

The system can be operated during startup, shutdown, and refueling modes, as well as during 

power operation. 

The primary purpose of the reactor water cleanup system is to: (1) reduce the deposition of 

water impurities on fuel surfaces, thus minimizing heat transfer surface fouling; (2) reduce 

secondary sources of beta and gamma radiation by removing corrosion products, impurities, 

and fission products from the reactor coolant; (3) reduce the concentration of chloride ions to 

protect steel components from chloride stress corrosion; and (4) maintain or lower water level in 

the reactor vessel during startup, shutdown, and refueling operations, in order to accommodate 

reactor coolant swell during heatup and to accommodate water inputs from the control rod drive 

system. 

The secondary purpose of the reactor water cleanup system is to minimize thermal stratification 

of the reactor vessel during periods of no recirculation flow; to provide an alternate means of 

vessel cooldown; and to provide continuous water quality monitoring for conductivity, pH, 

oxygen, and silica. The reactor water cleanup system accomplishes these purposes by forced 

circulation of reactor coolant through heat exchangers and filter-demineralizers. 

LRA Table 2.3.3-24 identifies the components subject to an AMR for the reactor water cleanup 

system by component type and intended function. 

2.3.3.24.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the reactor water 

cleanup system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-72 

2.3.3.25 Remote Shutdown Panel Room HVAC System 

2.3.3.25.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.25 describes the remote shutdown panel room HVAC system, which is a 

mechanical system designed to maintain air temperature, quality, and humidity and maintain the 

remote shutdown panel compartment at a slight positive pressure ensuring the proper operation 

of controls and equipment that can be used to safely shut down the plant if the main control 

room is unusable. 

The purpose of the remote shutdown panel room HVAC system is to provide a continuous 

supply of filtered and conditioned air and maintain the remote shutdown panel room 

compartment at a slightly positive pressure to prevent infiltration of fire, smoke, fumes, and 

airborne radioactivity from surrounding areas into the remote shutdown panel room 

compartment. The system accomplishes this by providing adequate ventilation flow capacity 

into the remote shutdown panel room compartment to prevent infiltration when the ventilation 

system is manually placed in service. 

LRA Table 2.3.3-25 identifies the components subject to an AMR for the remote shutdown panel 

room HVAC system by component type and intended function. 

2.3.3.25.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the remote 

shutdown panel room HVAC system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.26 Service Water Intake Ventilation System 

2.3.3.26.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.26 describes the service water intake ventilation system, which is a normally 

operating forced air ventilation system designed to remove waste heat produced from the 

components located in the service water intake structure. 

The purpose of the service water intake ventilation system is to maintain the temperatures in the 

two service water pump areas and traveling screen motor room within design conditions. The 

system accomplishes this by supplying fresh air and re-circulating air throughout the service 

water intake structure. This ventilation system is designed as a safety-related system and will 

remain operational during accident conditions. 

LRA Table 2.3.3-26 identifies the components subject to an AMR for the service water intake 

ventilation system by component type and intended function. 
Structures and Components Subject to Aging Management Review 

 2-73 

2.3.3.26.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the service water 

intake ventilation system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.27 Service Water System 

2.3.3.27.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.27 describes the service water system, which is a normally operating 

open-loop cooling system designed to provide cooling water from the Delaware River (the 

ultimate heat sink) to perform both safety-related and nonsafety-related functions. 

The purpose of the service water system is to provide river water cooling for the closed-loop 

cooling water systems, safety and turbine auxiliary cooling system (SACS), and the reactor 

auxiliary cooling system (RACS). The system accomplishes this by supplying strained river 

water from the ultimate heat sink to the tube side of the SACS and RACS heat exchanger and 

discharging the heated water to the cooling tower basin or overboard discharges. 

During normal operating conditions and loss of offsite power conditions, the service water 

system provides river water cooling to the SACS and RACS. During a LOCA and other DBAs, 

the service water system provides river water only to the SACS, and the RACS is automatically 

isolated. The service water system operation is initiated manually or automatically. Automatic 

operation includes service water system pump starts and isolation of nonsafety-related 

components. 

LRA Table 2.3.3-27 identifies the components subject to an AMR for the service water system 

by component type and intended function. 

2.3.3.27.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has 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 the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.28 Standby Diesel Generator Area Ventilation Systems 

2.3.3.28.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.28 describes the standby diesel generator area ventilation system, which is a 

normally operating mechanical system designed to provide proper environmental conditions 

within each of the compartments contained in the auxiliary building control and diesel structure. 

The purpose of the standby diesel generator area ventilation system is to maintain compartment 

environmental conditions using cooling, heating, and ventilation throughout the diesel portion of 
Structures and Components Subject to Aging Management Review 

 2-74 

the auxiliary building control and diesel generator area building. The system accomplishes this 

by regulating temperature and ventilating air in the diesel building compartments during normal 

and accident conditions. 

LRA Table 2.3.3-28 identifies the components subject to an AMR for the standby diesel 

generator area ventilation system by component type and intended function. 

2.3.3.28.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the standby diesel 

generator area ventilation systems mechanical components within the scope of license renewal, 

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.29 Standby Diesel Generator and Auxiliary Systems 

2.3.3.29.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.29 describes the standby diesel generator and auxiliary system, which is a 

standby mechanical system designed to provide power to Class 1E and selected non-Class 1E 

loads that are needed for safe and orderly shutdown of the reactor, maintaining the plant in a 

safe shutdown condition and mitigating the consequences of a DBA in the event the preferred 

power source is not available. 

The purpose of the standby diesel generator and auxiliary system is to independently provide 

sufficient power to energize all equipment required for safely shutting down the reactor. The 

system accomplishes this by using diesel engines to rotate electric generators attached to the 

diesel engines. 

The standby diesel generator and auxiliary system uses four diesel generator units located in 

separate rooms of the auxiliary building. Each diesel engine will be automatically started under 

LOCA conditions (reactor low-low level, a high drywell pressure signal), and/or loss of power 

condition (undervoltage condition in the 4,160-volt AC system), or by core spray system manual 

initiation. 

LRA Table 2.3.3-29 identifies the components subject to an AMR for the standby diesel 

generator and auxiliary system by component type and intended function. 

2.3.3.29.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the standby diesel 

generator and auxiliary systems mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-75 

2.3.3.30 Standby Liquid Control System 

2.3.3.30.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.30 describes the standby liquid control system, which is a standby and 

redundant sodium pentaborate injection system that is used if the normal reactivity control 

provisions become inoperative, and can be used at anytime in core life. This system acts 

independently from the control rod drive system. The most severe requirement for which the 

system is designed is shutdown from a full power operating condition assuming complete failure 

of the control rod drive system to respond to a scram signal. 

The purpose of the standby liquid control system is to provide sufficient capacity for controlling 

the reactivity difference between the steady state rated operating condition of the reactor and 

the cold shutdown condition, including shutdown margin, thereby ensuring complete shutdown 

capability from the most reactive condition, at any time in core life. The system accomplishes 

this by injecting sodium pentaborate solution into the reactor vessel to absorb neutrons. The 

neutron absorber is dispersed within the reactor core in sufficient quantity to provide a 

reasonable margin for dilution leakage and imperfect mixing. The standby liquid control system 

is not provided as a backup for reactor trip functions, since most transient conditions that require 

reactor trip occur too rapidly to be controlled by the standby liquid control system. Standby 

liquid control operation is initiated automatically by signals from redundant reactivity control 

system or can be initiated manually. 

The standby liquid control system consists of a storage tank, two positive displacement pumps, 

two explosive valves, a test tank, and associated piping and valves. The system takes suction 

from the storage tank and pumps borated water directly into the reactor vessel near the bottom 

of the core shroud. The boron acts as a neutron absorber and shuts down the reactor. 

LRA Table 2.3.3-30 identifies the components subject to an AMR for the standby liquid control 

system by component type and intended function. 

2.3.3.30.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the standby liquid 

control system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.3.31 Torus Water Cleanup System 

2.3.3.31.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.31 describes the torus water cleanup system, which is a mechanical system 

designed to maintain torus water purity, clarity, and level within specified limits. The torus water 

cleanup system has no function related to the safe shutdown of the plant. It can be operated 

during startup, shutdown, and refueling modes, as well as during power operation. 

The purpose of the torus water cleanup system is to maintain suppression pool water quality 

within its limits. The torus water cleanup system accomplishes this purpose by processing torus 

water through the fuel pool cooling and cleanup system’s filter demineralizer. 
Structures and Components Subject to Aging Management Review 

 2-76 

The torus water cleanup system is manually initiated and operated intermittently, as necessary, 

to maintain suppression pool water quality within its limits. 

LRA Table 2.3.3-31 identifies the components subject to an AMR for the torus water cleanup 

system by component type and intended function. 

2.3.3.31.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.31, UFSAR Section 9.1.3, 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 necessary to complete the review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAI as discussed below. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.3.31-01 and noted that they could not 

locate anchors on license renewal drawings LR-M-53-1, sheet 2 (lines O-EC-6”-HBD-025 and 

EE-6”-HCD-001) and LR-M-53-1, sheet 1 (lines 8”-HBD-002 and 8”-HCD-001). The applicant 

was requested to provide additional information to locate the anchors for the O-EC-6”-HBD-025, 

EE-6”-HCD-001, 8”-HBD-002, and 8”-HCD-001 lines between the end of the (a)(2) scoping 

boundary and the safety-nonsafety interface. The staff needed the information to determine if 

the applicant appropriately extended the boundary beyond the safety-nonsafety interface. 

The applicant’s response, dated May 11, 2010, described the location of the anchors, which are 

within the existing (a)(2) scoping boundary. This conforms to the applicant’s methodology and 

did not result in the inclusion of any additional components within the scope of license renewal. 

Based upon its review, the staff finds the applicant’s response to RAI 2.3.3.31-01 acceptable. 

2.3.3.31.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the torus water cleanup system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.3.32 Traversing Incore Probe System 

2.3.3.32.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.32 describes the traversing incore probe (TIP) system, which is an electrical 

instrumentation system designed to provide neutron flux data to be used for calibration of the 

local power range monitor (LPRM) detectors and to determine axial neutron flux levels for core 

power distribution measurements. The TIP system includes mechanical component types that 

are responsible for providing primary containment integrity. 

The purpose of the TIP system is to measure core neutron flux at various positions throughout 

the core. The system accomplishes this by using a set of fission chamber detector instruments 

identical to those used by the LPRM system and a positioning system capable of moving the 

fission chamber detectors to various locations in the core corresponding to the locations of the 
Structures and Components Subject to Aging Management Review 

 2-77 

LPRM detectors. The moveable TIP detectors, as with fixed LPRM detectors, generate signals 

that are processed to indicate neutron flux levels in the vicinity of each detector. 

LRA Table 2.3.3-32 identifies the components subject to an AMR for the TIP system by 

component type and intended function. 

2.3.3.32.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the TIP system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.3.4 Steam and Power Conversion Systems 

LRA Section 2.3.4 identifies the steam and power conversion systems SCs subject to an AMR 

for license renewal. The applicant described the supporting SCs of the steam and power 

conversion systems in the following LRA sections: 

• LRA Section 2.3.4.1, “Condensate Storage and Transfer System” 

• LRA Section 2.3.4.2, “Feedwater System” 

• LRA Section 2.3.4.3, “Main Condenser System” 

• LRA Section 2.3.4.4, “Main Steam System”

2.3.4.1 Condensate Storage and Transfer System

2.3.4.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.1 describes the condensate storage and transfer system, which is a 

condensate storage, makeup, and supply system designed to distribute water to the HPCI, 

reactor core isolation cooling, core spray, control rod drive, RHR, reactor water cleanup, fuel 

pool cooling and cleanup, condensate, feedwater, and radwaste systems for normal and testing 

operational modes. The system is normally filled by the makeup demineralizer system and 

operated continuously during plant power operation. 

The purpose of the condensate storage and transfer system is to provide for: (1) the bulk 

storage of condensate surge volume capability for the condensate system, (2) condensate 

supply for the condensate demineralizer resin transfer, (3) flushing, (4) seal water, (5) resin 

regeneration, and (6) makeup to the fuel pool cooling and cleanup system. The system 

supplies condensate to the suction of the HPCI, reactor core isolation cooling, core spray, and 

control rod drive pumps. The system also supplies condensate and makeup supply to various 

plant systems. 

The condensate storage and transfer system accomplishes this by continuously delivering 

pressurized condensate from the condensate transfer, condensate transfer jockey, or the 

refueling water pumps to individual plant systems. It also provides a flow path between plant 
Structures and Components Subject to Aging Management Review 

 2-78 

water supplies and various equipment when the appropriate manual or remote manual line-ups 

are made. 

LRA Table 2.3.4-1 identifies the components subject to an AMR for the condensate storage and 

transfer system by component type and intended function. 

2.3.4.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.4.1, UFSAR Section 9.2.6, 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 necessary to complete the review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAIs as discussed below. 

In a letter dated April 15, 2010, the staff issued RAI 2.3.4.1-01 and noted that license renewal 

drawing LR-M-51-1, sheet 1, location H-6, shows 10 CFR 54.4(a)(2) line AP-4”-HCD-022 

connected to 10 CFR 54.(a)(1) line AP-4”GBB-030. The applicant was requested to provide 

additional information to locate the anchors for this line between the end of the 

10 CFR 54.4 (a)(2) scoping boundary and the safety-nonsafety interface. The staff needed the 

information to determine if the applicant appropriately extended the boundary beyond the 

safety-nonsafety interface. 

The applicant’s response, dated May 11, 2010, described the location of the anchors, which are 

within the existing 10 CFR 54.4 (a)(2) scoping boundary. This conforms to the applicant’s 

methodology and did not result in the inclusion of any additional components within the scope of 

license renewal. Based upon its review, the staff finds the applicant’s response to 

RAI 2.3.4.1-01 acceptable. 

2.3.4.1.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the condensate storage and transfer system mechanical components within the scope 

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1). 

2.3.4.2 Feedwater System

2.3.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.2 describes the feedwater system, which is a normally operating system 

designed to provide preheated feedwater to the RPV. It provides water to the reactor at a flow 

rate equivalent to what is being generated into steam by boil-off and removed by the main 

steam system. 

The purpose of the feedwater system is to provide preheated feedwater to the RPV during 

normal operation. The system accomplishes this by delivering high-pressure feedwater to the 

reactor vessel. The feedwater system automatically maintains the desired RPV water level for 

all normal reactor operating conditions. 
Structures and Components Subject to Aging Management Review 

 2-79 

The feedwater system provides cooling water to the reactor core during a LOCA but is not 

credited in the accident analyses, and is not considered part of the ECCS or credited to support 

safe shutdown. 

LRA Table 2.3.4-2 identifies the components subject to an AMR for the feedwater system by 

component type and intended function. 

2.3.4.2.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has 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 the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.4.3 Main Condenser System 

2.3.4.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.3 describes the main condenser system, which is a heat sink for the turbine 

exhaust steam, turbine bypass steam, and other flows. It also deaerates and stores the 

condensate for reuse after a period of radioactive decay. Additionally, the main condenser 

system provides for post-accident containment and holdup of activity products. 

The purpose of the main condenser system is to condense and deaerate low-pressure turbine 

exhaust from each of the low-pressure turbines, reactor feed pump turbine exhaust steam, main 

turbine bypass steam, and other steam influents. It also provides a retention time to allow for 

the decay of short-lived radionuclides. The system accomplishes this by transferring heat to the 

circulating water system and by ensuring sufficient retention time in the hotwell to allow for the 

decay of short-lived isotopes. 

LRA Table 2.3.4-3 identifies the components subject to an AMR for the main condenser system 

by component type and intended function. 

2.3.4.3.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the main condenser 

system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.3.4.4 Main Steam System 

2.3.4.4.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.4 describes the main steam system, which is a normally pressurized system 

designed to deliver steam from the reactor to the main turbine and auxiliary system. 

The purpose of the main steam system is to provide a primary containment and reactor coolant 

pressure boundary function, serve as a pressure relief system, and serve as a steam 
Structures and Components Subject to Aging Management Review 

 2-80 

distribution system. The system accomplishes the primary containment and reactor coolant 

pressure boundary function by using piping and valves to limit reactor coolant inventory or 

radioactive release to within acceptable limits. The main steam system accomplishes the 

pressure relief function for the reactor coolant pressure boundary by way of automatic or 

manual actuation of safety relief valves. It also provides automatic or manual reactor 

depressurization to support low-pressure ECCS operation. Distribution of steam to the main 

turbine and auxiliary systems is accomplished by piping distribution branches in the turbine 

building. 

LRA Table 2.3.4-4 identifies the components subject to an AMR for the main steam system by 

component type and intended function. 

2.3.4.4.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has 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 the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-81 

2.4 Scoping and Screening Results: Structures

This section documents the staff’s review of the applicant’s scoping and screening results for 

structures. Specifically, this section describes the following structures: 

● auxiliary boiler building 

● auxiliary building control/diesel generator area 

● auxiliary building service/radwaste area 

● component supports commodity group 

● fire water pump house 

● piping and component insulation commodity group 

● primary containment 

● reactor building 

● service water intake structures 

● shoreline protection and dike 

● switchyard 

● turbine building 

● yard structures 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed 

passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To 

verify that the applicant properly implemented its methodology, the staff focused its review on 

the implementation results. This approach allowed the staff to confirm that there were no 

omissions of structural components that meet the scoping criteria and are subject to an AMR. 

The staff’s evaluation of the information provided in the LRA was performed in the same manner 

for all structures. The objective of the review was to determine if the structural components that 

appeared to meet the scoping criteria specified in the Rule, were identified by the applicant as 

within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff 

evaluated the applicant’s screening results to verify that all long-lived, passive SCs were subject 

to an AMR in accordance with 10 CFR 54.21(a)(1).

To perform its evaluation, the staff used the guidance in SRP-LR Section 2.4, “Scoping and 

Screening Results: Structures,” and reviewed the applicable LRA sections, focusing its review 

on components that had not been identified as within the scope of license renewal. The staff 

reviewed the UFSAR for each structure to determine if the applicant had omitted components 

with intended functions required by 10 CFR 54.4(a) from the scope of license renewal. The staff 

also reviewed the UFSAR to determine if all intended functions required by 10 CFR 54.4(a) 

were specified in the LRA. If omissions were identified, the staff requested additional 

information to resolve the discrepancies.

After completing its review of the scoping results, the staff evaluated the applicant’s screening 

results. For those components with intended functions, the staff sought to determine: (1) if the 

functions are performed with moving parts or a change in configuration or properties, or (2) if 

they are subject to replacement based on a qualified life or specified time period, as described 

in 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to 

confirm that these structural components were subject to an AMR as required by 
Structures and Components Subject to Aging Management Review 

 2-82 

10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information 

to resolve them.

2.4.1 Auxiliary Boiler Building 

2.4.1.1 Summary of Technical Information in the Application

LRA Section 2.4.1 describes the auxiliary boiler building (ABB) as a single story, structural steel 

and concrete masonry unit structure located north of the reactor building. It is located in the 

yard, physically separated from safety-related SSCs such that its failure would not impact a 

safety-related function. It consists of a single story structure partitioned into three areas: the 

auxiliary steam boiler area, water treatment room, and a unit substation room. 

The purpose of the ABB is to provide physical support, shelter, and protection for the 

nonsafety-related auxiliary steam and fresh water supply system components and switchgear 

for the yard electrical substation. Additionally, it houses other components such as oil-fired 

boilers, a deaerator, three boiler feedwater pumps, fresh water tanks and pumps, ventilation, 

and electrical and supporting equipment. 

LRA Table 2.4-1 identifies the components subject to an AMR for the ABB by component type 

and intended function. 

2.4.1.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the ABB SCs within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1). 

2.4.2 Auxiliary Building Control and Diesel Generator Area 

2.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.4.2 describes the auxiliary building control and diesel generator area building as 

a multi-story structure comprised of reinforced concrete walls, slabs, foundation mat, roof, and 

structural steel. It is physically located adjacent to, and north of, the reactor building. The 

auxiliary building control and diesel generator area is classified as a seismic Category I 

structure and is divided into compartments designed to provide physical separation for 

redundant mechanical and electrical safety-related components. It also contains unoccupied 

space, empty rooms, or rooms with abandoned equipment from the Unit 2 plant cancelled 

areas. 

The auxiliary building control and diesel generator area building foundation consists of a 

reinforced concrete mat placed on engineered structural backfill that bears on the dense 

Vincentown Formation. Seismic separation joints separate the foundation and building walls 

from the abutting buildings. 
Structures and Components Subject to Aging Management Review 

 2-83 

The diesel generator area is located in the western portion of the building. The purpose of the 

diesel generator area is to house the diesel fuel tanks, standby diesel generators, ventilation 

and electrical equipment, and supporting systems. 

The control area is located in the eastern portion of the building. The purpose of the control 

area is to house the control room, cable spreading rooms, computer rooms, battery rooms, 

ventilation and electrical equipment, and supporting systems. The control room envelope 

construction joints and penetrations for cable, pipe, HVAC duct, HVAC equipment, dampers, 

and doors are designed specifically for leak tightness. The Unit 2 cancelled control rooms were 

reconfigured for office space and conference rooms and are separate from the main control 

room. 

The purpose of the auxiliary building control and diesel generator area is to provide structural 

support, shelter, and protection to safety-related SSCs housed within it during normal plant 

operation, and during and following postulated DBAs and extreme environmental conditions. 

The control and diesel generator area ventilation systems are evaluated with the auxiliary 

building ventilation system. 

LRA Table 2.4-2 identifies the components subject to an AMR for the auxiliary building control 

and diesel generator area by component type and intended function. 

2.4.2.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.2 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. 

During its review of LRA Section 2.4.2, the staff identified an area in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for the auxiliary building control and diesel generator area. 

In a letter dated March 31, 2010, the staff issued RAI 2.4-2 and requested clarification regarding 

the reinforced concrete isolation walls since they are included in LRA Table 2.4-2 (auxiliary 

building control and diesel generator area) but their isolation function is not listed as an intended 

function in any concrete component listed in the aforementioned table. 

In its response dated April 22, 2010, the applicant stated that the reinforced concrete isolation 

walls are described in UFSAR Section 3.8.4.1.2 and LRA Section 2.4.2. The walls perform the 

isolation function by fulfilling all of the following intended functions: “flood barrier, HELB and 

medium energy line breaks (MELB) shielding, missile barrier, shelter, protection, shielding and 

structural support.” All of these functions are listed in LRA Table 2.4-2 for component type 

“concrete: interior” thus, there is no need for the additional intended function “isolation.” 

Based on its review, the staff finds the applicant’s response to RAI 2.4-2 acceptable because 

the isolation function for the reinforced concrete isolation walls in the auxiliary building control 

and diesel generator area have not been excluded from the scope of license renewal and are 

subject to an AMR. Therefore, the staff’s concern described in RAI 2.4-2 is resolved. 

2.4.2.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 
Structures and Components Subject to Aging Management Review 

 2-84 

identified the auxiliary building control and diesel generator area SCs within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.4.3 Auxiliary Building Service and Radwaste Area 

2.4.3.1 Summary of Technical Information in the Application

LRA Section 2.4.3 describes the auxiliary building service and radwaste area as a multi-story 

structure, separated into three sections and constructed of reinforced concrete and structural 

steel. Additionally, the structure has reinforced concrete panel walls, removable concrete and 

lead block shielding plugs that are restrained with metal decking, and built-up roofing over the 

reinforced concrete roof slab. It is located adjacent to, and east of, the reactor building. 

The building is classified as a seismic Category I structure and has seismic joints that separate 

the foundation mats and building walls of the structure sections and the abutting turbine 

building. 

The purpose of the auxiliary building service and radwaste area is to provide structural support, 

shelter, and protection to safety-related SSCs housed within it during normal plant operation, 

and during and following postulated DBAs and extreme environmental conditions. 

The building contains the remote shutdown panel, a section of the main steam line tunnel, cable 

tray areas, a pipe way, radwaste treatment and storage facilities, chemical lab, heating and 

ventilation equipment, machine shops, decontamination equipment, and personnel support 

facilities. Additionally, it also supports and protects nonsafety-related SSCs whose failure could 

impact a safety-related function. 

LRA Table 2.4-3 identifies the components subject to an AMR for the auxiliary building service 

and radwaste area by component type and intended function. 

2.4.3.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.3 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. 

During its review of LRA Section 2.4.3, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant’s scoping and screening results for 

the auxiliary building service and radwaste area. 

In a letter dated March, 31, 2010, the staff issued RAI 2.4-1 and requested that the applicant 

clarify which components included the main steam tunnel structural elements in LRA 

Table 2.4-3 (auxiliary building service and radwaste area) or justify their omission from scope. 

In its response dated April 22, 2010, the applicant stated that the main steam structural 

components are included in LRA Table 2.4-3. They are composed of the following component 

types: “blowout panel, concrete embedments, concrete: interior, penetration sleeves, spray 

shields and steel components: all structural steel.” 
Structures and Components Subject to Aging Management Review 

 2-85 

Based on its review, the staff finds the response to RAI 2.4-1 acceptable because the main 

steam tunnel structural elements have not been excluded from the scope of license renewal and 

are subject to an AMR. The staff’s concern described in RAI 2.4-1 is resolved. 

2.4.3.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the auxiliary building service and radwaste area SCs within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1). 

2.4.4 Component Supports Commodity Group 

2.4.4.1 Summary of Technical Information in the Application 

LRA Section 2.4.4 describes the component supports commodity group as consisting of 

structural elements and specialty components designed to transfer the load applied from an 

SSC to the building structural element or directly to the building foundation. The commodity 

group is comprised of the following supports: 

● supports for American Society of Mechanical Engineers (ASME) Class 1, 2, and 3 piping 

and components, including reactor vessel to biological shield wall stabilizer, reactor 

vessel skirt support anchorage, reactor vessel support ring girder and anchorage, control 

rod drive housing supports, and service water pumps 

● supports for ASME Class Metal Containment (MC) components, including suppression 

chamber seismic restraints, suppression chamber support saddles and columns, and 

vent system supports 

● supports for cable trays, conduit, HVAC ducts, tube track, instrument tubing, and 

non-ASME piping and components 

● supports for racks, panels, cabinets, and enclosures for electrical equipment and 

instrumentation 

● supports for the emergency diesel generator (EDG), HVAC system components, and 

other miscellaneous mechanical equipment 

● supports for platforms, pipe whip restraints, jet impingement shields, and other 

miscellaneous structures 

The purpose of a support is to transfer gravity, thermal, seismic, and other lateral loads imposed 

on or by the SSC to the supporting building structural element or foundation. This includes 

support for mechanical, electrical, and instrumentation SSCs that are within the scope of license 

renewal. 
Structures and Components Subject to Aging Management Review 

 2-86 

LRA Table 2.4-4 identifies the components subject to an AMR for the component supports 

commodity group by component type and intended function. 

2.4.4.2 Conclusion 

Based on the results of the staff evaluation of the LRA and UFSAR, the staff concludes that the 

applicant has appropriately identified the component supports commodity group SCs within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1). 

2.4.5 Fire Water Pump House 

2.4.5.1 Summary of Technical Information in the Application 

LRA Section 2.4.5 describes the fire water pump house as a single story, above-grade concrete 

structure. It is physically located in the yard north of the reactor building. The structure is 

composed of concrete masonry block with reinforcement steel for the exterior walls and 

concrete masonry block walls for the interior. 

The purpose of the fire water pump house is to provide structural support, shelter, and 

protection for components required for fire protection, such as the diesel driven fire pump, motor 

driven fire pump and jockey pump, associated piping and piping components, controls and 

instrumentation, and electrical panels and enclosures. 

LRA Table 2.4-5 identifies the components subject to an AMR for the fire water pump house by 

component type and intended function. 

2.4.5.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the fire water pump 

house SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the system components subject to an AMR in accordance 

with the requirements stated in 10 CFR 54.21(a)(1). 

2.4.6 Piping and Component Insulation Commodity Group 

2.4.6.1 Summary of Technical Information in the Application 

LRA Section 2.4.6 describes the piping and component insulation commodity group as 

comprised of prefabricated blankets, modules, or panels made from metallic and nonmetallic 

materials, and engineered as integrated assemblies that fit the surface to be insulated. Metallic 

insulation or reflective mirror insulation is fabricated from stainless steel material and 

nonmetallic insulation and consists of materials such as calcium silicate, fiberglass and 

fiberglass molded insulation, cellular glass, and ceramic fiber. 
Structures and Components Subject to Aging Management Review 

 2-87 

Anti-sweat insulation used on chilled water systems consists of fiberglass insulation material 

jacketed with stainless steel or aluminum jacketing. The piping and component insulation 

commodity group is not classified as a safety-related commodity. 

The purpose of piping and component insulation is to improve thermal efficiency, minimize heat 

loads on the HVAC systems, provide for personnel protection, prevent freezing of heat traced 

piping, and protect against sweating of cold piping and components. Insulation located in areas 

with safety-related equipment is designed to protect nearby safety-related SSC equipment from 

overheating and maintain its structural integrity during postulated design-basis seismic events. 

Insulation within the primary containment has been evaluated to ensure that it will not affect the 

ECCS suction strainers. 

LRA Table 2.4-6 identifies the components subject to an AMR for the piping and component 

insulation commodity group by component type and intended function. 

2.4.6.2 Conclusion 

Based on the results of the staff evaluation of the LRA and UFSAR, the staff concludes that the 

applicant has appropriately identified the piping and component insulation commodity group 

SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant 

has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1). 

2.4.7 Primary Containment 

2.4.7.1 Summary of Technical Information in the Application 

LRA Section 2.4.7 describes the primary containment as a General Electric Mark I design and 

consists of a drywell, a pressure suppression chamber, and a vent system connecting the 

drywell and the pressure suppression chamber. It is designed, fabricated, inspected, and tested 

in accordance with the requirements of Subsection NE, “Requirements for MC Components,” of 

the ASME Boiler and Pressure Vessel (B&PV) Code, Section III. The primary containment is 

safety-related and classified as a seismic Category I structure. 

The primary containment structure is completely enclosed by the reactor building and is 

composed of the primary containment structure, primary containment penetrations, and internal 

structures of the primary containment structure. 

The purpose of the primary containment structure is to accommodate, with a minimum of 

leakage, the pressures and temperatures resulting from the break of any enclosed process pipe, 

and thereby, to limit the release of radioactive fission products to values which will ensure offsite 

dose rates well below 10 CFR 50.67 guideline limits. Additionally, it provides a source of water 

for ECCS and for pressure suppression in a LOCA event. The primary containment and internal 

structures also provide structural support to the RPV, the reactor coolant systems, and other 

safety and nonsafety-related SSCs housed within the primary containment. 

The drywell is a steel pressure vessel, with a spherical lower section, a cylindrical upper section, 

and a removable, flanged, hemi-ellipsoidal top head. Inner and outer steel cylindrical skirts, that 

are encased in concrete and anchored to a concrete pedestal, support the drywell. The 

concrete pedestal that supports the drywell is founded on the foundation slab of the reactor 
Structures and Components Subject to Aging Management Review 

 2-88 

building. The outer skirt is designed to transfer the drywell loads at the bottom of the drywell 

into the foundation. The inner skirt extends into the drywell and transfers RPV pedestal loads 

into the foundation. The drywell head is bolted to the drywell flange and is sealed with a double 

seal arrangement. Access into the drywell is through a personnel airlock/equipment hatch, with 

two mechanically interlocked doors, and the other is through an equipment access hatch. 

The purpose of the drywell is to house the RPV, the reactor coolant recirculation system, safety 

relief valves, the branch connections of the reactor primary system, the drywell spray header, 

and internal structures. The internal structures consist of a fill slab, reactor pedestal, biological 

shield wall and its lateral support structural steel, and miscellaneous steel. 

The pressure suppression chamber is a toroidal shaped, steel pressure vessel encircling the 

base of the drywell. The pressure suppression chamber, commonly called the torus, is partially 

filled with demineralized water and includes internal steel framing and access hatches. 

The vent system consists of eight circular vent lines, which form a connection between the 

drywell and the pressure suppression chamber. The lines enter the pressure suppression 

chamber through penetrations provided with expansion bellows (inboard and outboard) and join 

into a common header contained within the air space of the pressure suppression chamber. 

LRA Table 2.4-7 identifies the components subject to an AMR for the primary containment by 

component type and intended function. 

2.4.7.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.7 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. During its review of LRA Section 2.4.7, 

the staff identified areas in which additional information was necessary to complete the 

evaluation of the applicant’s scoping and screening results for the primary containment. 

In a letter dated March, 31, 2010, the staff issued RAI 2.4-3 and requested that the applicant 

clarify if the horizontal seismic restraints shown in UFSAR Figures 3.8-1 and 3.8-13 are included 

within the scope of license renewal per LRA Table 2.4-7 or else justify the exclusion. 

In its response dated April 22, 2010, the applicant stated that the horizontal seismic restraints 

shown in UFSAR Figures 3.8-1 and 3.8-13 are components of the torus (suppression chamber) 

supports and have not been excluded from the scope. 

The applicant also stated that the horizontal seismic restraints are included in the commodity 

group identified as ASME Class MC components which is included in LRA Table 2.4-4. 

Based on its review, the staff finds the response to RAI 2.4-3 acceptable because the horizontal 

seismic restraints have been included within the scope of license renewal and are subject to an 

AMR. The staff’s concern described in RAI 2.4-3 is resolved. 

In a letter dated March, 31, 2010, the staff issued RAI 2.4-4 and requested that the applicant 

clarify where the structural elements that transfer the RPV loads to the RPV ring girder and 

subsequently to the RPV pedestal (shown in UFSAR Figure 3.8-1) are evaluated in the LRA. 
Structures and Components Subject to Aging Management Review 

 2-89 

In its response dated April 22, 2010, the applicant stated that the RPV skirt bolting, ring girder, 

and support anchorage are the structural elements designed to transfer the RPV loads and are 

included in LRA Tables 2.4-4 and 2.4-7. 

The applicant also stated that the RPV skirt bolting, ring girder, and support anchorage are 

included in LRA Table 2.4-4 under the component type “Supports for ASME Class 1 Piping 

Components (support members; welds; bolted connections; support anchorage to building 

structure).” Additionally, the response stated that the RPV pedestal is listed in LRA Table 2.4-7 

under the component type “concrete: interior (RPV pedestal).” 

Based on its review, the staff finds the response to RAI 2.4-4 acceptable because the structural 

elements that transfer the RPV loads to the RPV ring girder and subsequently to the RPV 

pedestal have been included within the scope of license renewal and are, therefore, subject to 

an AMR. The staff’s concern described in RAI 2.4-4 is resolved. 

In a letter dated March, 31, 2010, the staff issued RAI 2.4-5 and requested that the applicant 

clarify the inclusion of the RPV and torus ring girder (shown in UFSAR Figure 3.8-1) as 

components subject to an AMR per LRA Table 2.4-7, “primary containment,” since LRA 

Table 2.4-7 does not include these components. 

In its response dated April 22, 2010, the applicant stated that the torus ring girder is included in 

LRA Table 2.4-7 and is within the scope of license renewal and is, therefore, subject to an AMR. 

Furthermore, the response stated that the RPV ring girder is included in LRA Table 2.4-4 as 

component type “Supports for ASME Class 1 Piping and Components (support members; 

welds; bolted connections; support anchorage to building structure).” 

Based on its review, the staff finds the response to RAI 2.4-5 acceptable because the torus and 

RPV ring girders have been included within the scope of license renewal and are subject to an 

AMR. The staff’s concern described in RAI 2.4-5 is resolved. 

In a letter dated March, 31, 2010, the staff issued RAI 2.4-6 and requested that the applicant 

clarify LRA Sections 2.4.7 (primary containment) and 2.4.8 (reactor building) and Tables 2.4-7 

and 2.4.8 which did not clearly indicate if the following components have been included within 

the scope of license renewal and are subject to an AMR: 

● refueling seal assembly 

● weld pads on the drywell shell for attachment of pipe supports 

● water seal plates at the base of the drywell head as shown in UFSAR Figure 3.8-1 

● spent fuel pool liner plate leak chase system 

In its response dated April 22, 2010, the applicant stated that all the aforementioned 

components, except the spent fuel pool liner plate leak chase system, have been included 

within the scope of license renewal and are subject to an AMR. 

The response stated that the refueling seal assembly and water seal plates provide a seal from 

the reactor to the primary containment drywell shell and from the exterior of the drywell shell to 

the liner of the reactor refuel well to permit flooding of the reactor refuel well or cavity. 

The applicant also stated that LRA Table 2.4-8 (reactor building) includes the component type 

“steel components: refueling bellows (RPV to drywell and drywell to reactor well),” however, the 
Structures and Components Subject to Aging Management Review 

 2-90 

applicant determined that this component type should have also included the carbon steel seal 

plates, which were inadvertently omitted from the table. Therefore, LRA Table 2.4-8 (reactor 

building), on page 2.4-40, was revised to add the carbon steel seal plates identified as the 

component type “steel components: refueling bellows seal plates (RPV to drywell and drywell to 

reactor well).” LRA Table 3.5.2-8 (reactor building), on page 3.5-197, was also revised to add 

the carbon steel seal plates. 

Additionally, the response stated that the weld pads on the drywell shell for attachment of pipe 

supports are included within LRA Table 2.4-4 (component supports commodity group) as 

component types “Supports for ASME Class 1 Piping and Components (support members; 

welds; bolted connections; support anchorage to building structure)” and “Supports for ASME 

Class 2 and 3 Piping and Components (support members; welds; bolted connections; support 

anchorage to building structure),” as shown on page 2.4-18. 

Finally, the response stated that the spent fuel pool liner plate leak chase system has not been 

included within the scope of license renewal since leak collection channels are not 

safety-related and are not part of the water retaining boundary, nor are they required to maintain 

the structural integrity of the spent fuel pool walls. The applicant further stated that the leak 

chase system is not relied upon in safety analyses or plant evaluations to perform a safety 

function. Therefore, the spent fuel pool liner plate leak chase system and its components do not 

have a license renewal intended function. 

Based on its review, the staff finds the response to RAI 2.4-6 acceptable because the following 

components: 

● refueling seal assembly 

● weld pads on the drywell shell for attachment of pipe supports 

● water seal plates at the base of the drywell head as shown in UFSAR Figure 3.8-1 

● spent fuel pool liner plate leak chase system 

have all been clarified regarding their inclusion or exclusion within the scope of license renewal 

and those components which have not been included have been justified. The staff’s concern 

described in RAI 2.4-6 is resolved. 

In RAI 2.4-7 dated March 31, 2010, the staff requested that the applicant clarify the inclusion of 

the shear ties shown in UFSAR Figure 3.8-29 (biological shield plan and elevation) in LRA 

Table 2.4-7, since it was not clear where they had been included. 

In its response dated April 22, 2010, the applicant stated that the shear ties are included within 

the scope of license renewal and are subject to an AMR. Furthermore, the response stated that 

the structural elements that comprise the biological shield wall are the shear ties, liner plates, 

and associated bolting and concrete. Finally, the response stated that the biological shield wall 

shear ties, as well as the liner plates are included as the component type “steel components: 

biological shield liner plates,” as shown in LRA Table 2.4-7 (primary containment), and the 

associated bolting is included in the component type “bolting (structural),” also in LRA 

Table 2.4-7 (primary containment). The biological shield wall concrete is included as the 

component type “concrete: interior (biological shield),” as shown in LRA Table 2.4-7 (primary 

containment) on page 2.4-31. 
Structures and Components Subject to Aging Management Review 

 2-91 

Based on its review, the staff finds the response to RAI 2.4-7 acceptable because the shear ties 

have been included within the scope of license renewal and are subject to an AMR. The staff’s 

concern described in RAI 2.4-7 is resolved. 

2.4.7.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, the applicant’s RAI response, 

and applicable boundary drawings, the staff concludes that the applicant has appropriately 

identified the primary containment SCs within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.4.8 Reactor Building 

2.4.8.1 Summary of Technical Information in the Application 

LRA Section 2.4.8 describes the reactor building as a reinforced concrete enclosure that 

consists of a cylindrical containment structure topped by a toroid spherical dome, with a 

rectangular lower section enclosing the base of the cylinder. The reactor building is a seismic 

Category I reinforced concrete structure designed to maintain its structural integrity during and 

following postulated DBAs and extreme environmental conditions. The reactor building is 

comprised of 7 floor levels in the Unit 1 reactor building and the three-story, reinforced concrete 

and structural steel enclosure plant cancelled area, formerly the Unit 2 reactor building. 

The rectangular reinforced concrete foundation mat is 14 feet thick with the bottom of the mat 

approximately 61 feet below plant grade and founded on engineered structural backfill that 

bears on the dense Vincentown Formation. The mat also supports the southern portion of the 

auxiliary building service and radwaste area. 

The purpose of the reactor building is to minimize ground level release of airborne, radioactive 

fission products and to provide for controlled, elevated release through the ventilation stack of 

the building’s atmosphere under accident conditions. Additionally, it houses the spent fuel 

storage pool, the steam dryer and moisture separator storage pool, the new fuel storage vault, 

reactor cavity, spent fuel storage pool skimmer surge tanks, reactor auxiliary equipment, 

refueling equipment, reactor vessel servicing equipment, and engineered safety features. It 

also provides a secondary containment pressure boundary, structural support, shielding, 

shelter, and protection for primary containment and the components housed within, against 

external DBEs. Finally, it serves as primary containment during reactor refueling and 

maintenance operations when the primary containment system is open. 

The cylindrical wall above the refuel floor supports a 150-ton capacity, polar crane. Personnel 

access openings to the building are provided with interlocked double door air lock systems to 

minimize reactor building leakage. 

The plant cancelled area structure is founded on a reinforced concrete foundation mat that is 

14 feet thick with the bottom of the mat approximately 61 feet below plant grade and founded on 

engineered structural backfill that bears on the dense Vincentown Formation. The foundation is 

structurally independent of the other foundations, separated by a seismic joint. The building 

does not house any safety-related equipment and is classified as a seismic Category I structure. 
Structures and Components Subject to Aging Management Review 

 2-92 

LRA Table 2.4-8 identifies the components subject to an AMR for the reactor building by 

component type and intended function. 

2.4.8.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the reactor building 

SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant 

has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1). 

2.4.9 Service Water Intake Structures 

2.4.9.1 Summary of Technical Information in the Application 

LRA Section 2.4.9 describes the service water intake structures as composed of the service 

water intake structure, service water chemical control building, hypochlorite storage tank dike 

and foundation, and service water sampling shed. 

Service Water Intake Structure. The service water intake structure is a multi-story, reinforced 

concrete and steel structure located west of the reactor building. It is comprised of a reinforced 

concrete foundation mat, slabs, walls, and structural steel. The roof for the structure is 

reinforced concrete. The reinforced concrete foundation mat of the structure is founded on lean 

concrete bearing on the dense Vincentown Formation. It is classified as a seismic Category I 

structure. 

The service water intake structure has trash racks and traveling water screens located on the 

western side of the structure that filter debris from the incoming flow. An outdoor gantry crane 

services the service water intake structure. The crane is supported from the building reinforced 

concrete within the building envelope and from structural steel frames outside the building 

boundary. The foundation for the frames consists of a reinforced concrete slab on piles. 

The service water intake structure and the service water system supply cooling water drawn 

from the Delaware River for reactor safeguard and auxiliary equipment under all credible DBEs 

and DBAs. The Delaware River is the ultimate heat sink, required to provide cooling water for 

emergency shutdown, as well as during normal plant operation. 

The purpose of the service water intake structure is to provide river water to dissipate waste 

heat from the plant during normal, shutdown, and accident conditions. The intake structure also 

provides structural support for pumps and components, which convey the river water to the 

plant. In addition, it provides structural support and access to electrical, mechanical, and 

structural components required to support the function and operation of the service water 

system, service water intake ventilation system (including the deicing system), steel bulkheads, 

trash racks, traveling water screens, access platforms, ladders, and stairs. Components that 

make up the service water intake structure are within the scope of license renewal except for 

miscellaneous steel (ladders, stairs) on the outside of the structure and the pump bay steel 

bulkheads. The miscellaneous steel and the bulkheads are provided for personnel access and 

to facilitate maintenance of the pumps. The components are nonsafety-related and their failure 

would not impact a safety-related function. Thus, the components do not perform an intended 

function and are not within the scope of license renewal. 
Structures and Components Subject to Aging Management Review 

 2-93 

Service Water Chemical Control Building and Hypochlorite Storage Tank Dike and Foundation. 

The service water chemical control building and hypochlorite storage tank dike and foundation 

are structures located east of the service water intake structure, and are founded on a common 

reinforced concrete slab on grade. The service water chemical control building is a metal 

prefabricated commercial grade building. The purpose of the service water chemical control 

building and hypochlorite storage tank dike and foundation is to house the equipment used to 

inject hypochlorite into the service water system. The hypochlorite storage tank dike and 

foundation is a combination of reinforced concrete slab and short perimeter walls that provide 

structural support for the storage tanks that contain the hypochlorite chemical, and functions as 

a fluid retaining basin in case of storage tank leakage or failure. These structures are classified 

as nonsafety-related and do not perform an intended function for license renewal. 

Service Water Sampling Shed. The service water sampling shed is located in the yard 

northwest of the reactor building. The shed is a metal prefabricated commercial grade building 

founded on a reinforced concrete slab on grade. The purpose of the structure is to house the 

equipment used to sample chemicals in the service water system. The structure is classified as 

nonsafety-related and does not perform an intended function for license renewal. 

LRA Table 2.4-9 identifies the components subject to an AMR for the service water intake 

structures by component type and intended function. 

2.4.9.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the service water 

intake structures SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and 

that the applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.4.10 Shoreline Protection and Dike 

2.4.10.1 Summary of Technical Information in the Application 

LRA Section 2.4.10 describes the shoreline protection and dike, also known as the “shoreline 

protective dike” as comprised of cofferdams, steel sheet piles, and rock located at the service 

water intake structure along the Delaware River shoreline. The original earthen shoreline dike 

west of the reactor building was replaced with sheet pile retaining walls and rock fill 

construction, extending 100 feet on both sides of the service water intake structure. This 

section of the shoreline protection and dike is classified as nonsafety-related and seismic 

Category Il/I, to provide protection against shoreline recession during probable maximum 

hurricane (PMH) surge. An earthen dike continues north of the intake structure sheet pile 

retaining walls to the barge slip and south to the Salem Generating Station Units 1 and 2 

structures. 

The shoreline protection dike includes four 44-foot diameter sheet pile cellular cofferdams, two 

on each side of the service water intake structure. The cofferdams are filled with coarse 

aggregate with the lower part of the backfill pressure grouted. 
Structures and Components Subject to Aging Management Review 

 2-94 

The purpose of the shoreline protection and dike is to provide protection against shoreline 

recession for the service water system SCs during and following design seismic and flood 

events. 

LRA Table 2.4-10 identifies the components subject to an AMR for the shoreline protection and 

dike by component type and intended function. 

2.4.10.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the shoreline 

protection and dike SCs within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.4.11 Switchyard 

2.4.11.1 Summary of Technical Information in the Application 

LRA Section 2.4.11 describes the switchyard as physically located in a fenced area east of the 

reactor building and comprised of the 500-kilovolt (kV) switchyard and a control house. 

The switchyard foundation consists of reinforced concrete walls, grade beams, and isolated 

footings bearing on steel piles. The control house is a single story masonry wall structure, with 

its foundation composed of a reinforced concrete slab on steel piles. Its roof is comprised of a 

precast, prestressed, concrete hollow slab covered with insulation and built-up roofing. A 

reinforced concrete cable underground vault runs under the northern and the eastern sides of 

the control house. The piles for the switchyard are composed of steel pipe filled with concrete 

and protected with a cathodic protection system. The switchyard is classified as a 

nonsafety-related structure and its failure would not impact a safety-related function but meets 

10 CFR 54.4(a)(3) because it is relied upon in the safety analyses or plant evaluations to 

perform a function that demonstrates compliance with the NRC regulations for SBO 

(10 CFR 50.63). 

The purpose of the switchyard is to provide structural support, shelter, and protection for the 

13.8-kV station power system, and the offsite 500-kV AC system components and commodities. 

LRA Table 2.4-11 identifies the components subject to an AMR for the switchyard by 

component type and intended function. 

2.4.11.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the switchyard SCs 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-95 

2.4.12 Turbine Building 

2.4.12.1 Summary of Technical Information in the Application 

LRA Section 2.4.12 states that the structures included in the boundary of the turbine building 

are the turbine building and the administration facility. The section describes the turbine 

building as a multi-story, reinforced concrete and steel structure located adjacent to the auxiliary 

building service and radwaste area, and east of the reactor building. The structures included in 

the boundary of the turbine building are the turbine building and the administration facility. The 

above ground exterior walls are precast concrete panels and insulated metal siding. The roof is 

cellular metal deck, insulation board, and built-up roofing material supported by structural steel. 

The building foundation consists of reinforced concrete mats placed on engineered structural 

backfill that bears on the dense Vincentown Formation. Seismic joints separate the foundation 

mats and building walls of the turbine building, the administration facility, and the abutting 

auxiliary building service and radwaste area. The turbine building is classified as a 

nonsafety-related, nonseismic Category I structure. 

The Turbine Building. The turbine building encloses the steam and power conversion system 

and turbine auxiliary systems, reactor protection system components, and supporting systems. 

Major components within the building include the main turbine generator, main condensers, air 

ejectors, moisture separators, feedwater heaters, feed and condensate pumps, condensate 

demineralizers, main steam control and stop valves, and their associated piping. Radioactive 

components are enclosed within heavy concrete walls with labyrinth entrances for shielding 

purposes. Some interior walls, required for separation, radiation shielding, or fire protection, are 

constructed of fully grouted reinforced concrete masonry units. The building also houses other 

nonsafety-related electrical and mechanical equipment and components, such as the motor 

generator sets for reactor recirculation pumps, condensate storage and transfer pumps, the 

demineralizer system, HVAC equipment, electrical equipment and components, and 

instrumentation and their enclosures, as applicable. Two 220-ton overhead cranes are provided 

above the turbine generator operating floor to service the turbine generator unit. The turbine 

generator is supported by a free standing, reinforced concrete pedestal founded on a reinforced 

concrete mat foundation, and the pedestal extends to the operating floor. The operating floor 

framing is supported on slide bearings that are in turn, supported by the pedestal. Separation 

joints are provided between the pedestal and walls and other turbine building floors to prevent 

the transfer of turbine vibration to the building. 

The turbine building houses the main condenser system to provide shielding for post-accident 

containment and holdup. The turbine building also provides shielding from radiation exposure 

to allow personnel access to operate and maintain equipment. 

The purpose of the turbine building is to provide structural support, shelter, and protection for 

SSCs classified as safety and nonsafety-related. The safety-related components housed within 

the turbine building are fail-safe by design, and the failure of nonsafety-related SSCs cannot 

prevent the accomplishment of the safety-related intended function. 

The Administration Facility. The administration facility contains office, warehouse, and 

unoccupied space, or empty rooms from the Unit 2 plant cancelled areas. The old Unit 2 turbine 

generator-operating floor and lay down area is a common storage area with the turbine building 

generator-operating floor. The administration facility first (grade level) and second floors were 
Structures and Components Subject to Aging Management Review 

 2-96 

reconfigured for office space, conference rooms, a cafeteria, and supporting facilities that have 

no safety-related function. 

Reactor protection system sensors are mounted on the turbine to monitor first stage pressure, 

main control valve fast closure, and stop valve closure and on the main condenser to measure 

condenser vacuum. This safety-related equipment is located in the turbine building. The 

sensors are safety-related, however, they are physically mounted on equipment that is not 

seismic Category I, and are located in the turbine building, which is not a seismic Category I 

structure. The reactor protection system is a fail-safe design, with other diverse safety-related 

reactor scram signals such that no single failure or credible natural disaster can prevent a 

reactor scram. Therefore, failure of the turbine components or structure will not result in a 

failure of the reactor protection system to attain its fail-safe state and scram the reactor. This 

system is evaluated with the reactor protection system. 

LRA Table 2.4-12 identifies the components subject to an AMR for the turbine building by 

component type and intended function. 

2.4.12.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the turbine building 

SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant 

has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1). 

2.4.13 Yard Structures 

2.4.13.1 Summary of Technical Information in the Application

LRA Section 2.4.13 describes the yard structures as comprised of the compressed gas storage 

areas, concrete box valve pits, condensate storage tank dike and foundation, fire water tank 

foundations, light poles, manholes, handholes and duct banks, miscellaneous yard structures, 

transformer foundations, transmission towers and foundations, trenches, and yard drainage 

catch basins and ditch. 

The purpose of the yard structures is to provide structural support, shelter, and protection for 

safety-related and nonsafety-related components and commodities, including components 

credited for SBO and fire protection. In addition, the condensate storage tank dike and 

foundation protects against the uncontrolled release of condensate water to the environment. 

Other functions of the yard structures include drainage of the yard area, lighting, and personnel 

and vehicular access throughout the yard area. 

Compressed Gas Storage Areas. Compressed gas storage areas are comprised of the carbon 

dioxide storage facility, hydrogen storage facility, liquid oxygen storage facility, and nitrogen 

storage facility. The compressed gas storage areas are reinforced concrete slab foundations on 

grade facilities that are located in the yard area. The compressed gas storage areas are 

nonsafety-related and separated from safety-related SSCs such that their failure would not 

impact a safety-related function. The compressed gas storage areas do not perform an 

intended function and are not within the scope of license renewal. 
Structures and Components Subject to Aging Management Review 

 2-97 

Concrete Box Valve Pits. The concrete box valve pits are located in the yard area and are 

buried below plant grade with a removable concrete panel on top. There are access openings 

in the concrete panels with covers to allow personnel access into the valve pits. The valve pits 

contain nonsafety-related piping and valves for not in-scope plant water systems, including the 

circulating water system and the not in-scope portion of the service water system. The concrete 

valve pits are located at grade level and below. They are separated from safety-related SSCs, 

except for valve pits 4 and 5, such that their failure would not impact a safety-related function. 

Valve pits 4 and 5 are located adjacent to the west wall of the Unit 1 reactor building, and failure 

of these valve pits and enclosed components would not affect the license renewal intended 

functions of the reactor building or enclosed mechanical piping system. The reinforced concrete 

box valve pits do not perform an intended function and are not within the scope of license 

renewal. 

Condensate Storage Tank Dike and Foundation. The condensate storage tank dike and 

foundation is a reinforced concrete structure located south of the reactor building. The structure 

has a 2 feet thick rectangular reinforced concrete foundation slab with the top of the slab 

approximately 9 feet below plant grade. The reinforced concrete foundation slab of the 

structure is founded on lean concrete bearing on the dense Vincentown Formation. An 

octagonal reinforced concrete slab, approximately 2 feet thick, is cast on the foundation slab 

and functions as the foundation pedestal for the condensate storage tank. There are 2 feet 

thick reinforced concrete walls, approximately 20 feet in height, along the edge of the foundation 

slab that form an open top box structure. The structure has been sized to contain any spillage 

due to the failure of the condensate storage tank. A reinforced concrete valve pit is located on 

the east side of the condensate storage tank dike. This valve pit is a rectangular open top box 

structure similar to the condensate storage tank dike, with the perimeter walls extending 

approximately 1 foot above plant grade and with grating over the open top. The condensate 

storage tank dike and foundation is classified as a seismic Category I structure. The 

condensate storage tank dike and foundation perform license renewal intended functions and 

are within the scope of license renewal. 

Fire Water Tank Foundations. The fire water tank foundations are two octagonal reinforced 

concrete slabs on grade and are approximately 3 feet thick. The tank foundations are located 

north of the reactor building in the yard, separated from safety-related SSCs such that their 

failure would not impact a safety-related function. There is a reinforced concrete valve pit 

located on the south end of each tank foundation and they extend approximately 6 feet under 

the tank foundation. The valve pit is a rectangular box structure with perimeter walls extending 

approximately 1 foot above plant grade and a foundation slab approximately 10 feet below plant 

grade. There is a reinforced concrete slab that serves as a roof over the valve pit, with an 

opening that has a manhole cover for personnel access. The valve pit foundation consists of a 

reinforced concrete slab with piles under the perimeter walls. The fire water tank foundations 

perform an intended function and are within the scope of license renewal. 

Light Poles. Light poles are metal poles that are mounted on concrete pier foundations located 

in the yard area. The light poles provide area lighting for the safe movement of personnel and 

for security surveillance, and are classified as nonsafety-related. Light poles do not perform an 

intended function and are not within the scope of license renewal. 

Manholes, Handholes, and Duct Banks. Manholes and handholes consist of reinforced 

concrete rectangular box structures buried underground with a reinforced concrete panel on top. 

The manholes have an opening and cover to allow plant personnel access to electrical cables 

routed in duct banks. Manholes and handholes serve as intermediate connection points of duct 
Structures and Components Subject to Aging Management Review 

 2-98 

banks routed in the yard area. There are safety-related and nonsafety-related manholes 

located in the yard area. Manhole covers are provided at the openings for shelter and 

protection. 

Duct banks are comprised of the placement of multiple raceways in an excavated trench in the 

yard that are encased in concrete and then backfilled with soil or engineered compacted backfill. 

The duct banks are used to route nonsafety-related and safety-related cables between 

structures and in the switchyard area. Safety-related duct banks that are buried in the yard are 

provided with a reinforced concrete protection slab that is cast over the duct bank for missile 

protection. 

Manholes, handholes, and duct banks perform an intended function and are within the scope of 

license renewal. 

Miscellaneous Yard Structures. Miscellaneous yard structures, located in the yard area, are not 

uniquely tied to a group of common structures in the yard. These miscellaneous yard structures 

include roadways, sidewalks, fences, bollards, lift stations, reinforced concrete foundation slabs 

for buildings that have been removed from the site, concrete pads for commercial grade HVAC 

units for office buildings, abandoned concrete equipment foundations, plant security shooting 

range and facility complex, and miscellaneous yard sheds and foundations. The miscellaneous 

yard structures are nonsafety-related and separated from safety-related SSCs. The 

miscellaneous yard structures do not perform an intended function and are not within the scope 

of license renewal. 

Transformer Foundations. Transformer foundations are reinforced concrete slabs that provide 

structural support for station transformers located in the yard area. The foundations can be 

concrete slabs on grade, concrete slabs that are cast on a subgrade foundation several feet 

below grade, or on piles with perimeter walls with a pedestal type concrete equipment pad on 

the foundation slab that provides the structural support for the transformer. Transformer 

foundations are classified as nonsafety-related and do not perform a safety-related function. 

There are transformers that are required to support SBO restoration and, therefore, those 

foundations are within the scope of license renewal. 

Transmission Towers and Foundations. Transmission towers and foundations are tall steel 

tower structures that are supported on reinforced concrete pier foundations located in the yard 

area. The transmission towers are located between the HCGS switchyard and the Salem 

Generating Station (Salem) switchyard. These transmission towers support the 500-kV power 

lines that are routed between the HCGS and Salem switchyards. Transmission towers and 

foundations are classified as nonsafety-related and do not perform a safety-related function. 

These transmission towers are required to support the SBO restoration function and, therefore, 

are within the scope of license renewal. 

Trenches. Trenches are reinforced concrete rectangular box structures with open tops that are 

buried in excavated trenches in the yard area, with either a metal grating or metal plate covering 

the open tops. The trenches are used to route piping and components for not in-scope plant 

systems. The top of the trenches are located at approximately 6 inches above plant grade with 

the remaining portion of the trenches below grade such that their failure would not impact a 

safety-related function. The trenches do not perform an intended function and are not within the 

scope of license renewal. 
Structures and Components Subject to Aging Management Review 

 2-99 

Yard Drainage Catch Basins and Ditch. Yard drainage catch basins are reinforced concrete box 

structures that are buried in the yard, with an open top that has slotted grating. The yard ditch is 

an open channel earthen feature located along the northern boundary of the station’s property. 

These features are provided to drain the station’s yard area during normal and severe 

rainstorms. The yard drainage catch basins and ditch do not perform an intended function and 

are not within the scope of license renewal. 

LRA Table 2.4-13 identifies the components subject to an AMR for the yard structures by 

component type and intended function. 

2.4.13.2 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the yard structures 

SSCs within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant 

has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1). 
Structures and Components Subject to Aging Management Review 

 2-100 

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls 

Systems

This section documents the staff’s review of the applicant’s scoping and screening results for 

the electrical and I&C systems. Specifically, this section discusses: 

● Electrical and I&C Component Commodity Groups 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed 

passive, long-lived SSCs that are within the scope of license renewal and subject to an AMR. 

To verify that the applicant properly implemented its methodology, the staff focused its review 

on the implementation results. This approach 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 provided in the LRA was performed in the same manner 

for all electrical and I&C systems. The objective of the review was to determine if the 

components and supporting structures for electrical and I&C systems that appear to meet the 

scoping criteria specified in the Rule, were identified by the applicant as within the scope of 

license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant’s 

screening results to verify that all long-lived, passive SSCs were subject to an AMR, in 

accordance with 10 CFR 54.21(a)(1). 

To perform its evaluation, the staff used the guidance in SRP-LR Section 2.5, “Scoping and 

Screening Results: Electrical and Instrumentation and Controls Systems,” and reviewed the 

applicable LRA sections, focusing its review on components that had not been identified as 

within the scope of license renewal. The staff reviewed the UFSAR for each electrical and I&C 

system to determine if the applicant had omitted components with intended functions required 

by 10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the UFSAR to 

determine if all intended functions required by 10 CFR 54.4(a) were specified in the LRA. If 

omissions were identified, the staff requested additional information to resolve the 

discrepancies. 

After completing its review of the scoping results, the staff evaluated the applicant’s screening 

results. For those SSCs with intended functions, the staff sought to determine: (1) if the 

functions are performed with moving parts or a change in configuration or properties, or (2) if the 

SSCs are subject to replacement based on a qualified life or specified time period, as described 

in 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to 

confirm that these SSCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). If 

discrepancies were identified, the staff requested additional information to resolve them. 

2.5.1 Electrical and Instrumentation and Controls Component Commodity Groups 

2.5.1.1 Summary of Technical Information in the Application 

LRA Section 2.5 describes the electrical and I&C systems. The scoping method includes all 

plant electrical and I&C components. Evaluation of electrical systems includes electrical and 

I&C components in mechanical systems. The plant-wide basis approach for the review of plant 
Structures and Components Subject to Aging Management Review 

 2-101 

equipment eliminates the need to indicate each unique component and its specific location and 

precludes improper exclusion of components from an AMR. 

The electrical and I&C components that were identified to be within the scope of license renewal 

have been grouped by the applicant into component commodity groups. The applicant has 

applied the screening criteria in 10 CFR 54.21(a)(1)(i) and 10 CFR 54.21(a)(1)(ii) to this list of 

component commodity groups to identify those that perform their intended functions without 

moving parts or without a change in configuration or properties, and to remove the component 

commodity groups that are subject to replacement based on a qualified life or specified time 

period. 

LRA Table 2.5.2-1 identifies the components subject to an AMR for the electrical commodity 

groups by component type and intended function. 

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 required by 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). 

General Design Criteria 17 of 10 CFR Part 50, Appendix A, requires that electric power from the 

transmission network to the onsite electric distribution system be supplied by two physically 

independent circuits to minimize the likelihood of their simultaneous failure. In addition, the staff 

noted that the guidance provided by letter dated April 1, 2002, “Staff Guidance on Scoping of 

Equipment Relied on to Meet the Requirements of the Station Blackout Rule (10 CFR 50.63) for 

License Renewal (10 CFR 54.4(a)(3)),” states: 

For purposes of the license renewal rule, the staff has determined that the plant 

system portion of the offsite power system that is used to connect the plant to the 

offsite power source should be included within the scope of the rule. This path 

typically includes switchyard circuit breakers that connect to the offsite system 

power transformers (startup transformers), the transformers themselves, the 

intervening overhead or underground circuits between circuit breaker and 

transformer and transformer and onsite electrical system, and the associated 

control circuits and structures. Ensuring that the appropriate offsite power 

system long-lived passive SSCs that are part of this circuit path are subject to an 

AMR will assure that the bases underlying the 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, switchyard breakers (including the associated controls and structures) within the 

scope of license renewal. Figure 2.1-2, “Hope Creek Offsite Power for SBO,” indicates the SBO 

recovery path and electrical distribution systems. LRA Section 2.5.1 states that the scoping 

boundary consists of six 500-kV switchyard circuit breakers (30X, 31X, 50X, 51X, 60X, and 
Structures and Components Subject to Aging Management Review 

 2-102 

61X). 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. 

In the LRA, the applicant stated that cable tie-wraps are used to bundle wires and cables 

together to maintain the cable runs neat and orderly. The cable tie-wraps are not credited for 

maintaining cable ampacity, ensuring maintenance of cable minimum bending radius, or 

maintaining cables within vertical raceways. Furthermore, the applicant is not crediting the use 

of cable tie-wraps in the seismic qualification of cable trays. Based on the review of this 

information and the UFSAR, the staff finds the applicant’s exclusion of cable tie-wraps from the 

SSCs subject to an AMR, acceptable. 

2.5.1.3 Conclusion 

Based on the results of the staff evaluation of the LRA, UFSAR, and applicable boundary 

drawings, the staff concludes that the applicant has appropriately identified the electrical and 

I&C systems components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and that the applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1). 

2.6 Conclusion for Scoping and Screening

The staff reviewed the information in LRA Section 2, “Scoping and Screening Methodology for 

Identifying Structures and Components Subject to Aging Management Review, and 

Implementation Results.” 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). 

On the basis of its review, the staff concludes that the applicant has 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). 

With regard to these matters, the staff concludes that the activities authorized by the renewed 

license will continue to be conducted in accordance with the CLB, and any changes made to the 

CLB, to comply with 10 CFR 54.21(a)(1), are in accordance with NRC regulations.
 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 Hope Creek Generating Station (HCGS), 

by the staff of the United States Nuclear Regulatory Commission (NRC or the staff). 

In Appendix B of its license renewal application (LRA), PSEG Nuclear, LLC (PSEG or the 

applicant) described the 47 AMPs it relies on to manage or monitor the aging of passive and 

long-lived structures and components (SCs). 

In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA 

Section 2 as within the scope of license renewal and subject to an AMR. 

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report

In preparing its LRA, the applicant credited NUREG-1801, “Generic Aging Lessons Learned 

(GALL) Report,” Revision 1, 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 SCs for license renewal without change. 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 the programs at its facility correspond to those reviewed and approved in the 

GALL Report. 

The purpose of the GALL Report is to provide the staff with 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 used to review an 

applicant’s LRA will be greatly reduced, thereby improving the efficiency and effectiveness of 

the license renewal review process. The GALL Report also serves as a reference for applicants 

and staff reviewers to quickly identify those AMPs and activities that the staff has determined 

will adequately manage or monitor aging during the period of extended operation. 

The GALL Report identifies: (1) systems, structures, and components (SSCs); (2) SC materials; 

(3) environments to which the SCs are exposed; (4) the aging effects associated with the 

materials and environments; (5) the AMPs credited with managing or monitoring the aging 

effects; and (6) recommendations for further applicant evaluations of aging management for 

certain component types. 

The staff performed its review in accordance with the requirements of Title 10, Part 54 of the 

Code of Federal Regulations (10 CFR Part 54), “Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants”; the guidance provided in NUREG-1800, “Standard Review 
Aging Management Review Results 

 3-2 

Plan for Review of License Renewal Applications for Nuclear Power Plants” (SRP-LR), 

Revision 1, dated September 2005; and the guidance provided in the GALL Report. 

In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and 

associated AMPs during the week of February 19, 2010, as described in the “Audit Report 

Regarding the Hope Creek Generating Station, License Renewal Application,” dated 

September 3, 2010 (Agencywide Documents Access and Management System (ADAMS) 

Accession No. ML101660452). The onsite audits and reviews are designed to maximize the 

efficiency of the staff’s LRA review. The applicant can respond to questions, the staff can 

readily evaluate the applicant’s responses, the need for formal correspondence between the 

staff and the applicant is reduced, and the result is an improvement in review efficiency. 

3.0.1 Format of the License Renewal Application 

The applicant submitted an application that followed the standard LRA format, as determined by 

the staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003 (ADAMS Accession 

No. ML030990052). This LRA format incorporates lessons learned from the staff’s reviews of 

previous 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 Section 3 parallels Chapter 3 of the SRP-LR. The AMR results 

information in LRA Section 3 is presented in the following two table types: 

 (1) Table 3.x.1 – where “3” indicates the LRA section number, “x” indicates the subsection 

number from the GALL Report, and “1” indicates that this is the first table type in LRA 

Section 3.

 (2) Table 3.x.2-y – where “3” indicates the LRA section number, “x” indicates the subsection 

number from the GALL Report, “2” indicates that this is the second table type in LRA 

Section 3, and “y” indicates the system table number.

The content of the previous LRAs and HCGS application are essentially the same. The intent of 

the format used for the LRA was to modify the tables in LRA Section 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 that it considered to be consistent with the GALL Report. In each 

Table 2, the applicant identified the linkage between the scoping and screening results in LRA 

Section 2 and the AMRs in LRA Section 3. 

3.0.1.1 Overview of Table 1s 

Each Table 1 summarizes and compares how the facility aligns with the corresponding tables in 

the GALL Report. The tables are essentially the same as Tables 1 through 6 in the GALL 

Report, except that the “Type” column has been replaced by an “Item Number” column and the 

“Item Number in GALL” column has been replaced by a “Discussion” column. The “Item 

Number” column is a means for the staff reviewer to cross-reference Table 2s with Table 1s. In 

the “Discussion” column, the applicant provided clarifying information. 
Aging Management Review Results 

 3-3 

The following are examples of information that might be contained within this column: 

● further evaluation recommended – information or reference to information on further 

evaluations 

● name of a plant-specific program 

● exceptions to GALL Report assumptions 

● discussion of how the line is consistent with the corresponding line item in the GALL 

Report when the consistency may not be obvious 

● discussion of how the item is different from the corresponding line item in the GALL 

Report (e.g., when an exception is taken to a GALL Report AMP) 

The format of each Table 1 allows the staff to align a specific row in the table with the 

corresponding GALL Report table row so that the consistency can be checked easily. 

3.0.1.2 Overview of Table 2s 

Each Table 2 provides the detailed results of the AMRs for components identified in LRA 

Section 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures 

within a specific system grouping (e.g., reactor coolant system (RCS), engineered safety 

features (ESFs), auxiliary systems, etc.). For example, the ESF group has tables specific to the 

core spray system, high-pressure coolant injection (HPCI) system, and residual heat removal 

(RHR) system. Each Table 2 consists of nine columns: 

 (1) Component Type – The first column lists LRA Section 2 component types subject to an 

AMR in alphabetical order. 

 (2) Intended Function – The second column identifies the license renewal intended 

functions, including abbreviations, where applicable, for the listed component types. 

Definitions and abbreviations of intended functions are in LRA Table 2.0-1. 

 (3) Material – The third column lists the particular construction material(s) for the component 

type. 

 (4) Environment – The fourth column lists the environments to which the component types 

are exposed. Internal and external service environments are indicated with a list of 

these environments in LRA Tables 3.0-1 and 3.0-2. 

 (5) Aging Effect Requiring Management – The fifth column lists aging effects requiring 

management (AERMs). As part of the AMR process, the applicant determined any 

AERMs for each combination of material and environment. 

 (6) Aging Management Programs – The sixth column lists the AMPs that the applicant uses 

to manage the identified aging effects. 

 (7) NUREG-1801 Volume 2 Item – The seventh column lists the GALL Report item(s) 

identified in the LRA as similar to the AMR results. The applicant compared each 

combination of component type, material, environment, AERM, and AMP in LRA 

Table 2 with the GALL Report items. If there were no corresponding items in the GALL 
Aging Management Review Results 

 3-4 

Report, the applicant left the column blank in order to identify the AMR results in the LRA 

tables corresponding to the items in the GALL Report tables. 

 (8) Table 1 Item – The eighth column lists the corresponding summary item number from 

LRA Table 1. If the applicant identifies in each LRA Table 2 AMR results consistent with 

the GALL Report, the Table 1 line item summary number should be listed in LRA 

Table 2. If there is no corresponding item in the GALL Report, column eight is left blank. 

In this manner, the information from the two tables can be correlated. 

 (9) Notes – The ninth column lists the corresponding notes used to identify how the 

information in each Table 2 aligns with the information in the GALL Report. The notes, 

identified by letters, were developed by an NEI work group and will be used in future 

LRAs. Any plant-specific notes identified by numbers provide additional information 

about the consistency of the line item with the GALL Report. 

3.0.2 Staff’s Review Process 

The staff conducted three types of evaluations of the AMRs and AMPs: 

 (1) For items that the applicant stated was consistent with the GALL Report, the staff 

conducted either an audit or a technical review to determine consistency. 

 (2) For items that the applicant stated was 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. 

 (3) For other items, the staff conducted a technical review to verify conformance with 

10 CFR 54.21(a)(3) requirements. 

Staff audits and technical reviews of the applicant’s AMPs and AMRs determine whether the 

aging effects on SCs can be adequately managed to maintain their intended functions 

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 AMPs 

For AMPs for which the applicant claimed consistency with the GALL Report AMPs, the staff 

conducted either an audit or a technical review to verify the claim. For each AMP with one or 

more deviations, the staff evaluated each deviation to determine whether the deviation was 

acceptable and whether the modified AMP would adequately manage the aging effect(s) for 

which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full 

review to determine their adequacy. The staff evaluated the AMPs against the following 

10 program elements defined in SRP-LR Appendix A: 

 (1) Scope of the Program – Scope of the program should include the specific SCs subject to 

an AMR for license renewal. 

 (2) Preventive Actions – Preventive actions should prevent or mitigate aging degradation. 

 (3) Parameters Monitored or Inspected – Parameters monitored or inspected should be 

linked to the degradation of the particular structure or component intended functions. 

 (4) Detection of Aging Effects – Detection of aging effects should occur before there is a 

loss of structure or component intended functions. This includes aspects such as 

method or technique (i.e., visual, volumetric, surface inspection), frequency, sample 

size, data collection, and timing of new/one-time inspections to ensure timely detection 

of aging effects. 

 (5) Monitoring and Trending – Monitoring and trending should provide predictability of the 

extent of degradation, as well as timely corrective or mitigative actions. 

 (6) Acceptance Criteria – Acceptance criteria, against which the need for corrective action 

will be evaluated, should ensure that the structure or component intended functions are 

maintained under all CLB design conditions during the period of extended operation. 

 (7) Corrective Actions – Corrective actions, including root cause determination and 

prevention of recurrence, should be timely. 

 (8) Confirmation Process – Confirmation process should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective. 

 (9) Administrative Controls – Administrative controls should provide for a formal review and 

approval process. 

 (10) Operating Experience – Operating experience of the AMP, including past corrective 

actions resulting in program enhancements or additional programs, should provide 

objective evidence to support the conclusion that the effects of aging will be adequately 

managed so that the SC intended functions will be maintained during the period of 

extended operation. 

Details of the staff’s audit evaluation of program elements (1) through (6) are documented in 

SER Section 3.0.3. 

The staff reviewed the applicant’s quality assurance (QA) program and documented its 

evaluations in SER Section 3.0.4. The staff’s evaluation of the QA program included an 
Aging Management Review Results 

 3-6 

assessment of the “corrective actions,” “confirmation process,” and “administrative controls” 

program elements. 

The staff reviewed the information on the “operating experience” program element and 

documented its evaluation in SER Section 3.0.3. 

3.0.2.2 Review of AMR Results 

Each LRA Table 2 contains information concerning whether or not the AMRs identified by the 

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed 

the intended function, material, environment, AERM, and AMP combination for a particular 

system component type. Item numbers in column 7 of the LRA, “NUREG-1801 Volume 2 Item,” 

correlate to an AMR combination as identified in the GALL Report. The staff also conducted 

onsite audits to verify these correlations. A blank in column seven indicates that the applicant 

was unable to identify an appropriate correlation in the GALL Report. The staff also conducted 

a technical review of combinations not consistent with the GALL Report. The next column, 

“Table 1 Item,” provides a reference number that indicates the corresponding row in Table 1. 

3.0.2.3 UFSAR Supplement 

Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed 

the updated final safety analysis report (UFSAR) supplement, which summarizes the applicant’s 

programs and activities for managing aging effects for the period of extended operation, as 

required by 10 CFR 54.21(d). 

3.0.2.4 Documentation and Documents Reviewed 

In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report. 

During the onsite audit, the staff also examined the applicant’s justifications to verify that the 

applicant’s activities and programs will adequately manage the effects of aging on SCs. The 

staff also conducted detailed discussions and interviews with the applicant’s license renewal 

project personnel and others with technical expertise relevant to aging management. 

3.0.3 Aging Management Programs 

SER Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA 

Appendix B. The table also indicates whether the AMP is an existing or new program 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. 
Aging Management Review Results 

 3-7 

Table 3.0.3-1 Hope Creek Generating Station Aging Management Programs 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL 

Report 

GALL Report Aging 

Management 

Programs 

SER 

Section 

ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC, 

and IWD Program 

A.2.1.1 

B.2.1.1 

Existing Consistent XI.M1, “ASME 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD” 

3.0.3.1.1 

Water Chemistry A.2.1.2 

B.2.1.2 

Existing Consistent with 

Exceptions 

XI.M2, “Water 

Chemistry” 

3.0.3.2.1 

Reactor Head Closure 

Studs 

A.2.1.3 

B.2.1.3 

Existing Consistent XI.M3, “Reactor Head 

Closure Studs” 

3.0.3.1.2 

BWR Vessel ID 

Attachment Welds 

A.2.1.4 

B.2.1.4 

Existing Consistent XI.M4, “BWR Vessel 

ID Attachment Welds” 

3.0.3.1.3 

BWR Feedwater Nozzle A.2.1.5 

B.2.1.5 

Existing Consistent XI.M5, “BWR 

Feedwater Nozzle” 

3.0.3.1.4 

BWR Control Rod Drive 

Return Line Nozzle 

A.2.1.6 

B.2.1.6 

Existing Consistent XI.M6, “BWR Control 

Rod Drive Return 

Line Nozzle” 

3.0.3.1.5 

BWR Stress Corrosion 

Cracking 

A.2.1.7 

B.2.1.7 

Existing Consistent with 

Enhancement 

XI.M7, “BWR Stress 

Corrosion Cracking” 

3.0.3.2.2 

BWR Penetrations A.2.1.8 

B.2.1.8 

Existing Consistent XI.M8, “BWR 

Penetrations” 

3.0.3.1.6 

BWR Vessel Internals A.2.1.9 

B.2.1.9 

Existing Consistent XI.M9, “BWR Vessel 

Internals” 

3.0.3.1.7 

Thermal Aging and 

Neutron Irradiation 

Embrittlement of Cast 

Austenitic Stainless 

Steel (CASS) 

A.2.1.10 

B.2.1.10 

New Consistent XI.M13, “Thermal 

Aging and Neutron 

Irradiation 

Embrittlement of Cast 

Austenitic Stainless 

Steel (CASS)” 

3.0.3.1.8 

Flow Accelerated 

Corrosion Program 

A.2.1.11 

B.2.1.11 

Existing Consistent with 

Exception 

XI.M17, “Flow 

Accelerated 

Corrosion” 

3.0.3.2.3 

Bolting Integrity 

Program 

A.2.1.12 

B.2.1.12 

Existing Consistent with 

Exception and 

Enhancement 

XI.M18, “Bolting 

Integrity” 

3.0.3.2.4 

Open-Cycle Cooling 

Water Program 

A.2.1.13 

B.2.1.13 

Existing Consistent XI.M20, “Open-Cycle 

Cooling Water 

System” 

3.0.3.1.9 

Closed-Cycle Cooling 

Water Program 

A.2.1.14 

B.2.1.14 

Existing Consistent with 

Exception and 

Enhancements 

XI.M21, 

“Closed-Cycle 

Cooling Water 

System” 

3.0.3.2.5 
Aging Management Review Results 

 3-8 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL 

Report 

GALL Report Aging 

Management 

Programs 

SER 

Section 

Inspection of Overhead 

Heavy Load and Light 

Load (Related to 

Refueling) Handling 

Systems 

A.2.1.15 

B.2.1.15 

Existing Consistent with 

Enhancements 

XI.M23, “Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to Refueling) 

Handling Systems” 

3.0.3.2.6 

Compressed Air 

Monitoring Program 

A.2.1.16 

B.2.1.16 

Existing Consistent XI.M24, “Compressed 

Air Monitoring” 

3.0.3.1.10 

Fire Protection Program A.2.1.17 

B.2.1.17 

Existing Consistent with 

Exception and 

Enhancements 

XI.M26, “Fire 

Protection” 

3.0.3.2.7 

Fire Water System A.2.1.18 

B.2.1.18 

Existing Consistent with 

Enhancements 

XI.M27, “Fire Water 

System” 

3.0.3.2.8 

Aboveground Steel 

Tanks 

A.2.1.19 

B.2.1.19 

Existing Consistent with 

Enhancements 

XI.M29, 

“Aboveground Steel 

Tanks” 

3.0.3.2.9 

Fuel Oil Chemistry A.2.1.20 

B.2.1.20 

Existing Consistent with 

Exceptions and 

Enhancements 

XI.M30, “Fuel Oil 

Chemistry” 

3.0.3.2.10 

Reactor Vessel 

Surveillance 

A.2.1.21 

B.2.1.21 

Existing Consistent with 

Enhancements 

XI.M31, “Reactor 

Vessel Surveillance” 

3.0.3.2.11 

One-Time Inspection 

Program 

A.2.1.22 

B.2.1.22 

New Consistent XI.M32, “One-Time 

Inspection” 

3.0.3.1.11 

Selective Leaching of 

Materials 

A.2.1.23 

B.2.1.23 

New Consistent XI.M33, “Selective 

Leaching of 

Materials” 

3.0.3.1.12 

Buried Piping 

Inspection 

A.2.1.24 

B.2.1.24 

Existing Consistent with 

Enhancement 

XI.M34, “Buried 

Piping and Tanks 

Inspection” 

3.0.3.2.12 

External Surfaces 

Monitoring 

A.2.1.25 

B.2.1.25 

New Consistent XI.M36, “External 

Surfaces Monitoring” 

3.0.3.1.13 

Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components 

A.2.1.26 

B.2.1.26 

New Consistent XI.M38, “Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components” 

3.0.3.1.14 

Lubricating Oil Analysis A.2.1.27 

B.2.1.27 

Existing Consistent with 

Exception 

XI.M39, “Lubricating 

Oil Analysis” 

3.0.3.2.13 

ASME Section XI, 

Subsection IWE 

A.2.1.28 

B.2.1.28 

Existing Consistent with 

Enhancements 

XI.S1, “ASME Section 

XI, Subsection IWE” 

3.0.3.2.14 

ASME Section XI, 

Subsection IWF 

A.2.1.29 

B.2.1.29 

Existing Consistent XI.S3, “ASME Section 

XI, Subsection IWF” 

3.0.3.1.15 

10 CFR 50, Appendix J A.2.1.30 

B.2.1.30 

Existing Consistent XI.S4, “10 CFR 50 

Appendix J” 

3.0.3.1.16 

Masonry Wall Program A.2.1.31 

B.2.1.31 

Existing Consistent with 

Enhancements 

XI.S5, “Masonry Wall 

Program” 

3.0.3.2.15 
Aging Management Review Results 

 3-9 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL 

Report 

GALL Report Aging 

Management 

Programs 

SER 

Section 

Structures Monitoring 

Program 

A.2.1.32 

B.2.1.32 

Existing Consistent with 

Enhancements 

XI.S6, “Structures 

Monitoring Program” 

3.0.3.2.16 

RG 1.127, “Inspection 

of Water-Control 

Structures Associated 

with Nuclear Power 

Plants” 

A.2.1.33 

B.2.1.33 

Existing Consistent with 

Enhancements 

XI.S7, RG 1.127, 

“Inspection of 

Water-Control 

Structures Associated 

with Nuclear Power 

Plants” 

3.0.3.2.17 

Protective Coating 

Monitoring and 

Maintenance Program 

A.2.1.34 

B.2.1.34 

Existing Consistent XI.S8, “Protective 

Coating Monitoring 

and Maintenance 

Program” 

3.0.3.1.17 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements 

A.2.1.35 

B.2.1.35 

New Consistent XI.E1, “Electrical 

Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements” 

3.0.3.1.18 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits 

A.2.1.36 

B.2.1.36 

New Consistent XI.E2, “Electrical 

Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used 

in Instrumentation 

Circuits” 

3.0.3.1.19 

Inaccessible Medium 

Voltage Cables Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements 

A.2.1.37 

B.2.1.37 

New Consistent XI.E3, “Inaccessible 

Medium-Voltage 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements” 

3.0.3.1.20 

Metal Enclosed Bus A.2.1.38 

B.2.1.38 

New Consistent XI.E4, “Metal 

Enclosed Bus” 

3.0.3.1.21 

Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements 

A.2.1.39 

B.2.1.39 

New Consistent with 

Exception 

XI.E6, “Electrical 

Cable Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements” 

3.0.3.2.18 

Metal Fatigue of 

Reactor Coolant 

Pressure Boundary 

A.3.1.1 

B.3.1.1 

Existing Consistent with 

Enhancements 

X.M1, “Metal Fatigue 

of Reactor Coolant 

Pressure Boundary” 

3.0.3.2.19 
Aging Management Review Results 

 3-10 

Applicant Aging 

Management Program 

LRA 

Sections 

New or 

Existing 

Program 

Applicant 

Comparison to 

the GALL 

Report 

GALL Report Aging 

Management 

Programs 

SER 

Section 

Environmental 

Qualification (EQ) of 

Electrical Components 

A.3.1.2 

B.3.1.2 

Existing Consistent X.E1, “Environmental 

Qualification (EQ) of 

Electric Components” 

3.0.3.1.22 

High Voltage Insulators A.2.2.1 

B.2.2.1 

New Plant-specific N/A 

(HCGS High Voltage 

Insulators Program) 

3.0.3.3.1 

Periodic Inspection A.2.2.2 

B.2.2.2 

New Plant-specific N/A 

(HCGS Periodic 

Inspection Program) 

3.0.3.3.2 

Aboveground Non-Steel 

Tanks 

A.2.2.3 

B.2.2.3 

New Plant-specific N/A 

(HCGS Aboveground 

Non-Steel Tanks 

Program) 

3.0.3.3.3 

Buried Non-Steel Piping 

Inspection 

A.2.2.4 

B.2.2.4 

Existing Plant-specific N/A 

(HCGS Buried 

Non-Steel Piping 

Inspection Program) 

3.0.3.3.4 

Boral Monitoring 

Program 

A.2.2.5 

B.2.2.5 

Existing Plant-specific N/A 

(HCGS Boral 

Monitoring Program) 

3.0.3.3.5 

Small-Bore Class 1 

Piping Inspection 

A.2.2.6 

B.2.2.6 

New Plant-specific N/A 

(HCGS Small-Bore 

Class 1 Piping 

Inspection Program) 

3.0.3.3.6 

3.0.3.1 AMPs That Are Consistent with the GALL Report 

In LRA Appendix B, the applicant identified the following AMPs as being consistent with the 

GALL Report: 

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

● Rector Head Closure Studs 

● BWR Vessel ID Attachment Welds 

● BWR Feedwater Nozzle 

● BWR Control Rod Drive Return Line Nozzle 

● BWR Penetrations 

● BWR Vessel Internals 

● Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel 

(CASS) 
Aging Management Review Results 

 3-11 

● Open-Cycle Cooling Water System 

● Compressed Air Monitoring 

● One-Time Inspection 

● Selective Leaching of Materials 

● External Surfaces Monitoring 

● Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

● ASME Section XI, Subsection IWF 

● 10 CFR Part 50, Appendix J 

● Protective Coating Monitoring and Maintenance Program 

● Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

● Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits 

● Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

● Metal Enclosed Bus 

● Environmental Qualification (EQ) of Electric Components 

3.0.3.1.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Summary of Technical Information in the Application. LRA Section B.2.1.1 describes the 

existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as 

consistent with GALL AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD.” The applicant stated that the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program includes inspections performed to manage cracking, 

loss of fracture toughness, and loss of material in Classes 1, 2, and 3 piping and components 

exposed to reactor coolant, steam, and treated water environments within the scope of license 

renewal. The applicant stated that the program provides for periodic visual, surface, and 

volumetric examination and for leakage testing of pressure retaining piping and components 

including welds, pump casings, valve bodies, integral attachments, and pressure retaining 

bolting and that the program consists of condition monitoring activities that detect degradation of 

components before loss of intended function. 

The applicant stated that its current ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program is based on the 2001 Edition through the 2003 Addenda of ASME Code 

Section XI and that its program is updated each successive 120-month inspection interval to 

comply with the requirements of the latest edition of the ASME Code, as specified in 

10 CFR 50.55a, 12 months before the start of the inspection interval. 
Aging Management Review Results 

 3-12 

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 whether 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 with the corresponding 

elements of GALL 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 

AMP XI.M1, with the exception of the “detection of aging effects” program element. For this 

element, the staff determined that additional clarification was needed, which resulted in the 

issuance of a request for additional information (RAI). 

The staff noted that the applicant is currently in its third, 10-year inservice inspection (ISI) 

interval and that the current ISI interval does not continue into the period of extended operation. 

The staff also noted that during the current interval, the applicant’s ISI program includes a 

risk-informed inservice inspection (RI-ISI) methodology that has been approved for the current 

interval in accordance with the requirements of 10 CFR 50.55a. The staff further noted that in 

LRA Section B.2.1.1 the applicant stated that its ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program uses an alternative method to determine the 

inspection locations, inspection frequency, and inspection techniques for Class 1 Categories 

B-F and B-J, and Class 2 Categories C-F-1 and C-F-2 welds. It was not clear to the staff 

whether the discussion of alternative inspection methods in the LRA is applicable only to the 

current inspection interval or whether the discussion also applies to the period of extended 

operation. By letter dated May 14, 2010, the staff issued RAI B.2.1.1-01 requesting that the 

applicant explain why RI-ISI and other alternatives to the requirements of ASME Code Section 

XI, Subsections IWB, IWC, and IWD are discussed in the LRA’s program description for the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. 

In its response dated June 14, 2010, the applicant stated that RI-ISI and other alternatives to 

the ASME Code Section XI requirements were discussed in the LRA because they are 

contained in the applicant’s existing ISI Program Plan for the third 10-year inspection interval, 

which was used to evaluate the ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program against the recommendations in GALL AMP XI.M1. The applicant stated that 

it recognizes that the license renewal process does not review and approve future plant ISI 

program plans, including RI-ISI and other alternatives to the ASME Code Section XI 

requirements. The applicant further stated that at the end of the current 10-year ISI interval, it 

will be required to submit an update to its ISI Program Plan for staff review in accordance with 

the requirements of 10 CFR 50.55a. 

Based on its review, the staff finds the applicant’s response to RAI B.2.1.1-01 acceptable 

because it clarifies that the staff’s current approval for the use of RI-ISI and other alternatives to 

ASME Code Section XI requirements is valid only for the current 10-year ISI interval, and it 

confirms that at the end of the current 10-year ISI interval, the applicant will submit an update to 

its ISI Program Plan for staff review in accordance with the requirements of 10 CFR 50.55a. 

The staff’s concern as described in RAI B.2.1.1-01 is resolved. 

Based on its audit and review of the applicant’s response to RAI B.2.1.1-01, the staff finds that 

elements one through six of the applicant’s ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD Program are consistent with the corresponding program elements of GALL 

AMP XI.M1 and, therefore, acceptable. 
Aging Management Review Results 

 3-13 

Operating Experience. LRA Section B.2.1.1 summarizes operating experience related to the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The 

applicant described detection of an axially oriented flaw indication on a reactor recirculation inlet 

nozzle to safe end weld during the 2004 refueling outage and of a circumferentially oriented flaw 

indication on a different reactor recirculation nozzle to safe end weld during the 2007 refueling 

outage. For both occurrences, the applicant stated that the characteristics of the flaw were 

determined, documented, entered into the site’s corrective action program, and evaluated both 

for apparent cause and for determination and implementation of appropriate corrective actions. 

The applicant stated that these examples demonstrate that the program provides appropriate 

guidance for inspection and evaluation, deficiencies are entered into the corrective action 

program, and effective corrective actions, including expansion of inspection scope due to 

observed conditions, are implemented. 

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 found no 

operating experience to indicate that the applicant’s program would not be effective in 

adequately managing 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. LRA Section A.2.1.1 provides the UFSAR supplement for the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The staff reviewed 

this UFSAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program as described in SRP-LR Table 3.1-2. The 

staff also notes that the applicant committed (Commitment No. 1) to ongoing implementation of 

the existing ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program 

for managing aging of applicable components during 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 review of the applicant’s ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program, the staff finds all program elements consistent with 

the GALL Report. The staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 
Aging Management Review Results 

 3-14 

3.0.3.1.2 Reactor Head Closure Studs 

Summary of Technical Information in the Application. LRA Section B.2.1.3 describes the 

existing Reactor Head Closure Studs Program as consistent with GALL AMP XI.M3, “Reactor 

Head Closure Studs.” The applicant stated that the program provides for ASME Section XI 

inspections of reactor head closure studs, nuts, and washers for cracking due to 

stress-corrosion cracking (SCC) or intergranular stress-corrosion cracking (IGSCC), loss of 

material due to wear, and coolant leakage from reactor vessel closure stud bolting. The 

applicant stated that the Reactor Head Closure Studs Program is a condition-based monitoring 

program that effectively monitors and detects the applicable aging effects and that the 

frequency of monitoring is adequate to prevent significant degradation. The applicant further 

stated that the program is based on examination and inspection requirements specified in the 

1998 ASME Code Section XI, including the 2000 addenda, and preventive measures described 

in NRC Regulatory Guide (RG) 1.65, “Materials and Inspection for Reactor Vessel Closure 

Studs.” The applicant also stated that the program uses visual and volumetric examinations in 

accordance with ASME Code Section XI, the applicable edition of the ASME Code does not 

require surface examinations of the studs, and surface examinations of the reactor head closure 

studs are not performed. The applicant stated that the extent and schedule for examining and 

testing the reactor head closure studs, nuts, and washers are as specified in ASME Code 

Section XI, Table IWB-2500-1 for Examination Category B-G-1 components, “Pressure 

Retaining Bolting Greater than 2 Inches in Diameter.” 

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 whether 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 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 

AMP XI.M3, with the exception of the “detection of aging effects” program element. For this 

program element, the staff determined the need for additional clarification, which resulted in the 

issuance of an RAI. 

In GALL AMP XI.M3, the “detection of aging effects” program element states that Examination 

Category B-G-1 for pressure retaining bolting greater than 2 inches in diameter in reactor 

vessels specifies surface and volumetric examination of studs when they are removed from the 

reactor vessel flange. In its review of the applicant’s “detection of aging effects” program 

element, the staff noted that the applicant performs volumetric (not volumetric and surface) 

examination of reactor head closure studs when they are removed from the reactor vessel 

flange. The staff also noted that in the program description subsection of LRA Section B.2.1.3, 

the applicant stated that the Reactor Head Closure Studs Program is based on the examination 

and inspection requirements specified in the 1998 ASME Section XI Boiler and Pressure Vessel 

(B&PV) Code, Subsection IWB, including the 2000 addenda. However, the staff also noted that 

this statement conflicts with other statements in the LRA (e.g., LRA Section B.2.1.1), which 

indicate that the applicant’s current ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program is based on the 2001 Edition, with 2002 and 2003 Addenda, of ASME 

Code Section XI. 

By letter dated May 14, 2010, the staff issued RAI B.2.1.3-01 requesting that the applicant 

explain why implementation of only volumetric examinations, rather than volumetric and surface 

examinations, for removed closure studs was not identified as an exception to the 
Aging Management Review Results 

 3-15 

recommendations in the GALL Report and justify how the use of only volumetric inspections for 

these components will provide adequate detection of aging effects during the period of extended 

operation. The staff also requested that the applicant clarify which edition and addenda of 

ASME Code Section XI provide the basis for the applicant’s Reactor Head Closure Studs 

Program. 

In its response dated June 14, 2010, the applicant stated that the ASME Code Section XI 

edition applicable to its current ISI program is the 2001 Edition through 2003 Addenda and that 

this edition is also applicable to the Reactor Head Closure Studs Program. The applicant 

further stated that the 1998 Edition of the ASME Code was inadvertently referenced in the 

Reactor Head Closure Studs Program description in LRA Appendix B. The applicant stated that 

an exception to the surface examination of the reactor vessel studs described in the “detection 

of aging effects” program element of GALL AMP XI.M3 was not identified because the program 

description of GALL AMP XI.M3 states that the ISI requirements are in conformance with the 

2001 Edition of the ASME Code Section XI. The applicant also stated that the 2001 Edition of 

the ASME Code Section XI does not require surface examination of the reactor head closure 

studs, in place or removed. The applicant further stated that a volumetric examination (only) of 

the reactor head closure studs is adequate because the 2001 Edition of the ASME Code 

including the 2003 addenda, in Table IWB-2500-1, Category B-G-1, Item No. B6.20, specifies 

volumetric examination. In its response, the applicant also stated that its examination in the 

program is consistent both with the requirements of the applicable ASME Code Section XI and 

with alternate inspection requirements described in RG 1.65, “Materials and Inspection for 

Reactor Vessel Closure Studs,” Revision 1, dated April 2010. 

Based on its review, the staff finds the applicant’s response to RAI B.2.1.3-01 acceptable 

because: (1) the applicant’s clarification resolved the conflict noted in the LRA and the ASME 

Code edition and addenda used by the applicant, which is consistent with the recommendations 

in the GALL Report, and (2) surface examinations, in addition to volumetric examinations, are 

not required by the applicable edition and addenda of the ASME Code, and volumetric 

examinations, alone, have been found adequate to detect the aging effect of interest as 

documented in the latest revision of RG 1.65. The staff’s concern described in RAI B.2.1.3-01 

is, therefore, resolved. 

Based on its audit and review of the applicant’s response to RAI B.2.1.3-01, the staff finds that 

elements one through six of the applicant’s Reactor Head Closure Studs Program are 

consistent with the corresponding program elements of GALL AMP XI.M3 and, therefore, 

acceptable. 

Operating Experience. LRA Section B.2.1.3 summarizes operating experience related to the 

Reactor Head Closure Studs Program. The applicant cited the following examples of operating 

experience. The applicant stated that during the 1995 extended outage (RFO6), all reactor 

head closure studs and nuts were examined by the ultrasonic testing (UT) method, and during 

the 1994 refueling outage (RFO5), all reactor head closure studs and nuts were examined by 

the fluorescent magnetic particle method and all closure washers were examined by the visual 

testing (VT-1) method. The applicant stated that results of these examinations were all 

acceptable. The applicant also stated that during the spring 2006 refueling outage (RFO13), all 

reactor head closure studs were examined by the UT method, and all reactor head closure 

studs, nuts, and washers were examined by the VT-1 method. The applicant stated that one 

closure nut (number 66) exhibited gouge marks on the outside of the top surface of the nut and 

that this condition was identified, documented, and evaluated as acceptable in the corrective 

action program. The applicant further stated that no other recordable indications were identified 
Aging Management Review Results 

 3-16 

in the inspection. The applicant stated that these examples demonstrate that the Reactor Head 

Closure Studs Program is effective in assuring that intended function(s) will be maintained 

consistent with the CLB for the period of extended operation. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant and are evaluated in the GALL Report. As 

discussed in the Audit Report, the staff conducted an independent search of the plant-specific 

operating experience information to determine whether the applicant had 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 of SRP-LR Section A.1.2.3.10 

and, 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 notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed 

(Commitment No. 3) to ongoing implementation of the existing Reactor Head Closure Studs 

Program for managing aging of applicable components during 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 review of the applicant’s Reactor Head Closure Studs Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.3 BWR Vessel ID Attachment Welds 

Summary of Technical Information in the Application. LRA Section B.2.1.4 describes the 

existing BWR Vessel ID Attachment Welds Program as consistent with GALL AMP XI.M4, 

“BWR Vessel ID Attachment Welds.” The applicant stated that this program manages the 

effects of cracking of reactor vessel internal attachment welds exposed to reactor coolant 

through water chemistry and ASME Section XI Inservice Inspection. The applicant further 

stated that this program incorporates the inspection and evaluation recommendations of Boiling 

Water Reactor Vessel and Internals Project (BWRVIP)-48-A, as well as the water chemistry 

recommendations of BWRVIP-130. The applicant stated the scope of the programs includes 

the steam dryer support and hold down brackets, guide rod wall bracket, feedwater sparger 

bracket, jet pump riser braces, core spray piping brackets, and surveillance sample holder 

brackets. The applicant stated that SCC and IGSCC are managed by the detection and sizing 
Aging Management Review Results 

 3-17 

of cracks by ISI in accordance with the guidelines of NRC-approved BWRVIP-48-A and the 

requirements of the ASME Code Section XI, Table IWB-2500-1. 

The applicant stated the jet pump riser brace and core spray piping bracket attachment welds 

are inspected in accordance with the frequency and methods described in BWRVIP-48-A. The 

dryer support bracket and feedwater sparger bracket attachment welds are inspected using 

enhanced visual testing (EVT)-1 techniques while maintaining the inspection frequency per 

ASME Section XI Examination Category for B-N-2 components. The applicant further stated the 

remaining attachment welds are inspected in accordance with ASME Code Section XI, Table 

IWB 2500-1. 

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 whether they are 

bounded by the conditions for which the GALL Report was evaluated. The staff also conducted 

onsite interviews with the applicant to confirm these results. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL AMP XI.M4. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M4. 

The staff noted that the applicant’s BWR Vessel ID Attachment Welds Program is based on the 

augmented inspection and flaw evaluation guideline criteria in BWRVIP-48-A. In the safety 

evaluation (SE) on Topical Report BWRVIP-48-A, the staff issued three renewal applicant action 

items for BWR applicants crediting BWRVIP-48-A for aging management of reactor vessel 

inside diameter (ID) attachment welds. The applicant provided the staff’s renewal applicant 

action item descriptions and its responses to action items in LRA Appendix C, BWRVIP-All. The 

three action items follow: 

 (1) The staff’s first renewal applicant action item required that applicants identify those 

guideline criteria aspects in BWRVIP-48-A that they might deviate from. The staff noted 

that the applicant would not deviate from the recommended inspection and flaw 

evaluation criteria provided in BWRVIP-48-A and, thus, determined that the applicant 

adequately addressed the staff’s action item. 

 Based on this review, the staff concludes that the applicant has adequately addressed 

the staff’s first renewal applicant action item on BWRVIP-48-A. Therefore, this renewal 

applicant action item is resolved. 

 (2) The staff’s second renewal applicant action item required that BWR applicants provide a 

UFSAR supplement summary description of the AMP based on the BWRVIP-48-A 

recommended criteria. The applicant stated that LRA Appendix A includes the UFSAR 

supplement for the BWR Vessel ID Attachment Welds Program. The staff confirmed 

that the applicant has provided its UFSAR supplement summary description for the BWR 

Vessel ID Attachment Welds Program in LRA Section A.1.2.9. The staff’s evaluation of 

the applicant’s UFSAR supplement for this program follows later in this evaluation. 

 Based on this review, the staff concludes that the applicant has adequately addressed 

the staff’s second renewal applicant action item on BWRVIP-48-A. Therefore, this 

renewal applicant action item is resolved. 
Aging Management Review Results 

 3-18 

 (3) The staff’s third renewal applicant action item required that BWR applicants ensure that 

the inspection criteria in BWRVIP-48-A will not conflict with, or result in, changes to the 

plant’s technical specifications (TSs). The applicant stated that its implementation of the 

inspection strategy in BWRVIP-48-A will not result in the need for any changes to the TS 

for HCGS. The staff reviewed the TSs for HCGS and confirms that, while the methods 

in BWRVIP-48-A may constitute alternative staff-approved inspection guidelines for the 

ASME Code Class 1 reactor vessel ID attachment welds, the TSs for HCGS do not 

include any requirements to implement the ASME Code Section XI, ISI Program 

requirements for the facility. The staff also confirms that the applicant’s TSs center on 

operational-based, surveillance-based, and administrative control-based TS 

requirements and that the ISI Program and requirements are implemented through the 

applicant’s ASME Code Section XI, ISI Program, pursuant to 10 CFR 50.55a. Thus, 

based on this review, the staff concludes that the applicant has provided an adequate 

basis for concluding that its implementation of the guidelines in BWRVIP-48-A will not 

conflict with or result in any necessary changes in the TSs. 

Based on this review, the staff concludes that the applicant has adequately addressed the 

staff’s third renewal applicant action item on BWRVIP-48-A. Therefore, this renewal applicant 

action item is resolved. 

Based on its audit, the staff finds that elements one through six of the applicant’s BWR Vessel 

ID Attachment Welds Program are consistent with the corresponding program elements of 

GALL AMP XI.M4 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.4 also summarizes operating experience related to 

the BWR Vessel ID Attachment Welds Program. The staff noted that the applicant provided an 

overall operating experience summary statement in the “operating experience” program element 

for the BWR Vessel ID Attachment Weld Program and three examples of HCGS-specific 

operating experience demonstrating that the AMP accomplishes its intended objective. The 

staff confirmed that, in the visual inspections (EVT-1, VT-1, VT-3, as applicable) of these welds 

that have been performed since the plant has been in operation, the HCGS inspections have 

not detected any cracks in the vessel ID attachment welds. Other, similar BWRVIP-related 

inspections have found cracks in the core shroud welds and setscrew tack welds. These 

examples demonstrate that appropriate corrective actions are taken through the corrective 

action program when deficiencies are found, including actions to determine the cause and 

extent of the condition. 

Based on this review, the staff confirmed that the applicant has been implementing the 

inspections of its reactor vessel ID attachment welds in accordance with the requirements of 

ASME Code Section XI, as well as those from BWRVIP-48-A. The staff finds that the 

applicant’s inspection records provide acceptable confirmation that there is no plant-specific 

operating experience for the reactor vessel ID attachment welds to date. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant 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 found no 
Aging Management Review Results 

 3-19 

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. LRA Section A.2.1.4 provides the UFSAR supplement for the BWR 

Vessel ID Attachment Welds Program. The staff reviewed this UFSAR supplement description 

of the program and notes that it conforms to the recommended description for this type of 

program as described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed 

(Commitment No. 4) to ongoing implementation of the existing BWR Vessel ID Attachment 

Welds Program for managing the aging effects of applicable components during 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 BWR Vessel ID Attachment 

Welds Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.4 BWR Feedwater Nozzle 

Summary of Technical Information in the Application. LRA Section B.2.1.5 describes the 

existing BWR Feedwater Nozzle Program as consistent with GALL AMP XI.M5, “BWR 

Feedwater Nozzle.” The applicant stated that this program includes enhanced ISI pursuant to 

ASME Code Section XI, Subsection IWB, Table IWB 2500-1 and the recommendations of report 

GE-NE-523-A71-0594 and system modifications, performed prior to being put into service, that 

mitigate cracking. 

The applicant stated the program provides for the monitoring of feedwater nozzles for cracking 

in accordance with the requirements of the ASME Code Section XI, Subsection IWB, Table 

IWB-2500-1 and recommendations of GE-NE-523-A71-0594-A, Revision 1. The applicant 

further stated the program is implemented through the plant ISI program and specifies periodic 

ultrasonic (UT) inspections of critical regions of the feedwater nozzle that are performed at 

intervals not exceeding 10 years. 

The applicant further stated that, in response to NUREG-0619, design changes were made to 

the feedwater nozzles prior to initial plant operation to mitigate or prevent thermally-induced 

fatigue cracking, which included eliminating the cladding on nozzle inner diameter and the use 

of a triple sleeve feedwater sparger design. The applicant further stated that mitigation of 

cracking in the feedwater nozzle is also accomplished through the use of a feedwater level 

control system that uses a startup level control valve for low power operation to decrease flow 
Aging Management Review Results 

 3-20 

fluctuations, and the reactor water cleanup (RWCU) return flow is injected in both feedwater 

loops. 

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 whether they are 

bounded by the conditions for which the GALL Report was evaluated. The staff conducted 

onsite interviews with the applicant to confirm these results. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL AMP XI.M5. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M5. Based on its 

audit, the staff finds that the applicant’s BWR Feedwater Nozzle Program are consistent with 

the corresponding program elements of GALL AMP XI.M5 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.5 also summarizes operating experience related to 

the applicant’s BWR Feedwater Nozzle Program. 

The applicant stated that review of the industry operating experience, as summarized in 

NUREG-0619, reveals that several BWR plants have experienced cracking in the feedwater 

nozzles and connecting feedwater spargers. The applicant further stated that NUREG-0619 

provided several recommendations for inspections and design improvements. The applicant 

further stated that, it started operation in 1986 with the important design features 

recommendations in NUREG-0619 incorporated into the plant’s design, including eliminating the 

cladding on nozzle inner diameter and the use of a low leakage triple sleeve feedwater sparger. 

The applicant also stated that these design features significantly reduce thermal fatigue and the 

likelihood of cracking in the feedwater nozzles. 

The applicant also stated that the feedwater nozzles have been inspected for cracking as part of 

the Augmented Inspections of the HCGS ISI program in accordance with NUREG-0619 in 1987, 

1992, 1997, and 2004 using UT techniques. The staff reviewed the applicant’s operating 

experience basis document for safety significant operating experience relevant to the aging 

management of feedwater nozzles. The staff noted that the applicant has conducted numerous 

inspections of the feedwater nozzles as part of its ISI program without any recordable 

indications of cracking. 

The applicant also provided two operating experience examples that illustrate how cracking has 

been found in the recirculation system at HCGS. The staff noted that these examples show that 

industry operating experience is used to improve the effectiveness of the inspection process at 

HCGS. The staff also noted that these examples demonstrate that whenever deficiencies are 

found, appropriate corrective actions are taken through the corrective action program, including 

actions to determine the cause and extent of the condition. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant 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 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. 
Aging Management Review Results 

 3-21 

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. LRA Section A.2.1.5 provides the UFSAR supplement for the BWR 

Feedwater Nozzle Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed 

(Commitment No. 5) to ongoing implementation of the existing BWR Feedwater Nozzle Program 

for managing aging of applicable components during 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 review of the applicant’s BWR Feedwater Nozzle Program, the 

staff finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.5 BWR Control Rod Drive Return Line Nozzle 

Summary of Technical Information in the Application. LRA Section B.2.1.6 describes the 

existing BWR Control Rod Drive (CRD) Return Line Nozzle Program as consistent with GALL 

AMP XI.M6, “BWR Control Rod Drive Return Line Nozzle.” The applicant stated that the BWR 

CRD Return Line Nozzle Program monitors the effects of cracking on the intended function of 

the N9 nozzle (originally intended to be used as the CRD return line nozzle) by performing ISIs 

in conformance with the ASME Code Section XI, Subsection IWB, Table IWB 2500-1. To 

mitigate cracking, the applicant capped the CRD return line nozzle prior to going into service in 

1986, deleting the return line as part of the original plant design (as outlined in NUREG-0619). 

The applicant stated that continued inspection of the nozzle as required by NUREG-0619 is not 

applicable. 

The applicant’s ISI includes ultrasonic inspections of the nozzle inside radius section and 

nozzle-to-vessel weld. The applicant stated that future inspections of the inside radius of the N9 

nozzle will be performed using EVT-1 in accordance with NRC-accepted Code case N648-1, 

subject to the conditions specified in RG 1.147. 

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 whether they are 

bounded by the conditions for which the GALL Report was evaluated. The staff conducted 

onsite interviews with the applicant to confirm these results. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL AMP XI.M6. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M6. 
Aging Management Review Results 

 3-22 

The staff noted that the applicant made a major system modification that is outlined in 

NUREG-0619, by capping the CRD return line nozzle. The staff noted that this modification 

adds the nozzle-to-cap weld to the same category as other welds in the HCGS reactor vessel. 

The staff noted that the applicant conducts ultrasonic examinations of the CRD return line 

nozzle-to-cap weld in accordance with the guidelines of staff-approved BWRVIP-75-A as part of 

the BWR Stress Corrosion Cracking Program. The staff further noted that the inspection 

methods used in the program have been proven effective in detecting cracking in reactor 

pressure vessel (RPV) nozzles. 

Based on its audit, the staff finds that elements one through six of the applicant’s BWR CRD 

Return Line Nozzle Program are consistent with the corresponding program elements of GALL 

AMP XI.M6 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.6 also summarizes operating experience related to 

the BWR CRD Return Line Nozzle Program. The applicant stated that review of the current 

operating experience reveals that cracking in the CRD return line nozzle has occurred in several 

BWR plants as delineated in NUREG-0619 and Information Notice (IN) 2004-08, “Reactor 

Coolant Pressure Boundary Leakage Attributable to Propagation of Cracking in Reactor Vessel 

Nozzle Welds.” In response to the concerns described in NUREG-0619, the HCGS design 

eliminated the use of a CRD return line. Furthermore, the N9 nozzle, originally intended to be 

used for the CRD return line, was capped. The applicant believes that these design features 

significantly reduced the susceptibility of the nozzle to cracking associated with thermal fatigue. 

The staff noted that the applicant has conducted numerous UT inspections of the BWR CRD 

return line nozzle as part of its ISI program without any recordable indications of cracking. The 

staff further noted that the most recent exam in 2007 was performed using a Performance 

Demonstration Initiative (PDI)-qualified UT detection technique. 

The inspections that the applicant has conducted had been effective in detecting cracking and 

would have detected cracking if cracking had existed. These flaws or cracking indications are 

found before loss of intended function. As part of the corrective action program, the corrective 

action is to repair the flaw with weld overlay. The applicant also provided two operating 

experience examples that illustrate how flaw or cracking indications have been found in the two 

similar nozzles at HCGS. These two nozzles were actually recirculation inlet nozzle-to-safe end 

welds that were inspected as part of the BWR Feedwater Nozzle Program to meet the 

requirements of Generic Letter (GL) 88-01 and NUREG-0313 for IGSCC. The flaws were 

detected using an automated Performance Demonstration Initiative (PDI)-qualified UT detection 

technique. These indications are typical of the degradation previously observed in the industry 

and described in Section XI.M5 of the GALL Report. These examples show that industry 

operating experience is used to improve the effectiveness of the inspection process at HCGS. 

The staff reviewed the corrective action reports associated with these cracks and inspected the 

two nozzles during the AMP audit. The staff noted that these examples also demonstrate that 

whenever deficiencies are found, appropriate corrective actions are taken through the corrective 

action program, including actions to determine the cause and extent of the condition. The 

applicant further stated that its current ISI activities have been effective in successfully 

identifying unacceptable indications in other vessel nozzles. 

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 
Aging Management Review Results 

 3-23 

experience information to determine whether the applicant had 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 

and, therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A.2.1.6 provides the UFSAR supplement for the BWR CRD 

Return Line Nozzle Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed 

(Commitment No. 6) to ongoing implementation of the existing BWR CRD Return Line Nozzle 

Program for managing aging of applicable components during 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 review of the applicant’s BWR CRD Return Line Nozzle 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.6 BWR Penetrations 

Summary of Technical Information in the Application. LRA Section B.2.1.8 describes the 

existing BWR Penetrations Program as consistent with GALL AMP XI.M8, “BWR Penetrations.” 

The applicant stated that the program manages cracking of reactor vessel instrumentation 

penetrations (nozzles) exposed to reactor coolant by providing for mitigation of cracking through 

control of water chemistry and ISIs. The applicant also stated that the program includes 

inspection and flaw evaluation, pursuant to the guidelines of the staff-approved BWRVIP report 

BWRVIP-49-A, “Instrument Penetration Inspection and Flaw Evaluation Guidelines,” and 

monitoring and control of reactor coolant water chemistry, pursuant to the guidelines of 

BWRVIP-130, “BWR Water Chemistry Guidelines.” The applicant further stated that the scope 

of the program includes beltline instrumentation nozzles and other instrumentation nozzles, 

except for the standby liquid control/core plate differential pressure nozzle and the jet pumps 

instrumentation nozzles, which are in the scope of its ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD 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 whether they are 

bounded by the conditions for which the GALL Report was evaluated. The staff also conducted 

onsite interviews with the applicant to confirm these results. 
Aging Management Review Results 

 3-24 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL AMP XI.M8. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M8. 

The staff noted that the applicant’s BWR Penetrations Program is based on the augmented 

inspection and flaw evaluation guideline criteria in BWRVIP-49-A, which includes three renewal 

applicant action items for BWR applicants crediting BWRVIP-49-A for aging management of 

reactor vessel instrumentation nozzles. The applicant provided the staff’s renewal applicant 

action item descriptions and its responses to action items in LRA Appendix C, BWRVIP-All 

(1)-(3). The staff’s review of the applicant’s three action item responses is as follows: 

 (1) The staff’s first renewal applicant action item required that applicants identify those 

guideline criteria aspects in BWRVIP-49-A that they might deviate from. The staff noted 

that the applicant would not deviate from the recommended inspection and flaw 

evaluation criteria provided in BWRVIP-49-A and; thus, determined that the applicant 

adequately addressed the staff’s action item. Based on this review, the staff concludes 

that the applicant has adequately addressed the staff’s first renewal applicant action item 

on BWRVIP-49-A. Therefore, this renewal applicant action item is resolved. 

 (2) The staff’s second renewal applicant action item required that BWR applicants provide a 

UFSAR supplement summary description of the AMP based on the BWRVIP-49-A 

recommended criteria. The applicant stated that LRA Appendix A includes the UFSAR 

supplement for the BWR Penetrations Program. The staff confirmed that the applicant 

has provided its UFSAR supplement summary description for the BWR Penetrations 

Program in LRA Section A.2.1.8. The staff’s evaluation of the applicant’s UFSAR 

supplement for this program follows later in this evaluation. Based on this review, the 

staff concludes that the applicant has adequately addressed the staff’s second renewal 

applicant action item on BWRVIP-49-A. Therefore, this renewal applicant action item is 

resolved. 

 (3) The staff’s third renewal applicant action item required that BWR applicants ensure that 

the inspection criteria in BWRVIP-49-A will not conflict with or result in changes to the 

plant’s TSs. The applicant stated that its implementation of the inspection strategy in 

BWRVIP-49-A will not result in the need for any changes to the TSs for HCGS. The staff 

reviewed the TSs for HCGS and confirmed that, while the methods in BWRVIP-49-A 

may constitute alternative staff-approved inspection guidelines for the reactor vessel 

instrumentation nozzles, the TSs for HCGS do not include any requirements to 

implement the ASME Code Section XI, ISI Program requirements for the facility. The 

staff also confirmed that the applicant’s TSs center on operational-based, 

surveillance-based, and administrative control-based TS requirements and that the ISI 

program and requirements are implemented through the applicant’s ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program, pursuant to 

10 CFR 50.55a. Thus, based on this review, the staff concludes that the applicant has 

provided an adequate basis for concluding that its implementation of the guidelines in 

BWRVIP-49-A will not conflict with or result in any necessary changes in the TSs. 

Based on this review, the staff concludes that the applicant has adequately addressed 

the staff’s third renewal applicant action item on BWRVIP-49-A. Therefore, this renewal 

applicant action item is resolved. 
Aging Management Review Results 

 3-25 

Based on its audit, the staff finds that elements one through six of the applicant’s BWR 

Penetrations Program are consistent with the corresponding program elements of GALL 

AMP XI.M8 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.8 also summarizes operating experience related to 

the applicant’s BWR Penetrations Program. The applicant stated that its inspection 

requirements for reactor vessel instrumentation penetrations are implemented as part of the 

vessel ASME Code Section XI ISI activities, which is consistent with the recommendations of 

BWRVIP-49-A. The applicant also stated that as required by ASME Code Section XI, at each 

refueling, a reactor coolant boundary leakage is performed as part of the ISI program. The 

applicant stated that a VT-2 test by qualified personnel is performed for all reactor coolant 

pressure retaining components, including the reactor vessel instrument penetrations, within the 

scope of this program. The applicant further stated that throughout the operating life of the 

plant, no leaks have been found in the penetrations managed by this program. The applicant 

stated that a review of the inspection results did not reveal a case in which a VT-2 inspection 

found cracking in a Class 1 component. 

However, the staff noted that the required VT-2 inspections have detected leaks at mechanical 

interfaces such as flanges and valve packing. The staff further noted that in each case, the 

discrepancy is entered into the corrective action program and appropriate action, such as repair, 

is taken. The staff noted that this example demonstrates that the inspection techniques and 

qualified personnel are capable of detecting small leaks in Class 1 components and 

demonstrates that the inspection techniques used in the BWR Penetrations Program is capable 

of detecting leaks before a loss of intended function. 

Based on this review, the staff confirmed that the applicant has been implementing the 

inspections of its reactor vessel instrument nozzles in accordance with the requirements of 

ASME Code Section XI, as well as those from BWRVIP-49-A. The staff finds that the 

applicant’s inspection records provide acceptable confirmation that there is no plant-specific 

operating experience for the reactor vessel instrument nozzles to date. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant 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 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. LRA Section A.2.1.8 provides the UFSAR supplement for the BWR 

Penetrations Program. The staff reviewed this UFSAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed 
Aging Management Review Results 

 3-26 

(Commitment No. 8) to ongoing implementation of the existing BWR Penetrations Program for 

managing aging of applicable components during 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 the audit and review of the applicant’s BWR Penetrations Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.7 BWR Vessel Internals 

Summary of Technical Information in the Application. LRA Section B.2.1.9 describes the 

existing BWR Vessel Internals Program as consistent with GALL AMP XI.M9, “BWR Vessel 

Internals.” The applicant included Appendix C, “Response to BWRVIP Application Action 

Items,” which addresses the staff’s license renewal action items for various BWRVIP reports. 

The applicant stated that this program includes inspection, flaw evaluation, and repair guidelines 

that are consistent with the guidelines addressed in relevant BWRVIP reports. The applicant 

further stated that water chemistry guidelines per the BWRVIP-130 report, “BWR Water 

Chemistry Guidelines,” will be complied with to ensure the integrity of the reactor vessel 

internals (RVIs) components. 

The applicant provided information with respect to plant operating experience in which it stated 

that inspections were performed on core shroud, core plate, shroud support, low-pressure 

coolant injection (LPCI) coupling, core spray, jet pumps, top guide, CRD housings, lower 

plenum, steam dryer, and access hole covers. The applicant further stated that it evaluated the 

indications that were found thus far in these RVI components and accepted them per the 

applicable BWRVIP inspection guidelines. The applicant reiterated that it complied with the 

inspections and flaw evaluation guidelines specified in the applicable BWRVIP reports and it 

would continue to implement these guidelines to ensure the structural integrity and functionality 

of these components during the extended period of operation. 

Appendix C lists the following BWRVIP reports which would be implemented by the applicant 

during the period of extended operation: 

● BWRVIP-18-A, “BWR Core Spray Inspection and Flaw Guidelines” 

● BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines” 

● BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines” 

● BWRVIP-38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines” 

● BWRVIP 41, “BWR Vessel and Internals Project, Jet Pump Assembly, Inspection and 

Flaw Evaluation” 
Aging Management Review Results 

 3-27 

● BWRVIP 42-A, “BWR LPCI Coupling Inspection and Flaw Evaluation Guidelines” 

● BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines” 

● BWRVIP-48-A, “Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines” 

● BWRVIP-49-A, “Instrument Penetration Inspection and Flaw Evaluation Guidelines” 

● BWRVIP-74-A, “BWR Reactor Pressure Vessel Inspection and Flaw Evaluation 

Guidelines” 

In Appendix C, the applicant included three license renewal action items that are applicable to 

all BWRVIP reports and several other license renewal action items that are applicable to 

specific BWRVIP reports. In addition, Appendix C addresses the applicant’s response to other 

license renewal action items. 

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 whether 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 AMP XI.M9. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M9. 

During its audit, the staff reviewed the applicant’s program basis document and associated 

documents, and noted that the applicant’s implementation of the BWRVIP reports is consistent 

with GALL AMP XI.M9. The applicant routinely inspected the RVI components per the 

applicable BWRVIP reports, and repaired and/or evaluated the indications per the BWRVIP 

reports or ASME Code Section XI requirements. The staff noted that the applicant’s program 

relies on monitoring and control of reactor water chemistry based on the guidance of 

BWRVIP-130 report (Electric Power Research Institute (EPRI)-008192), which is a later revision 

to the BWRVIP-29 report, and the staff finds it acceptable because the GALL Report allows the 

use of a later revision of the BWRVIP report for monitoring the RCS water chemistry. During 

the audit, the staff noted that the applicant is using hydrogen water chemistry (HWC) in 

conjunction with noble metals chemical addition (NMCA) to mitigate IGSCC. The staff also 

noted that the applicant’s methodology of monitoring the effectiveness of HWC/NMCA includes 

a measurement of the electrochemical corrosion potential (ECP) of the RVI components in RCS 

water and monitoring the feedwater hydrogen level. These methods will ensure adequate 

protection of the majority of the RVI components from IGSCC. 

During its audit, the staff reviewed several inspection reports associated with the previous 

inspections that were performed on the RVI components by the applicant. Based on its review, 

the staff determined that the applicant complied with the inspection requirements of the 

applicable BWRVIP reports which are consistent with GALL AMP XI.M9. The staff also 

reviewed the applicant’s implementation of its corrective action methodology for identifying 

nonconforming conditions and found the applicant’s corrective action methodology acceptable. 

The staff, therefore, determined that the applicant adequately implemented the inspection 

criteria of the BWRVIP reports for the RVI components and that the applicant’s program is 

consistent with GALL AMP XI.M9. 
Aging Management Review Results 

 3-28 

The applicant is required to comply with the license renewal action items specified in the staff’s 

SEs for the aforementioned BWRVIP reports for the period of extended operation. The 

following paragraphs address the applicant’s responses to these license renewal action items 

and the corresponding staff’s evaluation. 

License Renewal Action Items Addressed in Appendix C. The applicant made a commitment to 

comply with the following three license renewal action items which are listed in the staff’s SEs 

for the various BWRVIP reports: 

 (1) HCGS’s AMP for the RVI components is bounded by the aforementioned BWRVIP 

reports. 

 (2) The UFSAR supplement addresses a summary of the programs and activities specified 

in the applicable BWRVIP reports. 

 (3) HCGS stated that no TS changes have been identified as a result of implementing the 

AMP for the RVI components. 

The staff reviewed the applicant’s disposition for these three license renewal action items and 

concludes that the applicant complied with the intent of the license renewal action items that 

were specified by the staff in its SEs for the applicable BWRVIP reports. 

According to the applicant, there are no time-limited aging analysis (TLAA) issues for HCGS 

related to the following BWRVIP reports, but it has committed to complying with the 

requirements specified in these BWRVIP reports: 

● BWRVIP-18-A, “BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines” 

● BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines” 

The staff reviewed the applicant’s response to the license renewal action items and accepted it 

because the staff’s SEs for the aforementioned BWRVIP reports do not specify any license 

renewal action items. 

For the license renewal action items specified in the staff’s SE dated October 18, 2001, the 

BWRVIP-74-A report addresses the aging effects on the RVI components and provides 

requirements to effectively manage the aging effects during the period of extended operation. 

The BWRVIP-74-A report also addresses the license renewal action items associated with 

TLAAs for the period of extended operation. The following paragraphs address the TLAAs and 

the AMP related to RVI components that are specified in the BWRVIP-74-A report, the 

applicant’s responses to these license renewal action items stated in LRA Appendix C, and the 

corresponding staff’s evaluation of each action item response. 

Because of item 4 of the staff’s BWRVIP-74-A SE report, the applicant identified loss of material 

and cracking as aging effects that require an AMP for the vessel flange leak detection (VFLD) 

line. The applicant stated that it would manage these aging effects by performing a one-time 

inspection and an ISI program per ASME Code Section XI, and by controlling the RCS water 

chemistry. The staff accepts the applicant’s proposed AMP for the VFLD lines because: (1) the 

combination of ISI and one-time inspection programs will adequately identify the aging 
Aging Management Review Results 

 3-29 

degradation in a timely manner, and (2) controlling water chemistry will also enable the 

applicant to effectively manage the occurrence of any cracking or loss of material in VFLD lines. 

Item 5 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report requires 

that the applicant describe how each plant-specific AMP addresses the 10 elements listed in 

GALL AMP XI.M9. The applicant stated that LRA Appendix B addresses the required 

10 elements. The staff reviewed Appendix B and accepts the applicant’s response because 

Appendix B adequately addresses the 10 elements of GALL AMP XI.M9. 

Item 6 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report requires 

that the applicant include a water chemistry program in its LRA to ensure that it can effectively 

manage IGSCC in the RCS. In its response, the applicant stated that it would comply with the 

BWRVIP-130 report, which superseded the BWRVIP-29 report. The staff accepts this response 

as the applicant’s compliance with the requirements of the BWRVIP-130 provides adequate 

mitigation to the occurrence of IGSCC. 

Item 7 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report requires 

that the applicant identify its RPV surveillance program. The applicant stated that it has 

implemented the staff-approved BWRVIP integrated surveillance program (ISP)—BWRVIP-116, 

“BWR Vessel and Internals Project Integrated Surveillance Program.” Compliance with the 

staff-approved ISP enables the applicant to effectively monitor neutron embrittlement of the 

RPV materials and, therefore, the staff accepts the applicant’s response. 

Item 8 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report requires 

that the applicant verify that the number of cycles assumed in the original fatigue design is 

conservative to assure that the estimated fatigue usage for 60 years of plant operation is not 

underestimated. The use of alternative actions for cases where the estimated fatigue usage is 

projected to exceed 1.0 will require case-by-case analysis. The applicant should address 

environmental fatigue for the components listed in the BWRVIP-74 report. The applicant stated 

that fatigue (including discussions of cycles, projected cumulative usage factors (CUFs), and 

environmental factors, etc.) is evaluated as a TLAA in LRA Section 4.3. The staff’s evaluation 

on this issue is addressed in SER Section 4.3. 

Item 9 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report requires 

that a set of pressure versus temperature (P-T) curves should be developed for the heat-up and 

cool-down operating conditions in the plant at a given effective full-power year (EFPY) during 

the period of extended operation. The applicant stated that the development of P-T curves for 

the period of extended operation is described as a TLAA in LRA Section 4.2.3. The staff 

evaluated the TLAA associated with P-T curves in SER Section 4.2. 

Item 10 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report 

requires that the applicant evaluate the percent of reduction in Charpy upper-shelf energy (USE) 

values for the beltline materials during the period of extended operation. The applicant stated 

that the TLAA evaluation of USE is addressed in LRA Section 4.2. The staff evaluated the 

TLAA associated with USE criteria for the RPV beltline materials in SER Section 4.2. 

Item 11 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report 

requires that the applicant obtain relief from the ISI of the circumferential shell welds during the 

period of extended operation. The BWRVIP-05 report, “Reactor Vessel Shell Weld Inspection 

Guidelines,” requires that each licensee will have to demonstrate that: (1) at the end of the 

period of extended operation, the circumferential shell welds will satisfy the limiting conditional 
Aging Management Review Results 

 3-30 

failure frequency specified in Appendix E for the staff’s SE dated July 28, 1998, for the 

BWRVIP-05 report and (2) it has implemented operator training and established procedures that 

limit the frequency of cold overpressure events to the amount specified in the staff’s SE dated 

July 28, 1998, for the BWRVIP-05 report. The applicant stated that the discussion of the relief 

from the ISI of the circumferential shell welds for HCGS during the period of extended operation 

is described in LRA Section 4.2. The staff evaluated the TLAA associated with the relief from 

the ISI of the RPV circumferential shell welds for HCGS and the staff’s evaluation is addressed 

in SER Section 4.2. 

Item 12 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report 

requires that the applicant monitor RPV axial beltline weld embrittlement. One acceptable 

method is to determine that the mean reference temperature nil-ductility transition (RTNDT) of the 

limiting RPV axial beltline weld at the end of the period of extended operation is less than the 

values specified in Table 1 of the staff’s SE dated October 18, 2001, for the BWRVIP-74-A 

report. The applicant stated that the TLAA evaluation of beltline axial welds is addressed in 

LRA Section 4.2. The staff evaluated the TLAA associated with the RPV axial weld failure 

probability for HCGS in SER Section 4.2. 

Item 13 of the license renewal action items in the staff’s SE for the BWRVIP-74-A report 

requires that the Charpy USE, P-T limit, inspection relief for the RPV circumferential shell welds, 

and RPV axial weld integrity evaluations are all dependent upon the neutron fluence. The 

applicant may perform neutron fluence calculations using a staff-approved methodology or may 

submit its methodology for staff review. If the applicant performs the neutron fluence calculation 

using a methodology previously approved by the staff, the applicant should identify the staff 

letter that approved the methodology. The applicant stated that the calculation of neutron flux is 

addressed in LRA Section 4.2. The staff evaluated the TLAAs associated with the neutron 

fluence calculations in SER Section 4.2. 

ASME Code Section XI, Subsection IWB-3600 states that flaw indications that exceed the size 

of allowable indications defined in ASME Code Section XI, Subsection IWB-3500 may be 

evaluated by analytical procedures, such as described in ASME Code Section XI, Appendix A, 

in order to calculate growth until the next inspection or the end of service lifetime of the 

component. Item 14 of the license renewal action items in the staff’s SE for the BWRVIP-74-A 

report requires that the components that have indications which were previously evaluated 

analytically in accordance with ASME Code Section XI, Subsection IWB-3600 until the end of 

the 40-year service period shall be re-evaluated for the 60-year service period corresponding to 

the license renewal term. The applicant stated that up to the time of the issuance of the staff’s 

SE for the BWRVIP-74-A report, it has no flaws that exceeded the applicable acceptance 

standards of ASME Code Section XI, Subsection IWB-3500 that would merit an analytical 

evaluation in accordance with ASME Code Section XI, Subsection IWB-3600. Therefore, item 

14 is not applicable because there are no indications that require a re-evaluation for the period 

of extended operation. The staff accepts this response because there are no flaws that require 

an analytical re-evaluation performed in accordance with ASME Code Section XI, Subsection 

IWB-3600. 

Based on its review, the staff finds that the applicant has addressed the license renewal action 

items as described above, and the staff’s acceptance of each license renewal action item is 

described above or in the referred SER Section 4. 
Aging Management Review Results 

 3-31 

Based on its audit, the staff finds that elements one through six of the applicant’s BWR Vessel 

Internals Program are consistent with the corresponding program elements of GALL AMP XI.M9 

and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.9 summarizes operating experience related to the 

BWR Vessel Internals Program. The staff noted that the applicant has identified relevant 

HCGS-specific operating experience in the “operating experience” program element discussion 

for the BWR Vessel Internals Program. The staff noted that there were flaw indications (cracks) 

in the core shroud circumferential welds and some of the jet pump assembly components 

(i.e., jet pump set screw tack weld and sensing line brackets). The staff also noted that the 

applicant has dispositioned the core shroud weld flaw indications as acceptable for further 

service without the need for repair or replacement of the components at this time. The staff 

noted that an auxiliary spring wedge was installed to replace the function of the set screw and 

the sensing line brackets were repaired. 

Related to the extended power uprate (EPU) at HCGS, the applicant has also implemented 

additional inspections on steam dryer components according to the guidance in BWRVIP-139. 

The staff noted that the inspections identified some additional SCC and weld quality cracking, 

but there was no evidence of the fatigue cracking that has been found in other BWRs after EPU. 

The applicant has attributed the lack of fatigue cracking to modifications made to the steam 

dryer as a result of industry experience. 

The staff noted that by implementing the BWR Vessel Internals Program, the applicant 

adequately demonstrated its capability in identifying the aging effects associated with the RVI 

components and that it can adequately monitor the aging degradation of the RVI components by 

using proper corrective actions to restore the structural integrity of the RVI components. 

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 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. LRA Section A.2.1.9 provides the UFSAR supplement for the BWR 

Vessel Internals Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. 

The staff also notes that the applicant committed (Commitment No. 9) to ongoing 

implementation of the existing BWR Vessel Internals Program for managing aging of applicable 
Aging Management Review Results 

 3-32 

components during the period of extended operation and to implement the BWRVIP guidelines 

as follows: 

● PSEG will inform the staff of any decision to not fully implement a BWRVIP guideline 

approved by the staff. 

● PSEG will notify the staff if changes are made to the RPV and its internals programs that 

affect the implementation of the BWRVIP guideline. 

● PSEG will submit any deviation from the existing flaw evaluation guidelines that are 

specified in the BWRVIP guideline. 

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 review of the applicant’s BWR Vessel Internals Program, the 

staff finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.8 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless 

Steel (CASS) 

Summary of Technical Information in the Application. LRA Section B.2.1.10 describes the new 

Thermal Aging and Neutron Irradiation Embrittlement of CASS Program as consistent with 

GALL AMP XI.M13, “Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic 

Stainless Steel (CASS).” 

The applicant stated that its program will include a component-specific evaluation to: (a) identify 

the “susceptible components” determined to be limiting from the standpoint of thermal aging 

susceptibility and/or neutron irradiation embrittlement, and (b) for each “potentially susceptible” 

component, aging management will be accomplished through either a supplemental 

examination of the affected component based on the neutron fluence to which the component 

has been exposed as part of the BWR Vessel Internals Program during the period of extended 

operation, or a component-specific evaluation to determine its susceptibility to loss of fracture 

toughness. 

The applicant identified the following CASS components as susceptible to thermal aging and 

neutron irradiation embrittlement and subject to loss of fracture toughness: control rod 

assemblies, guide tubes, core spray lines and spargers, spray nozzles and elbows, fuel 

supports, jet pump assemblies, transition piece, inlet, throat, and diffuser collar, and steam 

dryers drain line fittings. The applicant also stated that the new program will be implemented 

prior to the period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 
Aging Management Review Results 

 3-33 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL AMP X1.M13. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M13. 

The staff also conducted onsite interviews with the applicant to confirm the plan for the new 

program. In addition, the staff also confirmed that this program will include two phases where: 

● Phase 1 will identify components that exceed neutron fluence (E>1017 neutrons per 

square centimeter (n/cm2

) for all neutrons with E>1 million electron volts (MeV)) and/or 

temperature (greater than 250 °C) limits. 

● Phase 2 will either recommend supplemental examinations of susceptible components 

during the period of extended operation, or a component-specific evaluation to 

determine the component’s susceptibility to loss of fracture toughness. 

Based on its audit, the staff finds that elements one through six of the applicant’s Thermal Aging 

and Neutron Irradiation Embrittlement of CASS Program are consistent with the corresponding 

program elements of GALL AMP XI.M13 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.10 also summarizes operating experience related to 

the applicant’s existing BWR Vessel Internals Program. The applicant stated that there is 

sufficient confidence that the implementation of the Thermal Aging and Neutron Irradiation 

Embrittlement of CASS Program, which will augment the existing BWR Vessel Internals 

Program, will effectively identify the degradation of the CASS components found in the control 

rod assemblies, core spray lines and spargers, fuel supports, jet pump assemblies, and in the 

steam dryer prior to failure. 

The staff reviewed the applicant’s operating experience basis document for safety-significant 

operating experience relevant to the aging management of CASS components. The staff noted 

that the applicant has conducted numerous inspections of the reactor internals as part of its 

BWR Vessel Internals Program and provided three examples of aging that have been detected. 

The staff noted that in each case, inspections done as part of the existing BWR Vessel Internals 

Program found evidence of aging and conducted component-specific evaluations to determine 

whether the component should be repaired, replaced, or put on an enhanced inspection 

schedule. The staff noted that these examples, along with interviews with the applicant, 

demonstrate that the new program will: (1) implement appropriate corrective actions when 

deficiencies are identified and taken through the corrective action program, including actions to 

determine the cause and extent of condition, and (2) utilize operating experience to improve the 

inspection process at HCGS and ensure that the intended safety function of susceptible 

components is maintained. 

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. The staff noted that this is a new 

program and that no plant-specific operating experience is available. 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. 
Aging Management Review Results 

 3-34 

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. LRA Section A.2.1.10 provides the UFSAR supplement for the Thermal 

Aging and Neutron Irradiation Embrittlement of CASS Program. The staff reviewed this UFSAR 

supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR Table 3.1-2. The staff also notes 

that the applicant committed (Commitment No. 10) to implement the new Thermal Aging and 

Neutron Irradiation Embrittlement of CASS Program prior to entering the period of extended 

operation for managing aging of applicable components. 

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 review of the applicant’s Thermal Aging and Neutron Irradiation 

Embrittlement of CASS Program, the staff finds all program elements consistent with the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.9 Open-Cycle Cooling Water System 

Summary of Technical Information in the Application. LRA Section B.2.1.13 describes the 

existing Open-Cycle Cooling Water System Program as consistent with GALL AMP XI.M20, 

“Open-Cycle Cooling Water System.” The applicant stated that its program includes 

surveillance and control techniques to manage aging effects caused by bio-fouling, corrosion, 

erosion, protective coating failures, and silting in the open-cycle cooling water system. The 

applicant also stated that the program provides assurance that cracking, loss of material, 

increase in porosity and permeability, loss of strength, hardening, and reduction of heat transfer 

are maintained at acceptable levels. The applicant further stated that sodium hypochlorite 

injection, system and component testing, visual inspections, and other nondestructive 

examinations (NDEs) are performed to ensure that aging effects are 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 whether 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 AMP XI.M20. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M20. Based 

on its audit, the staff finds that elements one through six of the applicant’s Open-Cycle Cooling 

Water System Program are consistent with the corresponding program elements of GALL 

AMP XI.M20 and, therefore, acceptable. 
Aging Management Review Results 

 3-35 

Operating Experience. LRA Section B.2.1.13 summarizes operating experience related to the 

Open-Cycle Cooling Water System Program. The applicant stated in the operating experience 

that it identified excessive corrosion at several of the bell and spigot joints in portions of the 

service water buried piping. As a consequence, the applicant inspected all similar joints in the 

system using broadband scanning, which can detect degradation of carbon steel piping 

enclosed in reinforced concrete. Based on operating experience from the Salem Nuclear 

Generating Station (Salem) (co-located with HCGS), the applicant also stated that WEKO 

(elastomer) seals were used to correct the problem on eight joints, and cleaning and coating 

restorations were performed to restore other joints to original configurations. 

The applicant stated in operating experience that during routine maintenance, it identified three 

locations in the service water piping header that were below the nominal piping thickness where 

an epoxy coating had worn away. The applicant also stated that further evaluations of wall 

thickness were performed, and it was determined that the thicknesses were greater than the 

calculated design minimum wall thickness so the locations were cleaned and recoated with 

epoxy. The applicant further stated that a subsequent inspection of the system identified an 

additional area that had corroded below the minimum wall thickness and that corrective actions 

were taken to repair that area by using weld buildup and recoating with epoxy. 

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 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. LRA Section A.2.1.13 provides the UFSAR supplement for the 

Open-Cycle Cooling Water System Program. The staff reviewed this UFSAR supplement 

description of the program and notes that it conforms to the recommended description for this 

type of program as described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. 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). 

The staff also notes that the applicant committed (Commitment No. 13) to ongoing 

implementation of the existing Open-Cycle Cooling Water System Program for managing aging 

of applicable components during the period of extended operation. 

Conclusion. On the basis of its review of the applicant’s Open-Cycle Cooling Water System 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 
Aging Management Review Results 

 3-36 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.10 Compressed Air Monitoring 

Summary of Technical Information in the Application. LRA Section B.2.1.16 describes the 

existing Compressed Air Monitoring Program as consistent with GALL AMP XI.M24, 

“Compressed Air Monitoring.” The applicant stated that the program consists of testing, 

monitoring, and inspection of piping, piping components, and piping elements, compressor 

housings, and tanks for loss of material due to general, pitting, and crevice corrosion in the 

compressed air systems. The applicant also stated that this program includes periodic leak 

testing of valves, piping, and other system components; and preventive monitoring that checks 

air quality at multiple locations in the system to ensure that oil, water, rust, dirt, and other 

contaminants are kept within accepted limits. The applicant further stated that the program 

provides for timely corrective actions to ensure that the system is operated within accepted 

limits. 

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 whether 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 AMP XI.M24. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M24. Based 

on its audit, the staff finds that elements one through six of the applicant’s Compressed Air 

Monitoring Program are consistent with the corresponding program elements of GALL 

AMP XI.M24 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.16 summarizes operating experience related to the 

Compressed Air Monitoring Program. The applicant stated that the program is effective in 

ensuring that intended functions will be maintained consistent with the CLB for the period of 

extended operation. The applicant also stated that it had found and replaced instrument air 

lines that were worn due to vibration at mounting points. The applicant further stated that rust 

particles were found in the aftercooler drain line and drain trap, clogging the drain trap and 

thereby causing it to fail; these were replaced and UT testing was performed on upstream 

components to identify the potential source of rust particles. In both of these operational 

experiences, the applicant identified that through its actions, identification, evaluation, and 

correction, it ensured the continued effective operation of the compressed air monitoring 

system. 

Furthermore, the applicant stated that it identified a leak in an instrument airline at an elbow joint 

on the exit of an air dryer. The applicant stated that a temporary repair was made, and the item 

was placed into the work management system. The applicant also stated this temporary repair 

was completed because an instrument air header outage was required for a permanent repair to 

be made and that it was scheduled for completion during a refueling outage. The applicant 

further stated that this was an example of how compressed air deficiencies were identified, 

evaluated, and corrected to ensure the system maintained its intended functions. 
Aging Management Review Results 

 3-37 

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 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. LRA Section A.2.1.16 provides the UFSAR supplement for the 

Compressed Air Monitoring Program. The staff reviewed this UFSAR supplement description of 

the program and notes that it conforms to the recommended description for this type of program 

as described in SRP-LR Table 3.3-2. The staff also notes that the applicant committed 

(Commitment No. 16) to ongoing implementation of the existing Compressed Air Monitoring 

Program for managing aging of applicable components during 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 review of the applicant’s Compressed Air Monitoring Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.11 One-Time Inspection 

Summary of Technical Information in the Application. LRA Section B.2.1.22 describes the 

applicant’s new One-Time Inspection Program as consistent with GALL AMP XI.M32, “One 

Time Inspection.” The applicant stated that the One-Time Inspection Program will provide 

reasonable assurance that an aging effect is not occurring, or that the aging effect is occurring 

slowly enough to not affect the components intended function during the period of extended 

operation and, therefore, will not require additional aging management. The applicant stated 

that major component types covered by the program include piping, piping elements and piping 

components, reactor vessel and nozzles, and heat exchangers and tanks. The applicant further 

stated that the One-Time Inspection Program will be used to confirm the effectiveness of the 

Water Chemistry, Fuel Oil Chemistry, and Lubricating Oil Analysis programs at mitigating the 

effects of aging. The applicant further stated that it will use visual and volumetric inspection 

techniques performed per ASME Code standards, and its acceptance criteria will follow station 

procedures based on applicable industry and regulatory codes and standards. 
Aging Management Review Results 

 3-38 

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 whether 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 AMP XI.M32 and confirmed that each element of the applicant’s program is 

consistent with the corresponding element of GALL AMP XI.M32, with the exception of the 

“detection of aging effects” program element. For this element, the staff determined a need for 

additional clarification, which resulted in the issuance of an RAI. 

GALL AMP XI.M32 states in the “detection of aging effects” program element 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.” The LRA states, in regard to 

“detection of aging effects,” that the program element includes: (a) determination of the sample 

size based on an assessment of materials of fabrication, environment, plausible aging effects, 

and operating experience and (b) identification of inspection locations in the system, 

component, or structure based on the aging effect. The LRA, however, did not state how the 

selected set of sample components would be determined or the size of the sample of 

components that would be inspected. The staff noted that due to the uncertainty in determining 

the most susceptible locations and the potential for aging to occur in other locations, large 

sample sizes may be required in order to adequately confirm that an aging effect is not 

occurring. By letter dated December 13, 2010, the staff issued RAI B.2.1.22-1 requesting that 

the applicant provide clarifying information regarding how the selected set of components to be 

sampled will be determined and to provide the size of the sample of components that will be 

inspected. 

In its response dated January 6, 2011, the applicant stated that it will develop a sample plan 

which will establish sample groups based on aging effects and environments and be populated 

with the components and their materials of fabrication. The applicant also stated that a sample 

size of 20 percent of the population (up to a maximum of 25 inspections) will be established for 

each sample group. The applicant further stated that the selection of components for 

inspection, when possible, will be biased toward inspecting bounding or lead components most 

susceptible to aging in potentially more aggressive environments (e.g., low or stagnant flow 

areas) and selecting components with the lowest design margin. The applicant revised the 

program’s UFSAR supplement and program description to include this information. The staff 

finds the applicant’s response acceptable because the applicant’s sampling methodology: 

(a) ensures a representative sample of material and environment combination is considered, 

(b) ensures sample locations will focus on the most susceptible components, and (c) includes 

an appropriate sample size. The staff’s concerns described in RAI B.2.1.22-1 are resolved. 

Based on its audit and the resolution to RAI B.2.1.22-1, 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 AMP XI.M32 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.22 summarizes operating experience related to the 

One-Time Inspection Program. The applicant stated several examples of inspection that 

demonstrate that it has successfully used visual and volumetric inspection techniques to 

evaluate the integrity of various components, including the reactor steam dryer assembly 

weldments, service water pump lubrication reservoirs, and steam supply nozzle pipes at the 

feedwater heater. The applicant also stated that it will apply the same techniques in its 
Aging Management Review Results 

 3-39 

One-Time Inspection Program and, therefore, the program will be as effective as its previous 

inspections in identifying aging effects in relevant systems and components. In addition, for 

systems that credit the One-Time Inspection Program for aging management, the applicant 

reviewed Maintenance Rule and System Health reports and identified that none of the aging 

effects being managed by the One-Time Inspection Program negatively impacts any of those 

systems’ performance or causes any loss of component intended function for these systems. 

The applicant further stated that the overall condition of these systems with respect to the 

applicable aging effects, coupled with the one-time inspections, provide sufficient confidence 

that implementation of the One-Time Inspection Program will effectively identify and manage 

degradation that could lead to failure. 

The staff reviewed operating experience information in the application during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant 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 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. LRA Section A.2.1.22 provides the UFSAR supplement, as amended by 

letter dated January 6, 2011, for the One-Time Inspection Program. The staff reviewed this 

UFSAR supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, and 

3.4-2. The staff also notes that the applicant committed (Commitment No. 22) to implement the 

new One-time Inspection Program prior to entering the period of extended operation for 

managing aging of applicable components. Specifically, the applicant committed: 

1. To confirm the effectiveness of the Water Chemistry program to manage 

the loss of material, cracking, and the reduction of heat transfer aging 

effects for aluminum, copper alloy, ductile cast iron, gray cast iron, nickel 

alloy, steel, stainless steel, and cast austenitic stainless steel in treated 

water, steam, sodium pentaborate and reactor coolant environments. 

2. To confirm the effectiveness of the Fuel Oil Chemistry program to 

manage the loss of material aging effect for copper alloy, steel, 

galvanized steel and stainless steel in a fuel oil environment. 

3. To confirm the effectiveness of the Lubricating Oil Analysis program to 

manage the loss of material and the reduction of heat transfer aging 

effects for copper alloy, gray cast iron, steel and stainless steel in a 

lubricating oil environment. 
Aging Management Review Results 

 3-40 

4. To confirm loss of material in carbon steel piping and fitting is insignificant 

in an air/gas-wetted (internal) environment. 

The sample plan for inspection associated with the One-Time Inspection program 

will be developed to ensure there are adequate inspections to address each of 

the material, environment, and aging effect combinations. A sample size of 20 

percent of the population (up to a maximum of 25 inspections) will be established 

for each of the sample groups. 

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 review of the applicant’s One-Time Inspection Program and the 

resolution to RAI B.2.1.22-1, the staff determines that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement, 

as amended, for this AMP and concludes that it provides an adequate summary description of 

the program, as required by 10 CFR 54.21(d). 

3.0.3.1.12 Selective Leaching of Materials 

Summary of Technical Information in the Application. LRA Section B.2.1.23 describes the 

new Selective Leaching of Materials Program as consistent with GALL AMP XI.M33, “Selective 

Leaching of Materials.” The applicant stated that the Selective Leaching of Materials Program 

ensures the integrity of components made of gray cast iron, copper alloy with greater than 

15 percent zinc, and aluminum bronze with greater than 8 percent aluminum exposed to raw 

water, closed cooling water, soil (ground water), or treated water that may lead to selective 

leaching of one of the metal components. The applicant also stated that the AMP includes a 

one-time visual inspection and hardness measurements of selected components that may be 

susceptible to selective leaching to identify whether material loss from selective leaching is 

occurring and if selective leaching will affect the ability of components to perform their intended 

function for the period of extended operation. 

Based upon an observation during the regional license renewal inspections, IP-71002 (ADAMS 

Accession No. ML102740350), the applicant amended its LRA by letter dated September 1, 

2010, to include aging management activities, such as periodic inspections and trending, to 

manage the aging effects for material and environment combinations where selective leaching 

is identified. 

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 whether 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 AMP XI.M33 and confirmed that each element of the applicant’s program is 

consistent with the corresponding element of GALL AMP XI.M33, with the exception of the 

“scope of the program” element. For this element, the staff determined a need for additional 

clarification via an RAI. 
Aging Management Review Results 

 3-41 

GALL AMP XI.M33 states in the “scope of the program” element that the program “includes a 

one-time visual inspection and hardness measurement of a selected set of sample components 

to determine whether loss of material due to selective leaching is not occurring for the period of 

extended operation.” The LRA did not state how the selected set of sample components would 

be determined or the size of the sample of components that would be inspected. The staff 

noted that due to the uncertainty in determining the most susceptible locations and the potential 

for aging to occur in other locations, large sample sizes may be required in order to adequately 

confirm that selective leaching is not occurring. By letter dated December 13, 2010, the staff 

issued RAI B.2.1.23-1 requesting that the applicant provide specific information regarding how 

the selected set of components to be sampled will be determined and to provide the size of the 

sample of components that will be inspected. 

In its response dated January 6, 2011, the applicant stated that the sample size and inspection 

locations for the one-time inspections will be developed to ensure that a representative sample 

of material and environment combinations is selected with a focus on the leading indicator 

components. The applicant also stated that the representative sample size and one-time 

inspection locations will be based on the population of components with the two susceptible 

materials of fabrication. The applicant further stated that a sample size of 20 percent of the 

population of copper alloy components susceptible to selective leaching and a sample size of 

20 percent of the population of gray cast iron components susceptible to selective leaching will 

be established with up to a maximum of 25 inspections performed per susceptible material 

group. The applicant revised the program’s UFSAR supplement and program description to 

include this information. The staff finds the applicant’s response acceptable because the 

applicant’s sampling methodology: (a) ensures a representative sample of material and 

environment combinations is considered, (b) ensures sample locations will focus on known 

susceptible components, and (c) includes an appropriate sample size. The staff’s concerns 

described in RAI B.2.1.23-1 are resolved. 

Based on the results of the audit and the resolution of RAI B.2.1.23-1, the staff finds that 

elements one through six of the applicant’s Selective Leaching of Materials Program are 

consistent with the corresponding program elements of GALL AMP XI.M33 and, therefore, 

acceptable. 

Operating Experience. LRA Section B.2.1.23 summarizes operating experience related to the 

Selective Leaching of Materials Program. The applicant stated that through visual inspection, it 

has identified de-alloying of aluminum bronze valves in the service water system brackish water 

environment. The applicant also stated that a sample of a cross section of a valve was sent to a 

laboratory for confirmation of selective leaching and assessment of material properties, and that 

the service water system aluminum bronze valves susceptible to de-alloying were placed into 

the Valve Material Condition Improvement Project. The applicant further stated that as part of 

this project, valves that are susceptible to selective leaching have been gradually replaced and 

that this operating experience is being used to assess the potential for selective leaching and to 

proactively replace valves susceptible to selective leaching. 

The applicant stated that it has identified the graphitization of gray cast iron submerged pump 

components from long-term immersion in saltwater and brackish water environments in the 

Salem plant (co-located with the HCGS). The applicant also stated that as a result of this 

operating experience, HCGS evaluated similar potentially affected components and that while 

similar materials, environments, and components exist at HCGS, graphitization had not been 

observed at the plant. The applicant further stated that the HCGS pumps are less susceptible 

to selective leaching due to the water being recirculated as a closed-loop treated water system 
Aging Management Review Results 

 3-42 

through the cooling tower, rather than straight from the river, and because of the concern for 

selective leaching, these components are inspected on a 6-year frequency to ensure their 

function will be maintained. The applicant stated that this operating experience demonstrates 

how it effectively incorporates operating experience at Salem to assess the applicability at 

HCGS for potential selective leaching. 

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 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. LRA Section A.2.1.23 provides the UFSAR supplement, as amended by 

letter dated January 6, 2011, for the Selective Leaching of Materials Program. The staff 

reviewed this UFSAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program as described in SRP-LR Tables 3.1-2, 3.2-2, 

and 3.3-2. The staff also notes that the applicant committed (Commitment No. 23) to implement 

the new Selective Leaching of Materials Program prior to entering the period of extended 

operation for managing aging of applicable components. Specifically, the applicant’s 

commitment states: 

Selective Leaching of Materials is a new program that will include one-time 

inspections of a representative sample of susceptible components to determine 

where loss of material due to selective leaching is occurring. A sample size of 20 

percent of susceptible components will be subjected to a one-time inspection 

with a maximum of 25 inspections for each of the susceptible material groups. 

Where selective leaching is identified, further aging management activities will be 

implemented such that the component intended function is maintained consistent 

with the current licensing basis through 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 review of the applicant’s Selective Leaching of Materials 

Program and resolution of RAI B.2.1.23-1, the staff finds all program elements consistent with 

the GALL Report. The staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR supplement, as amended, for this AMP and concludes that it provides 

an adequate summary description of the program, as required by 10 CFR 54.21(d). 
Aging Management Review Results 

 3-43 

3.0.3.1.13 External Surfaces Monitoring 

Summary of Technical Information in the Application. LRA Section B.2.1.25 describes the new 

External Surfaces Monitoring Program as consistent with the program elements in GALL 

AMP XI.M36, “External Surfaces Monitoring.” The applicant stated that its program is a 

condition monitoring program that relies on observations made during visual inspections. The 

applicant also stated that it relies on this program to preliminarily detect corrosion by inspecting 

for degradation of coatings and the appearance of visually apparent corrosion products on steel 

components. The applicant further stated that the visual inspections conducted within this 

program serve to detect degradation of steel components prior to any loss of intended function. 

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 whether 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 AMP XI.M36. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M36. Based 

on its audit, the staff finds that elements one through six of the applicant’s External Surfaces 

Monitoring Program are consistent with the corresponding program elements of GALL 

AMP XI.M36 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.25 summarizes operating experience related to the 

External Surfaces Monitoring Program. The applicant’s operating experience included accounts 

of the detection and assessment of corrosion on steel piping surfaces and the corrective 

actions. The corrective actions, as described by the applicant, included removal of corrosion 

products prior to repair of the affected area by repainting. 

In one instance of operating experience, the applicant described a case where, during a plant 

tour, rust was observed on two chilled water pipe flanges that were exposed by the removal of 

insulation to facilitate piping repair on a section of chilled water supply line. The applicant stated 

that an engineering analysis determined that the corrosion was due to condensation that was 

allowed to form on the exposed area due to removal of the insulation. The applicant also stated 

that the program was effective for detecting the corrosion before loss of functionality and that 

the knowledge gained in that instance of operating experience was used to increase operator 

awareness regarding the potential susceptibility of the chilled water line to corrosion when 

insulation is not in place. 

Through another example of operating experience, the applicant described the detection of rust 

due to a leaking reactor core isolation cooling valve. The applicant stated that the observation 

of the rust, which led to the detection of the leak, illustrated the effectiveness of the program’s 

inspection process. The applicant also described the corrective actions that were implemented, 

which involved repairing the affected area that had rusted and also repairing the leak. 

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. 
Aging Management Review Results 

 3-44 

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 corrosion on SCCs 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. LRA Section A.2.1.25 provides the UFSAR supplement for the External 

Surfaces Monitoring Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant 

committed (Commitment No. 25) to implement the new External Surfaces Monitoring Program 

prior to entering the period of extended operation for managing aging of applicable components. 

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 review of the applicant’s External Surfaces Monitoring Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.14 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Summary of Technical Information in the Application. LRA Section B.2.1.26 describes the new 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as 

consistent with GALL AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components.” The applicant stated that this program manages the internal surfaces of 

steel piping, piping components, piping elements, tanks, and ducting components for loss of 

material. The applicant also stated that this program includes provisions for visual inspections 

of the internal surfaces of components not managed under other AMPs and that inspections will 

be performed when internal surfaces are accessible during maintenance, surveillances, and 

scheduled outages. For painted or coated surfaces, the applicant stated that it will monitor the 

condition of the finish as an indicator for corrosion of the underlying steel. The applicant further 

stated that operating history will be taken into consideration to determine the frequency of 

inspections and that a representative sample of locations will also be taken into consideration. 

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 whether 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 AMP XI.M38. As discussed in the Audit Report, the staff confirmed that 
Aging Management Review Results 

 3-45 

these elements are consistent with the corresponding elements of GALL AMP XI.M38, with the 

exception of the “detection of aging effects” program element. 

When the staff compared the LRA program description, which suggests the use of a 

“representative sample,” to GALL AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” “detection of aging effects” program element 

recommendations on sampling, it was unclear to the staff how the applicant defined its 

“representative sample” (i.e., the population criteria, size, and sampling methodology used). 

On August 18, 2010, the staff held a telephone conference with the applicant (see ADAMS 

Accession No. ML102440706) to clarify the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program’s sampling methodology, including how the 

population for each of the material-environment-aging effect combinations is being selected, 

and what type of engineering, design, or operating experience considerations would be used to 

select the sample of components for both the scheduled and supplemental inspections. During 

this discussion, the applicant stated that the program will ensure that for each material, 

environment, and aging effect combination, the applicant will conduct representative inspections 

as directed by formal preventive maintenance or recurring tasks within the work management 

system. The applicant also stated that the intent is to use existing preventive maintenance or 

recurring task activities augmented with new recurring task activities to address inspection of 

material, environments, and aging effects not adequately addressed by the current activities. 

The applicant further stated that if adverse conditions are identified, they will be entered into a 

corrective action program, discussed in the LRA, and appropriate actions will be directed 

including identifying and evaluating the cause and extent of condition(s). The staff finds the 

applicant’s response acceptable and that the “detection of aging effects” program element is 

consistent with the corresponding element of GALL AMP XI.M38, “Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components,” because its “representative 

sample” will include inspections for each material, environment, and aging effect combinations 

and that when degradation is found, it will be entered in the corrective action program. 

Based on its audit, the staff finds that elements one through six of the applicant’s Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program are consistent with 

the corresponding program elements of GALL AMP XI.M38 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.26 summarizes operating experience related to the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

applicant stated that industry operating experience indicates that it is possible to sustain age 

degradation on internal surfaces of susceptible components, but that visual inspections of 

internal surfaces of components at the plant showed only minimal internal degradations. The 

applicant also stated the following four examples of plant operating experience which 

demonstrate the effectiveness of the relevant plant procedures on maintenance, inspections, 

walkdowns, and systems checks: 

 (1) An extensive maintenance history search and interviews with system managers for the 

ventilation systems that are within the scope of license renewal was performed and 

revealed no evidence of age-related degradation. 

 (2) Review of the 10-year inspection of the HPCI pumps, including NDE data, identified no 

evidence of degradation. 
Aging Management Review Results 

 3-46 

 (3) During a walkdown of the service water intake structure, a through wall leak was 

identified that was attributed to silt accumulation and corrosion on the interior of the 

affected piping. The affected piping was replaced satisfactorily. 

 (4) During system testing, a check valve in the HPCI system was discovered to be leaking 

past the seat. The leakage was attributed to build up of corrosion products, and the seat 

was repaired and returned to service satisfactorily. 

The applicant further stated that these examples provide objective evidence that existing plant 

activities identify nonsafety-related failures prior to significant impact on adjacent safety-related 

SSCs and that identified failures are evaluated and corrective actions are taken to preclude 

recurrence. 

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 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. LRA Section A.2.1.26 provides the UFSAR supplement for the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff 

reviewed this UFSAR supplement description of the program and notes 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 notes that the applicant committed (Commitment No. 26) 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 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 Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components, the staff finds all program elements 

consistent with the GALL Report. The staff concludes that the applicant has demonstrated that 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 
Aging Management Review Results 

 3-47 

3.0.3.1.15 ASME Section XI, Subsection IWF 

Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the 

existing ASME Section XI, Subsection IWF Program as consistent with GALL AMP XI.S3, 

“ASME Section XI, Subsection IWF.” The applicant’s ASME Section XI, Subsection IWF 

Program consists of periodic ISI including visual examination of Classes 1, 2, 3, and metal 

containment (MC) component supports. They are inspected for loss of material, and loss of 

mechanical function in indoor air, outdoor air, and treated water environments. Bolting for 

supports is also included with these components and inspected for loss of material and preload 

by inspecting for missing, detached, or loosened bolts and nuts in indoor air, outdoor air, and 

treated water environments. According to the applicant, the program relies on the design 

change procedures that are based on EPRI TR-104213 guidance to ensure proper specification 

of bolting material, lubricant, and installation torque. Identified degradation concerns are 

entered in the corrective action program for evaluation or correction to ensure the intended 

function of the affected component support is maintained. The applicant also stated that the 

program is implemented through corporate and station procedures, which provide inspection 

and acceptance criteria consistent with the requirements of ASME Section XI, Subsection IWF 

2001 Edition through the 2003 Addenda as approved in 10 CFR 50.55a. The applicant further 

stated that the ISI program is updated each successive 120-month inspection interval to comply 

with the requirements of the latest edition of the ASME Code specified 12 months before the 

start of the inspection interval in accordance with 10 CFR 50.55a(g)(4)(ii). 

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 whether 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 AMP XI.S3. 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 

AMP XI.S3, with the exception of the “scope of the program” program element. For this 

element, the staff determined the need for additional clarification, which resulted in the issuance 

of an RAI. 

GALL AMP XI.M18, “Bolting Integrity,” states that GALL AMP XI.S3, “ASME Section XI, 

Subsection IWF,” manages inspection of safety-related bolting. However, the applicant stated 

that its Bolting Integrity Program follows information that is delineated in NUREG-1339, 

published in EPRI NP-5769 guidelines, and recommended by industry. Although recommended 

inspections for SCC to prevent or mitigate degradation and failure of structural bolts with actual 

yield strength of 150,000 pounds per square inch (psi) are provided in EPRI NP-5769, EPRI 

TR-104213, and NUREG-1339, the applicant stated in LRA Section 3.5.2 that American Society 

for Testing and Materials (ASTM) A490 bolts have high resistance to SCC due to their ductility, 

and industry and plant-specific operating experience has not identified SCC of ASTM A490 bolts 

as a concern. To understand the basis for the applicant’s statement, the staff needed additional 

information from the applicant to verify that its ASME Section XI, Subsection IWF Program is 

consistent with GALL AMP XI.S3. By letter dated May 14, 2010 (ADAMS Accession 

No. ML101060155), the staff issued RAI B.2.1.29-01 requesting that the applicant explain the 

basis for the conclusion that ASTM A490 bolts have resistance to SCC due to their ductility 

because published data indicate that ASTM A490 bolts have high hardness and are not ductile. 

In its response dated June 14, 2010, the applicant stated that three parameters must exist for 

SCC to occur in high-strength bolting. These parameters include: (1) a corrosive environment, 
Aging Management Review Results 

 3-48 

(2) a susceptible material, and (3) high-sustained tensile stresses. The absence of any one of 

these three parameters eliminates the material’s susceptibility to SCC. The applicant further 

stated that high-strength A490 bolting material used in nuclear steam supply system (NSSS) 

Class 1 component supports (RPV support) at HCGS is exposed to a normally noncorrosive 

indoor-air environment in containment and that lubricants containing molybdenum disulfide or 

unacceptable levels of contaminants are not approved for use on these bolts. Additionally, the 

bolts are not subject to high-sustained preload stress. Therefore, the applicant concluded that 

SCC is not considered an applicable aging mechanism requiring management. To further 

support this conclusion, the applicant also stated that “a review of industry documents, industry 

and site specific operating experience, and the fact that not all three parameters required for 

SCC are present, cracking due to SCC of ASTM A490 bolts was determined not to be an aging 

effect requiring management at Hope Creek Generating Station during the period of extended 

operation.” 

The staff finds this program acceptable because the applicant does not subject high-strength 

ASTM A490 bolts to unacceptable levels of contaminants or corrosive environments that can 

cause SCC. In addition, according to LRA Section B.2.1.12, A490 bolts used for NSSS Class 1 

RPV supports were installed with a preload of 105,000 psi, which is less than the minimum yield 

strength of 130,000 psi of these bolts. The staff’s concern described in RAI B.2.1.29-01 is 

resolved. 

Based on its audit and review of the applicant’s response to RAI B.2.1.29-01, the staff finds that 

elements one through six of the applicant’s ASME Section XI, Subsection IWF Program are 

consistent with the corresponding program elements of GALL AMP XI.S3 and, therefore, 

acceptable. 

Operating Experience. LRA Section B.2.1.29 summarizes operating experience related to the 

ASME Section XI, Subsection IWF Program. The first example of operating experience 

described by the applicant in LRA Section B.2.1.29 occurred during ASME Code Section XI, 

Subsection IWE inspections. In 2003, the applicant indicated that the ASME Section XI, 

Subsection IWE inspections identified light to heavy rust on nuts and washers for two bolts 

installed on a torus horizontal restraint (MC support). These bolts, nuts, and washers are 

components of the torus horizontal restraint which is managed by the ASME Section XI, 

Subsection IWF Program. Although the applicant noted that there was no measurable loss of 

material, the condition was entered in the corrective action program for evaluation. As a result, 

the remaining torus lateral restraint bolts, nuts, and washers were inspected during the next 

refueling outage (RF12). During this inspection, light to heavy rust was found on additional 

washers and nuts. Corrective actions were initiated to remove the rust from the washers and 

nuts. After the rust was removed, the supports were inspected, evaluated, and found 

acceptable for continued service without repair or replacement. 

As another example of operating experience, the applicant stated that in 2006, eight ASME 

Classes 1, 2, 3, and MC component supports were subjected to VT-3 in accordance with ASME 

Section XI, Subsection IWF. The supports were inspected for degradation including corrosion, 

distortion, spring can functionality and settings, loose bolts and nuts, debris, and foreign 

material. The applicant reports that VT-3 qualified examiners observed no unacceptable 

indications. Also in 2006, the applicant identified one broken concrete anchor on the support for 

the 1-inch diameter service water pump lube water line and replaced the anchor in accordance 

with the HCGS Repair, Replacement Program. The replaced anchor was found broken during a 

service water intake structure walkdown. The applicant reported that corrosion due to service 

water leakage or spray was suspected as the failure mechanism for the anchor. An engineering 
Aging Management Review Results 

 3-49 

evaluation concluded that the support was capable of performing its intended function with 

consideration for the remaining concrete anchors, but recommended the repair to restore the 

support to its design configuration. As a part of the extent of condition determination, similar 

supports at the service water intake structure were inspected. The inspections identified no 

additional broken concrete anchors. 

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 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. LRA Section A.2.1.29 provides the UFSAR supplement for the ASME 

Section XI, Subsection IWF Program. The staff reviewed this UFSAR supplement description of 

the program and notes that it conforms to the recommended description for this type of program 

as described in SRP-LR Table 3.5-2. The staff also notes that the applicant committed 

(Commitment No. 29) to ongoing implementation of the existing ASME Section XI, Subsection 

IWF Program for managing aging of applicable components during 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 review of the applicant’s ASME Section XI, Subsection IWF 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended 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). 

3.0.3.1.16 10 CFR Part 50, Appendix J 

Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the 

existing 10 CFR 50, Appendix J Program as consistent with GALL AMP XI.S4, “10 CFR Part 50, 

Appendix J.” The LRA further states that the program assures leakage through the primary 

containment and systems and components penetrating primary containment do not exceed 

allowable leakage rate limits in the TSs. The LRA further states that the program does not 

prevent degradation but provides measures for monitoring to detect degradation prior to the loss 
Aging Management Review Results 

 3-50 

of intended function. HCGS is implementing Option B of the program, which allows the testing 

intervals to be performance based. 

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 whether 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 AMP XI.S4. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.S4. Based on its 

audit, the staff finds that elements one through six of the applicant’s 10 CFR 50, Appendix J 

Program are consistent with the corresponding program elements of GALL AMP XI.S4 and, 

therefore, acceptable. 

Operating Experience. LRA Section B.2.1.30 summarizes operating experience related to the 

10 CFR 50, Appendix J Program. The applicant stated that the cumulative maximum leakage 

test results at HCGS in 2007 were approximately 40 percent of the total allowable limit specified 

in the TSs. The applicant further stated that a focused area self-assessment conducted for the 

10 CFR 50, Appendix J Program was completed in 2007 and the overall rating of the program 

was satisfactory. The applicant also provided documented notices of local leak-rate test (LLRT) 

failures where the initial LLRT exceeded the inservice testing (IST) limit. For these cases, the 

10 CFR 50, Appendix J program engineer determined that the leakage above the IST limit 

would not have a significant safety impact on HCGS or result in an increased radiological dose 

to the test performers. Therefore, the applicant determined that the current leakage is 

acceptable until the LLRT performance in the next refueling outage. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant 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 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. LRA Section A.2.1.30 provides the UFSAR supplement for the 

10 CFR 50, Appendix J Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.5-2. The staff also notes that the applicant committed 

(Commitment No. 30) to ongoing implementation of the existing 10 CFR 50, Appendix J 

Program for managing aging of applicable components during the period of extended operation. 
Aging Management Review Results 

 3-51 

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 review of the applicant’s 10 CFR 50, Appendix J Program, the 

staff finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.17 Protective Coating Monitoring and Maintenance 

Summary of Technical Information in the Application. LRA Section B.2.1.34 describes the 

existing Protective Coating Monitoring and Maintenance Program as consistent with GALL 

AMP XI.S8, “Protective Coating Monitoring and Maintenance Program.” The applicant stated 

that the Protective Coating Monitoring and Maintenance Program is an existing program that 

manages cracking, blistering, flaking, peeling, and delamination of Service Level 1 coatings 

subjected to indoor air in the containment structure. The applicant’s Protective Coating 

Monitoring and Maintenance Program defines a Service Level 1 coating as a coating system 

used in areas in reactor containment where the coating failure could adversely affect the 

operation of post-accident fluid systems and thereby impair safe shutdown, which is consistent 

with RG 1.54, Revision 1. 

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 whether 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 AMP XI.S8. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.S8. Based on its 

audit, the staff finds that elements one through six of the applicant’s Protective Coating 

Monitoring and Maintenance Program are consistent with the corresponding program elements 

of GALL AMP XI.S8 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.34 summarizes operating experience related to the 

Protective Coating Monitoring and Maintenance Program. The applicant provided the following 

examples of operating experience as objective evidence that the Protective Coating Monitoring 

and Maintenance Program will be effective in assuring that intended function(s) will be 

maintained consistent with the CLB for the period of extended operation: 

 (1) In 2001, an inspection of the HCGS Service Level 1 coatings was performed during the 

refueling outage. The inspection methodology was based on the guidelines of 

ASTM D 5163. The inspections covered five areas: (1) primary containment outside of 

the torus, (2) drywell at elevations - feet and 109 through 127 feet, (3) drywell head and 

flange, (4) interior of the torus, and (5) drywell at elevation 87 feet. The inspection 

consisted of visual examinations, including references to industry pictorial standards, on 

the various metal and concrete surfaces in the selected areas. The summary of 

inspections in the coatings report indicated that the coatings applied to metal and 

concrete surfaces were in good condition. Recommendations were made for future 

maintenance work in the drywell and torus and documented in the corrective action 
Aging Management Review Results 

 3-52 

program. This example provides objective evidence that the Protective Coating 

Monitoring and Maintenance Program is effective in monitoring, trending, and assessing 

the condition of the Service Level 1 coatings and documenting coating conditions. 

 (2) In 2004, a diver inspection was performed in the torus during the refueling outage. The 

purpose of the inspection was to assess the conditions of the underwater torus coatings 

and underlying metallic surfaces of the torus. The inspectors found 39 areas with 

coating deficiencies, all of which were due to mechanical damage as opposed to other 

forms of disbondment such as cracking, peeling, and delamination. The loss of material 

due to corrosion of the underlying steel (maximum loss was measured at 28 mils) at the 

areas of the 39 identified coating deficiencies was within the acceptance criteria of 

94 mils. Although the mechanism of the coating deficiencies were not related to the 

coatings’ ability to adhere to the substrate and that the observed loss of material on the 

torus metal surfaces were within the acceptance criteria, coating repairs were performed 

during the 2004 refueling outage. This example provides objective evidence that the 

Protective Coating Monitoring and Maintenance Program is effective in assessing and 

correcting the conditions of the Service Level 1 coatings underwater in the torus. 

 (3) During the 2009 refueling outage, the HCGS Service Level 1 coatings in the drywell 

were inspected following the guidelines of ASTM D 5163. Due to limited access, the 

coatings assessment was limited to coatings applied to steel and concrete surfaces at 

elevations 102 feet and 87 feet. The first area assessed was the concrete floor to 

drywell shell interface at elevation 87 feet to determine the condition of the coatings. 

The coatings did not exhibit any signs of peeling or delamination. There was no visible 

corrosion on the drywell shell. The remaining coating inspections consisted of visual 

examinations on the various metal and concrete coated surfaces. The summary of 

inspections in the coatings report indicated that the coatings applied to metal and 

concrete surfaces were in good condition. There were many instances of small areas of 

mechanically-damaged coatings bounded by sound coatings. These conditions were 

documented in the corrective action program and were satisfactorily addressed in the 

2009 refueling outage. This example provides objective evidence that the Protective 

Coating Monitoring and Maintenance Program is effective in assessing and correcting 

the conditions of the Service Level 1 coatings. 

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 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. 
Aging Management Review Results 

 3-53 

UFSAR Supplement. LRA Section A.2.1.34 provides the UFSAR supplement for the Protective 

Coating Monitoring and Maintenance Program. The staff reviewed this UFSAR supplement 

description of the program and notes that it conforms to the recommended description for this 

type of program as described in SRP-LR Table 3.5-2. The staff also notes that the applicant 

committed (Commitment No. 34) to ongoing implementation of the existing Protective Coating 

Monitoring and Maintenance Program for managing aging of applicable components during the 

period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Protective Coating Monitoring 

and Maintenance Program, the staff finds all program elements consistent with the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.18 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

Summary of Technical Information in the Application. LRA Section B.2.1.35 describes the new 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program as consistent with GALL 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 

Environmental Qualification Requirements Program manages embrittlement, cracking, swelling, 

surface contamination, or discoloration to ensure that electrical cables, connections, and 

terminal blocks not subject to the EQ requirements of 10 CFR 50.49 but are within the scope of 

license renewal and are capable of performing their intended functions. 

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 whether 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 AMP XI.E1. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL 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 Environmental Qualification Requirements Program 

are consistent with the corresponding program elements of GALL AMP XI.E1 and, therefore, 

acceptable. 

Operating Experience. LRA Section B.2.1.35 summarizes operating experience related to the 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program. The applicant stated that in April 17, 2006, a motor lead damaged by 

heat exposure was visually discovered at HCGS. An engineering evaluation of the cable 

condition was performed. The damaged portion of the cable was removed and new cable was 

spliced into place to eliminate the heat-damaged cable completely. The applicant also stated 

that in March 2, 2004, a power cord in the radiation monitoring system was visually discovered, 
Aging Management Review Results 

 3-54 

by an engineer during a periodic system walkdown, to have a degraded outer insulation (jacket). 

The power cable was replaced prior to any loss of function in accordance with the corrective 

action program. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant 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 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. 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.2.1.35 provides the UFSAR supplement for the Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualifications 

Requirements Program. The staff reviewed this UFSAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.6-2. The staff also notes that the applicant committed 

(Commitment No. 35) to implement the new Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program prior to entering the period of 

extended operation for managing aging of applicable components. 

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 review of the applicant’s Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff finds all 

program elements consistent with the GALL Report. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.1.19 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.2.1.36 describes the new 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits Program as consistent with GALL 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 Environmental Qualification Requirements Used 
Aging Management Review Results 

 3-55 

in Instrumentation Circuits Program manages the in-scope portions of the radiation monitoring 

system, and the neutron monitoring system not included in the EQ program. This program 

applies to sensitive instrumentation cable and connection circuits with low-level signals that are 

within the scope of license renewal and are located in areas where the cables and connections 

could be exposed to adverse localized environments caused by heat, radiation, or moisture. 

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 whether 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 AMP XI.E2. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL 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 Environmental Qualification Requirements Used in 

Instrumentation Circuits Program are consistent with the corresponding program elements of 

GALL AMP XI.E2 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.36 summarizes operating experience related to the 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits Program. The applicant stated that, in 

November 2004, a common cause analysis was initiated in response to an adverse trend with 

problems with instrumentation cables located under the reactor vessel. The applicant found 

water collecting on the top of the sleeve, which eventually caused leaking of water into the 

connector. The problem was resolved by removing the sleeves to improve the cable water 

resistance. The applicant also stated that, in April 2002, a degraded sensor cable was 

discovered on the turbine building circulating water sump radiation monitor. A radiation monitor 

spiked, tripping the turbine building circulating water sump. The cable was later replaced and 

the detector checked. 

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 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. 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.2.1.36 provides the UFSAR supplement for the Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits Program. The staff reviewed this UFSAR 

supplement description of the program and notes that it conforms to the recommended 
Aging Management Review Results 

 3-56 

description for this type of program as described in SRP-LR Table 3.6-2. The staff also notes 

that the applicant committed (Commitment No. 36) to implement the new Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits Program prior to entering the period of extended operation for 

managing aging of applicable components. 

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 review of the applicant’s Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation 

Circuits Program, the staff finds all program elements consistent with the GALL Report. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.20 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

Summary of Technical Information in the Application. LRA Section B.2.1.37 as supplemented 

by letter dated September 7, 2010, and September 30, 2010, describes the new Inaccessible 

Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program as consistent with GALL AMP XI.E3, “Inaccessible Medium Voltage 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The applicant 

stated that its program manages inaccessible power cables (480 volts (V), 4,160V, and 

13,800V) that are exposed to significant moisture simultaneously with significant voltage. The 

applicant stated that significant moisture is defined as periodic exposure to moisture that lasts 

more than a few days (e.g., cable in standing water). The applicant also stated that significant 

voltage exposure is defined as being subject to system voltage for more than 25 percent of the 

time. The applicant noted that no inaccessible power cable exposed to significant moisture was 

excluded from the program due to the “significant voltage” criterion. The applicant further stated 

that in-scope, non-EQ, inaccessible power cables subject to significant moisture and voltage will 

be tested as part of this AMP. The applicant stated that these power cables will be tested using 

a proven test for detecting deterioration of the insulation system due to wetting, such as power 

factor, partial discharge, or polarization index as described in EPRI TR-103834-P1-2, or other 

testing that is state-of-the-art at the time the test is performed. Finally, the applicant stated that 

the cable test frequency will be established based on test results and industry operating 

experience. The maximum time between tests will be no longer than 6 years. The applicant 

further stated that the first tests will be completed prior to the period of extended operation. 

The applicant stated that prior to the period of extended operation, manholes and cable vaults, 

associated with cables included in this AMP, will be inspected for water collection with water 

removal done as necessary. In-scope, non-EQ, inaccessible power cables subject to significant 

moisture and voltage will be evaluated, so that draining or other corrective actions can be taken. 

The applicant also stated that the objective of the inspections, as a preventive action, is to 

minimize the exposure of power cables to significant moisture. The frequency of inspections for 

accumulated water will be established based on inspection results. The applicant further stated 

that this approach to determining the inspection frequency recognizes a recurring inspection, set 

at the optimum frequency, would result in the cables being submerged only as a result of event 
Aging Management Review Results 

 3-57 

driven, rain and drain, type occurrences and that station procedures will direct the assessment 

of the cable condition as a result of rain or other event driven occurrences. The applicant stated 

that sufficient manhole and cable vault inspections will be performed prior to the period of 

extended operation so that proper inspection frequencies are established to minimize the 

exposure of power cables to significant moisture during the period of extended operation. 

Finally, the applicant stated that the maximum time between inspections will be no more than 

1 year. 

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 whether 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 AMP XI.E3. 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 

AMP XI.E3. Based on its audit, the staff finds that elements one through six of the applicant’s 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program are consistent with the corresponding program elements of GALL 

AMP XI.E3 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.37 summarizes operating experience related to the 

applicant’s Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program. The applicant stated that, in response to GL 2007-01, 

“Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation Systems 

or Cause Plant Transients,” the plant has no history of failures of inaccessible or underground 

medium or low (480V or greater) voltage power cables. 

The LRA provided examples of operating experience that the applicant stated provided 

objective evidence that the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program will be effective in assuring that intended 

functions will be maintained consistent with the CLB for the period of extended operation. 

Examples include: 

 (1) References to testing of a representative sample of medium voltage cables as part of 

existing maintenance procedures for megger testing rotating electrical equipment and 

associated power cables. 

 (2) Reference to August 2007 standing water and potential flooding of cable vaults 

containing motor feed and control cable for service water. Corrective action consisted of 

re-grading the yard area to minimize rainwater from pooling on the vaults and conducting 

inspections of two cable vaults and pumping water from these vaults due to cable 

submergence identified in the vaults. The cable vault structure was found to be in good 

material condition. 

 (3) The applicant’s February 2008 self-assessment of critical medium voltage underground 

cable and the applicant’s follow-up actions to develop a test program and institute 

preventive maintenance activities. 

Based on these examples, the applicant stated that detection methods exist to identify aging 

effects and prevent the loss of intended function, corrective actions have accounted for industry 

operating experience, and industry operating experience will be used to improve the program 
Aging Management Review Results 

 3-58 

such that, if any aging effects do occur, they would be detected prior to loss of intended 

function. 

The staff reviewed the operating experience 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 applicant’s plant operating experience information to determine 

whether the applicant had adequately incorporated and evaluated operating experience related 

to this program. Furthermore, the staff performed a search of regulatory operating experience 

for the period 2000 through November 2009. Databases were searched using various 

keywords and then reviewed by the technical auditor staff. 

During its review, the staff identified operating experience which needed additional clarification 

to determine if the applicant’s program will be effective in adequately managing aging effects 

during the period of extended operation. The staff’s need for additional clarification resulted in 

the issuance of an RAI. 

Prior to the license renewal AMP audit in June 2009, the applicant inspected manholes 

associated with medium voltage cables for the “C” service water pump. Each manhole includes 

separate vaults per train with a separate cover for each vault. There are a total of three 

manholes. Two manholes contain vaults for two service water trains (A and C) and (D and B), 

respectively. The third manhole contains four separate vaults, one for each service water train 

(A, B, C, and D). The applicant’s inspection of the “C” vaults found standing water in both vaults 

with the “C” train service water medium voltage cables submerged. The applicant generated a 

condition report to address the standing water in the “C” service water vaults. The condition 

report also included the service water A, B, and D trains based on the expectation that 

scheduled follow-on inspections would also find submerged cables in these vaults. The 

applicant noted in the condition report that the duct banks containing the service water medium 

voltage cables are designed to drain water away from the service water building and reactor 

building into the manholes and vaults, but there is no drainage system to remove water from the 

vaults. The condition report noted that the vaults contain sumps, but that sump pumps were 

never installed. 

The “A” vaults were inspected in September 2009 and also found to have standing water and 

submerged service water medium voltage cables. The staff was present during this inspection 

and observed the vaults once they were pumped out. The staff also noted that the service 

water medium voltage cables contained splices at both “A” vault locations. During this site visit, 

the staff also reviewed inspections findings and photographs of the previous “C” service water 

vault inspection. In November 2009, both the “B” and “D” vaults were inspected by the applicant 

with standing water and medium voltage cable submergence also noted for these vaults. The 

staff was present for the “D” vault inspections and also discussed cable test results and 

inspection results for the “B” vault. The staff again noted that the service water medium voltage 

cables contained splices at both “D” vault locations. The staff confirmed that service water 

medium voltage cable splices were also located in the “C” and “B” vault locations. 

On September 30, 2009, the staff issued an integrated inspection report (Report 

#05000354/2009004) for HCGS and identified submerged medium voltage cable associated 

with “A” and “C” service water medium voltage cable inspections. The inspection report notes 

that the inspectors verified that the applicant conducted an adequate operability evaluation 

associated with the cables and identified appropriate corrective action. The report also states 

that the inspectors verified the integrity of cables and splices and the condition of the cable 
Aging Management Review Results 

 3-59 

support structure. The inspection report identified the “A” and “C” submerged service water 

medium voltage cables as a non-cited violation of very low safety significance (green) since it 

did not represent an actual loss of safety function or contribute to external event core damage 

sequences. 

During the audit, the staff also interviewed HCGS personnel and reviewed documentation for 

in-scope medium voltage inaccessible cables associated with station blackout (SBO) to 

determine whether these cables were also subject to submergence. The applicant stated that 

the manholes and one cable pit associated with SBO were inspected in July 2009, and cable 

submergence was noted during these inspections. The staff was concerned that the applicant’s 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program may not be adequate based on current operating experience with 

submerged cables. 

By letter dated May 14, 2010, the staff issued RAIs B.2.1.37-1 and B.2.1.37-2 requesting that 

the applicant explain how LRA Section B.2.1.37 meets GALL AMP XI.E3 for in-scope, 

inaccessible medium voltage cables (including SBO recovery cables) based on plant operating 

experience that shows in-scope inaccessible medium voltage cables exposed to significant 

moisture (more than a few days). 

Regarding plant-specific operating experience with submerged service water cables, the staff 

requested in RAI B.2.1.37-1 that the applicant: 

Describe how HCGS LRA AMP B.2.1.37 meets GALL AMP XI.E3 considering 

that operating history shows that the in-scope inaccessible medium voltage cable 

are exposed to significant moisture (i.e., exposure lasting more than a few days). 

In addition, (a) describe how plant operating experience were incorporated into 

AMP B.2.1.37 to minimize exposure of in-scope inaccessible medium voltage 

cables to significant moisture during the period of extended operation, (b) discuss 

manhole and vault inspections (including event-driven significant moisture 

exposure such as rain) and how adjustments and modifications will be made 

based on operating experience to minimize cable exposure to significant 

moisture, (c) discuss any corrective actions taken that address submerged cable 

conditions and cable support structure degradation identified through manhole 

and vault inspection, and (d) discuss cable testing frequency and applicability 

that demonstrates in-scope, inaccessible medium voltage cables will continue to 

perform their intended function during the period of extended operation. 

The applicant responded by letters dated June 14, 2010, and August 9, 2010, and stated: 

The Hope Creek LRA AMP B.2.1.37, Inaccessible Medium Voltage Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, is 

a new program that is currently in the process of being implemented at Hope 

Creek. This program includes (1) testing of in-scope, inaccessible medium 

voltage cables subject to significant moisture and significant voltage and (2) 

inspection of cable vaults, including subsequent pumping of accumulated water if 

required, as a preventive measure to minimize the potential exposure of in-scope 

cables to significant moisture. 

Specifically, each of the in-scope service water cables was tested between 

September and November 2009. The cable test results determined that all of the 

in-scope service water cable insulations are in good condition. In-scope service 
Aging Management Review Results 

 3-60 

water cable testing will continue to be conducted periodically [every 18 months] 

during their associated service water pump motor outages. The cable test 

frequency may be adjusted based on data trending in accordance with the 

corrective action process. 

Plant-specific operating experience has identified cable vault water accumulation 

resulting in exposure of the in-scope service water cable to significant moisture. 

This condition was reported and evaluated in the corrective action process. 

Based on this identified operating experience and in accordance with the 

corrective action process, Hope Creek has commenced periodic inspections of 

the in-scope service water cables, and removing accumulated water as required, 

to monitor the in-scope service water cables. The service water cable vaults are 

currently inspected for water accumulation weekly. Trending and 

characterization of the water intrusion rate allow adjustments to the service water 

cable vault inspection frequency in accordance with the corrective action 

process. 

The applicant also stated that the Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program implementation plan 

includes, prior to the period of extended operation, additional service water cable vault 

inspections will be performed and the frequency of inspections for accumulated water will be 

adjusted based on inspection results to ensure that the in-scope service water cables are not 

exposed to significant moisture. The maximum time between inspections will be no longer than 

2 years, which meets the recommended frequency in GALL AMP XI.E3. 

The applicant also stated that the Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements meets GALL AMP XI.E3 for the 

in-scope service water cable because initial tests have been implemented and will be 

periodically performed (not to exceed 10 years) and, prior to the period of extended operation, 

the frequency of inspections for accumulated water will be established (not to exceed 2 years) 

based on inspection results to ensure that in-scope service water cables are not exposed to 

significant moisture during the period of extended operation. 

The applicant further stated that physical modifications have been made to the service water 

cable vault lids to allow more frequent inspections and water pumping. The applicant also 

stated that the cable vault lid feature also accommodates future adjustments in inspection 

frequency including assessing the cable condition as a result of rain or other event-driven 

occurrences as directed by station procedures (e.g., hurricane, tropical storm, or coastal 

flooding warnings issued for the site area prompts the inspection and assessment of the cable 

vaults for water accumulation). 

The applicant did not identify concrete-related issues or conditions adverse to quality for the 

service water cable vault structures. During the service cable vault inspection, the applicant 

noted that most cable supports experienced failure of the galvanized surface coating, but no 

degradation of the structural integrity of the steel structure was observed. The applicant stated 

that corrective actions have been initiated to repair the galvanized steel coating on the cable 

supports. 
Aging Management Review Results 

 3-61 

Regarding plant-specific operating experience with submerged SBO cables, the staff requested 

in RAI B.2.1.37-2 that the applicant: 

Describe how HCGS LRA AMP B.2.1.37 meets GALL AMP XI.E3 for in-scope 

inaccessible medium voltage SBO recovery cables considering that operating 

history shows that the in-scope inaccessible medium voltage SBO recovery 

cables are exposed to significant moisture (i.e., exposure lasting more than a few 

days). In addition, (a) describe how plant operating experience were 

incorporated into AMP B.2.1.37 to minimize exposure of SBO in-scope 

inaccessible medium voltage cables to significant moisture during the period of 

extended operation, (b) discuss any corrective actions taken that addresses 

submerged cable conditions and cable support structure degradation identified 

through manhole/vault inspections, and (c) discuss cable testing frequency and 

applicability that demonstrates in-scope, inaccessible medium voltage cable will 

continue to perform their intended function during the period of extended 

operation 

The applicant responded by letters dated June 14, 2010, and August 9, 2010, and stated: 

The Hope Creek LRA AMP B.2.1.37, Inaccessible Medium Voltage Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements, is a new 

program that is currently in the process of being implemented a Hope Creek. 

This program includes (1) testing of in-scope, inaccessible medium voltage 

cables subject to significant moisture and significant voltage and (2) inspection of 

cable manholes, including subsequent pumping of accumulated water if required, 

as a preventive measure to minimize the potential exposure of in-scope cables to 

significant moisture. 

Specifically, Hope Creek will perform cable testing of the in-scope SBO recovery 

cables during their associated transformer outages. The first test is scheduled 

for October 2010. The current plan is to test the in-scope SBO recovery cables 

periodically during their associated transformer outages. The cable test 

frequency may be adjusted based on data trending. 

Plant-specific operating experience has identified cable vault water accumulation 

resulting in exposure of the in-scope SBO recovery cables to significant moisture. 

This condition was reported and evaluated in the corrective action process. 

Based on this identified operating experience and in accordance with the 

corrective action process, Hope Creek has commenced periodic ([every] 

18 months) inspections of the in-scope SBO recovery cable manholes/pits and 

removing accumulated water as required to monitor the in-scope SBO recovery 

cables. 

Prior to the period of extended operation, additional SBO recovery cable 

manhole inspections will be performed and the frequency of inspections for 

accumulated water will be adjusted based on inspection results to ensure that the 

in-scope SBO recovery cables are not exposed to significant moisture. The 

maximum time between inspections will be no longer than 2 years, which meets 

the recommended frequency in GALL AMP XI.E3. 

The Hope Creek LRA AMP B.2.1.37 meets GALL AMP XI.E3 for the in-scope 

SBO recovery cables because prior to the period of extended operation, cable 
Aging Management Review Results 

 3-62 

tests will be periodically performed (not to exceed 10 years) and, prior to the 

period of extended operation, the frequency of inspections for accumulated water 

will be established (not to exceed 2 years) based on inspection results to ensure 

that the in-scope SBO recovery cables are not exposed to significant moisture 

during the period of extended operation. 

In its RAI response, the applicant identified 5 manholes and 2 cable pits that are in-scope for 

SBO inaccessible medium voltage cables. The applicant stated that 3 manholes and 1 cable pit 

were inspected between April and June 2009. The applicant noted that 2 of the 3 manhole 

inspections and the cable pit inspection identified submerged cables. The applicant stated that 

the manholes were subsequently dewatered. The applicant also stated that no cable defects, 

concrete, cable support related issues or conditions adverse to quality were observed for all 

cables within these 3 manholes and 1 cable pit. The applicant did note that the cable pit 

showed evidence of a conduit failure. The condition was entered into the corrective action 

process with repairs scheduled for April 2012. The applicant further stated that the remaining 

2 manholes are planned to be inspected during the next respective transformer outages in April 

2012 (station service transformers). The applicant plans to inspect the remaining cable pit in 

October 2010. By letter dated January 19, 2011, the applicant provided updated information 

concerning SBO cable testing performed during the October 2010 refueling outage. The 

applicant stated that testing of the “B” channel of the in-scope SBO 13-kilovolt (kV) cables was 

conducted and the test results were acceptable. The applicant also stated that testing of the “A” 

channel is scheduled for 2012 with follow-up testing of the “B” channel scheduled for 2013. 

The applicant stated that as a result of this operating experience, actions have been initiated to 

establish recurring tasks to open, inspect, and dewater manholes and cable pits. The applicant 

noted that cable condition is also assessed as a result of rain or other event-driven occurrences 

as directed by station procedures. The applicant further stated that trending and characterizing 

the water intrusion rate allow adjustments to the SBO recovery cable manhole inspection 

frequency in accordance with the corrective action process. 

The applicant stated that it is planning to perform SBO recovery cable testing every 3 years 

during station service transformer outages. The applicant also stated that testing will be 

conducted periodically in order to trend and characterize the SBO recovery cable insulation 

condition. As noted above, by letter dated January 19, 2011, the applicant provided updated 

information concerning SBO cable testing that was performed during the October 2010 refueling 

outage. 

The staff has concluded, based on recently identified industry operating experience concerning 

the failure of inaccessible low voltage power cables (480V to 2kV) in the presence of significant 

moisture, that these cables can potentially experience aging effect related degradation. 

The staff was also concerned that recent industry operating experience also showed an 

increasing trend in cable failures with a length of service beginning in the 6th through 10th year 

of operation. The staff determined, based on the review of the cable failure distribution, that 

annual inspection of cable manholes and a cable testing frequency of at least every 6 years is a 

conservative approach to ensuring the operability of inaccessible power cables and, therefore, 

should be considered. The staff noted that the applicant’s Inaccessible Medium Voltage Cables 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program did not 

address inaccessible low voltage power cables. 

By teleconference dated August 16, 2010, the staff discussed with the applicant the cable test 

and manhole/vault inspection frequencies and the inclusion of inaccessible low voltage cables 
Aging Management Review Results 

 3-63 

into the scope of the applicant’s Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program based on recent industry 

operating experience. By letter dated September 7, 2010, the applicant submitted a supplement 

to the LRA to include inaccessible low voltage power cables in the scope of the Inaccessible 

Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program. The applicant stated the following: 

The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements aging management program is 

changed to include low voltage power cables (480V or greater) that are exposed 

to significant moisture. In addition, the criterion for significant voltage has been 

clarified because all inaccessible power cables (480V, 4,160V, and 13,800V) 

exposed to significant moisture at Hope Creek are included in this program. No 

inaccessible power cable exposed to significant moisture is excluded from the 

program due to the “significant voltage” criterion. Finally, operating experience 

has been updated to include the fact that there have been no underground or 

inaccessible low voltage cable failures at Hope Creek. 

The applicant revised LRA Appendix A, Section A.2.1.37, Section A.5, License Renewal 

Commitment List, Commitment No. 37, and LRA Appendix B, Section B.2.1.37 to revise the 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program to include inaccessible low voltage power cables (480V to 2kV). The 

applicant also updated operating experience to include in-scope inaccessible low voltage power 

cables stating that HCGS has no history of failures for these cables. The applicant also revised 

the LRA to state that no inaccessible power cable was excluded from the AMP due to 

“significant voltage” criterion. 

However, in its September 7, 2010, LRA supplement, the applicant did not address the effect of 

industry and plant-specific operating experience concerning inaccessible power cable tests or 

cable manhole and vault inspection frequencies referenced by GALL Report AMP XI.E3 (10 and 

2 years respectively). By teleconference dated September 9, 2010, the staff asked the 

applicant to explain why an increased cable test and cable manhole and vault inspection 

frequency for in-scope inaccessible power cables based on recent industry and plant-specific 

operating experience is not appropriate for HCGS. During the conference call, the applicant 

agreed to evaluate increased test and inspection frequencies for HCGS. By letter dated 

September 30, 2010, the applicant supplemented its LRA to change the maximum cable test 

frequency from 10 years to 6 years and the maximum cable vault and manhole inspection 

frequency from 2 years to 1 year. With the change to the applicant’s cable vault and manhole 

inspection frequencies and cable test frequencies, confirmatory item CI 3.0.3.1.20-1 is closed. 

Based on the applicant’s responses to RAIs B.2.1.37-1 and B.2.1.37-2, and information 

provided in the applicant’s LRA supplement dated September 7, 2010, and September 30, 

2010, the staff finds that: 

 (a) The applicant has appropriately expanded the program scope to include inaccessible 

low voltage power cables (480V to 2kV) and clarified that no inaccessible power cable 

was excluded based on the “significant voltage” criterion. The applicant noted that the 

increased scope to include inaccessible low voltage power cable did not result in 

additional cable vaults being added to the applicant’s Inaccessible Medium Voltage 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 

Program. 
Aging Management Review Results 

 3-64 

 (b) HCGS cable insulation testing is appropriate because: (1) it considers plant-specific and 

industry operating experience, (2) plant-specific operating experience has not revealed 

any instance of inaccessible power cable failure due to aging related effects within the 

scope of the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program, and (3) the actual frequency of 

testing may be adjusted based on test results and operating experience and is currently 

scheduled every 18 months for in-scope inaccessible service water power cables and 

every 3 years for in-scope SBO inaccessible power cables. This approach is consistent 

with the discussion of operating experience in the SRP-LR Section A.1.2.3.10, which 

states that applicants should consider plant-specific and applicable industry operating 

experience for its AMPs. 

 (c) The applicant’s inspection frequency for cable vaults and manholes and cable pits 

containing inaccessible in-scope power cables is appropriate because it takes into 

account applicable industry and plant-specific operating experience including cable vault 

and manhole and cable pit water accumulation at HCGS. The actual periodic frequency 

of inspection will be established prior to the period of extended operation based on 

inspection results and is currently weekly for in-scope service water vaults and every 

18 months for in-scope SBO manholes and cable pits. The SBO cables are normally 

energized, therefore, maintenance and inspection activities are typically scheduled 

during refueling outages. Additional inspections are performed based on event-driven 

occurrences such as rain or other event-driven occurrences as directed by station 

procedures. Given that plant-specific operating experience has shown significant water 

accumulation in cable vaults and manholes and cable pits within the scope of this AMP, 

an inspection frequency determined through inspection results and additional 

inspections based on event-driven occurrences is acceptable because the applicant’s 

current trending effort will continue to inform the program’s inspection periodicity (i.e., to 

provide feedback for changes of the inspection periodicity as appropriate). 

 (d) The applicant also addressed the effect of industry and plant-specific operating 

experience concerning inaccessible power cable test and cable manhole and vault 

inspection frequencies by changing the maximum cable test frequency from 10 years to 

6 years and the maximum cable vault and manhole inspection frequency from 2 years to 

1 year. 

The staff finds that with the enhancements described above, the Inaccessible Medium Voltage 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will 

adequately manage the aging effects of inaccessible power cables, consistent with industry 

operating experience, such that there is reasonable assurance that inaccessible power cables 

(480V and greater) subject to significant moisture will be adequately managed during the period 

of extended operation. The staff’s concern with respect to the inclusion of inaccessible low 

voltage power cables is resolved. With the resolution of confirmatory item CI 3.0.3.1.20-1, the 

staff’s concern with test and inspection frequencies is resolved. 

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

RAIs B.2.1.37-1 and B.2.1.37-2, and the LRA supplements dated September 7, 2010, and 

September 30, 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. 

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. 
Aging Management Review Results 

 3-65 

UFSAR Supplement. LRA Section A.2.1.37 provides the UFSAR supplement for the 

Inaccessible Medium Voltage Cables not subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR Table 

3.6-2. 

By letter dated May 14, 2009, the staff issued RAI B.2.1.37-4 to request that the applicant 

discuss why the LRA Appendix A, Section A.2.1.37, UFSAR summary description does not 

include definitions of significant moisture and significant voltage consistent with SRP-LR 

Table 3.6-2 and LRA Section B.2.1.37. The applicant responded by letter dated June 14, 2010, 

and stated that LRA Section A.2.1.37 is revised to include these definitions. With the 

information provided by the applicant’s RAI response, the staff finds the UFSAR supplement 

acceptable because the applicant revised LRA Section A.2.1.37 to be consistent with the 

guidance of SRP-LR Table 3.6-2. Based on the applicant’s response to RAI B.2.1.37-4, the 

staff’s concern described in RAI B.2.1.37-4 is resolved. In addition, as part of the applicant’s 

supplement to the LRA dated September 7, 2010, the applicant revised LRA Section A.2.1.37 to 

include low voltage power cables (480V or greater) to the scope of the applicant’s Inaccessible 

Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program, clarifying that no inaccessible power cables were excluded from the 

program due to the “significant voltage” criterion, and added condition-based inspections for 

manhole and cable vaults. Finally, as part of the applicant’s supplement to the LRA dated 

September 30, 2010, the applicant resolved confirmatory item CI 3.0.3.1.20-1 by addressing the 

effect of industry and plant-specific operating experience concerning inaccessible power cable 

test and cable manhole and vault inspection frequencies by changing the maximum cable test 

frequency from 10 years to 6 years and the maximum cable vault and manhole inspection 

frequency from 2 years to 1 year. With the resolution of confirmatory item CI 3.0.3.1.20-1 

concerning inspection and test frequencies, the staff determines that the applicant’s UFSAR 

supplement provides an adequate summary description consistent with guidance of SRP-LR 

Table 3.6. 

The staff also notes that the applicant committed (Commitment No. 37) to implement the new 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program prior to entering the period of extended operation for managing aging of 

applicable components. Specifically, Commitment No. 37 states: 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements is a new program that will be used to 

manage the aging effects and mechanisms of non-EQ, in-scope inaccessible 

power cables (480V, 4,160V, 13,800V) 

The cable test frequency will be established based on test results and industry 

operating experience. The maximum time between tests will be no longer than 

6 years. 

Manholes and cable vaults associated with the cables included in this aging 

management program will be inspected for water collection (with water removal 

as necessary) with the objective of minimizing the exposure of power cables to 

significant moisture. Prior to the period of extended operation, the frequency of 

inspections for accumulated water will be established based on inspection results 

to minimize the exposure of power cable to significant moisture. The maximum 

time between inspection will be no loger than one year. 
Aging Management Review Results 

 3-66 

The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements aging management program will be 

enhanced as follows: 

1. Add low voltage power cables (480 volts or greater) to the scope of the 

program. 

2. Change cable testing maximum frequency from 10 years to 6 years. 

Change cable vault and manhole inspection maximum frequency from 2 

years to 1 year. 

The staff determines 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 review of the applicant’s Inaccessible Medium Voltage Cables 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the resolution 

of RAIs and confirmatory item CI 3.0.3.1.20-1, the staff finds all program elements consistent 

with the GALL Report. The staff concludes that the applicant has demonstrated that the effects 

of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.1.21 Metal Enclosed Bus 

Summary of Technical Information in the Application. LRA Section B.2.1.38 describes the new 

Metal Enclosed Bus Program as consistent with GALL AMP XI.E4, “Metal Enclosed Bus.” The 

applicant stated that the Metal Enclosed Bus Program manages the aging of in-scope metal 

enclosed buses within the scope of license renewal to ensure that they are capable of 

performing their intended functions. The applicant also stated that internal portions of the 

in-scope metal enclosed bus enclosures will be visually inspected for cracks, corrosion, foreign 

debris, excessive dust buildup, and evidence of moisture intrusion. Furthermore, loose-bolted 

connections will be checked by sampling using thermography from outside of the metal 

enclosed bus. 

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 whether 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 AMP XI.E4. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.E4. Based on its 

audit, the staff finds that elements one through six of the applicant’s Metal Enclosed Bus 

Program are consistent with the corresponding program elements of GALL AMP XI.E4 and, 

therefore, acceptable. 

Operating Experience. LRA Section B.2.1.38 summarizes operating experience related to the 

Metal Enclosed Bus Program. The applicant stated that, in January 2006, an electrical transient 

occurred in the HCGS switchyard in an outdoor section of non-segregated metal enclosed bus 

associated with the 13.8-kV island substation. The electrical fault was due to a breakdown of 

insulation properties between bus bars caused by tracking across a dislodged insulating boot. 
Aging Management Review Results 

 3-67 

The cause of the dislodged insulating boot was improper installation of the bus bar protective 

boots. A lack of effective preventive maintenance also contributed to this electrical transient 

because the last corrective maintenance action occurred 10 years prior. Corrective actions 

included installing new boots with an approved design, establishing appropriate PM tasks for 

this metal enclosed bus section, and completing the extent of condition inspections of adjoining 

transformers’ metal enclosed bus sections for similar conditions. The applicant also stated that, 

in March 2005, the applicant found deterioration of an alignment cover on the outdoor portions 

of metal enclosed bus during a visual inspection. The alignment cover is a protective covering 

over the links, comprised of a neoprene rubber material. A total of eight alignment joint 

assemblies were subsequently replaced or repaired. The bus enclosures were found to be 

clean, with no evidence of overheating of bus connections. 

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 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. 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.2.1.38 provides the UFSAR supplement for the Metal 

Enclosed Bus Program. The staff reviewed this UFSAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.6-2. The staff also notes that the applicant committed 

(Commitment No. 38) to implement the new Metal Enclosed Bus Program prior to entering the 

period of extended operation for managing aging of applicable components. 

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 review of the applicant’s Metal Enclosed Bus Program, the staff 

finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 
Aging Management Review Results 

 3-68 

3.0.3.1.22 Environmental Qualification (EQ) of Electric Components 

Summary of Technical Information in the Application. LRA Section B.3.1.2 describes the 

existing EQ of Electric Components Program as consistent with GALL AMP X.E1, 

“Environmental Qualification (EQ) of Electric Components Program.” The applicant also stated 

that the EQ of Electric Components Program manages the effects of thermal, radiation, and 

cyclic aging through the use of aging evaluations in adverse localized environments. The 

applicant stated that program activities establish, demonstrate, and document the level of 

qualification, qualified configuration, maintenance, surveillance, and replacement requirements 

necessary to meet 10 CFR 50.49, “Environmental Qualification of Electric Equipment Important 

to Safety for Nuclear Power Plants.” The applicant further stated that qualified life is determined 

for equipment within the scope of the EQ of Electric Components Program, and that appropriate 

actions, such as replacement, refurbishment, or reanalysis, are taken prior to or at the end of 

the qualified life of the equipment so that the aging limit is not exceeded. The applicant also 

stated that the program ensures maintenance of the qualified life for electrical equipment within 

the scope of the EQ of Electric Components Program through the period of extended operation. 

As required by 10 CFR 50.49, EQ program components not qualified for the current license term 

are refurbished, replaced, or have their qualification extended prior to reaching the aging limits 

established in the evaluations. Aging evaluations for EQ program components are TLAAs for 

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 whether 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 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 

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 AMP X.E1 and, therefore, acceptable. 

Operating Experience. LRA Section B.3.1.2 summarizes operating experience related to the 

EQ of Electric Components Program. The applicant stated its program is an existing program, 

which implements preventive activities to ensure that the qualified life of components within the 

scope of the program is maintained through the period of extended operation. The applicant 

also stated that the effects of aging are effectively managed by objective evidence that 

demonstrates that aging effects and mechanisms are adequately managed. 

The applicant’s operating experience includes the use of actual area temperature data to 

assess the impact on the qualified life of the HPCI pump motor, indicating that the program is 

capable of addressing changing plant conditions and assessing the EQ impact on components. 

Additional examples include actions to improve scheduling of EQ work orders including 

improved accounting for procurement lead times and outages and a program to convert EQ files 

to electronic format that included a re-evaluation of maintenance frequencies and benchmarking 

of EQ program files. The applicant stated these examples demonstrate that its program 

addresses changing plant conditions, and identifies and incorporates corrective actions and EQ 

program improvement. 
Aging Management Review Results 

 3-69 

The staff reviewed the operating experience 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 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. LRA Section A.3.1.2 provides the UFSAR supplement for the EQ of 

Electric Components Program. 

The staff reviewed this UFSAR supplement description of the program and notes that, in 

conjunction with the TLAA UFSAR supplement A.4.4, it conforms to the recommended 

description for this type of program as described in SRP-LR Table 4.4-2. 

The staff also notes that the applicant committed (Commitment No. 47) to ongoing 

implementation of the existing EQ of Electric Components Program for managing aging of 

applicable components during the period of extended operation. 

The staff determines 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 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 has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2 AMPs That Are Consistent with the GALL Report with Exceptions or 

Enhancements 

In LRA Appendix B, the applicant identified the following AMPs that were, or will be, consistent 

with the GALL Report, with exceptions or enhancements: 

● Water Chemistry 

● BWR Stress Corrosion Cracking 

● Flow-Accelerated Corrosion 
Aging Management Review Results 

 3-70 

● Bolting Integrity 

● Closed-Cycle Cooling Water System 

● Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

● Fire Protection 

● Fire Water System 

● Aboveground Steel Tanks 

● Fuel Oil Chemistry 

● Reactor Vessel Surveillance 

● Buried Piping Inspection 

● Lubricating Oil Analysis 

● ASME Section XI, Subsection IWE 

● Masonry Wall Program 

● Structures Monitoring Program 

● RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants” 

● Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements 

● Metal Fatigue of Reactor Coolant Pressure Boundary 

For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions or 

enhancements, the staff performed an audit 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 exceptions and enhancements to the GALL Report to 

determine whether they were acceptable and adequate. The results of the staff’s audit and 

reviews are documented in the following sections. 

3.0.3.2.1 Water Chemistry 

Summary of Technical Information in the Application. LRA Section B.2.1.2 describes the 

existing Water Chemistry Program as consistent, with exceptions, with GALL AMP XI.M2, 

“Water Chemistry.” The applicant stated that its program monitors and controls the chemical 

environments of those systems that are exposed to reactor water, steam, condensate and 

feedwater, CRD water, demineralized water storage tank water, condensate storage tank water, 

torus water, and spent fuel pool (SFP) water. The program manages the aging effects of 

cracking, loss of material, reduction of neutron-absorbing capacity, and reduction of heat 
Aging Management Review Results 

 3-71 

transfer for components exposed to sodium pentaborate, steam, and reactor coolant 

environments. The applicant also stated that its Water Chemistry Program follows the 

guidelines in EPRI 1008192, BWRVIP-130, “BWR Vessel and Internals Project BWR Water 

Chemistry Guidelines EPRI TR-1008192” (2004), which is a later revision of BWRVIP-29 (1994) 

and is consistent with the GALL Report, which recommends following industry guidelines of 

BWRVIP-29 (EPRI TR-103515), or later revisions. The applicant further stated that it has 

chosen to use ECP, the measured molar ratio of hydrogen to oxygen, as its primary indicator of 

IGSCC mitigation. 

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 whether 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 AMP XI.M2. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M2. 

The staff also reviewed the portions of the “scope of the program,” “parameters monitored or 

inspected,” and “detection of aging effects” program elements associated with the exceptions to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these exceptions follows. 

Exception 1. LRA Section B.2.1.2 states an exception to the “scope of the program” and 

“parameters monitored or inspected” program elements. The applicant stated that 

“NUREG-1801 [the GALL Report] indicates that hydrogen peroxide is monitored to mitigate 

degradation of structural materials. The Hope Creek program does not monitor for hydrogen 

peroxide.” 

As part of the audit, the staff interviewed the applicant’s technical personnel to discuss this 

exception and reviewed BWRVIP-130 and BWRVIP-190, “BWR Vessel and Internals Project 

BWR Water Chemistry Guidelines EPRI TR-1016579” (2008). During the interview, the 

applicant stated that it uses hydrogen addition and noble metal chemical applications to mitigate 

the occurrence of IGSCC by maintaining an ECP value less than -230 mV (millivolt), standard 

hydrogen electrode (SHE). The applicant also stated that it continuously monitors ECP in the 

reactor water system, and that by maintaining ECP less than -230 mV, SHE (below the action 

level value) the formation of hydrogen peroxide is sufficiently suppressed to mitigate the 

occurrences of IGSCC. 

The staff notes that BWRVIP-190 provides sufficient guidance for using ECP to determine 

hydrogen-to-oxygen molar ratios in reactor water in order to minimize the formation of hydrogen 

peroxide and mitigate IGSCC. The staff also notes that the applicant’s Water Chemistry 

Program includes activities to ensure that the reactor water contains an adequate excess of 

hydrogen-to-oxygen such that the ECP is maintained below values necessary to mitigate the 

aging effects of hydrogen peroxide and IGSCC. The staff finds the applicant’s exception 

acceptable because using ECP as the principle indicator of IGSCC mitigation is consistent with 

BWRVIP-190 guidance and, therefore, is consistent with the GALL Report, which recommends 

following the guidance of BWRVIP-29 or later revisions. 

Exception 2. LRA Section B.2.1.2 states an exception to the “scope of the program” and 

“parameters monitored or inspected” program elements. The applicant stated that 

“NUREG-1801 [the GALL Report] indicates that dissolved oxygen is monitored. The 
Aging Management Review Results 

 3-72 

condensate storage tank water, demineralized water storage tank water, SFP water, and torus 

water are not sampled for dissolved oxygen.” 

As part of the audit, the staff interviewed the applicant’s technical personnel to discuss this 

exception and reviewed BWRVIP-130 and BWRVIP-190. The applicant indicated it was 

consistent with industry guidelines, as recommended by the GALL Report, by following the 

industry guidelines of BWRVIP-130 and BWRVIP-190 (both are later revisions to BWRVIP-29). 

The applicant stated that the Water Chemistry Program required monitoring of conductivity, 

chlorides, sulfates, and total organic carbon (TOC) in accordance with BWRVIP-190, as its 

method for ensuring component integrity. 

The staff notes that dissolved oxygen is not one of the diagnostic parameters recommended by 

the EPRI guidance documents for monitoring the health of the auxiliary systems, whereas 

conductivity, chlorides, sulfates, and TOC are all diagnostic parameters for the auxiliary systems 

recommended by the EPRI. The staff also notes that BWRVIP-190 is a later revision of 

BWRVIP-29 and that following the guidance of BWRVIP-190 is consistent with the GALL 

Report, which recommends following the guidance of BWRVIP-29 or later revisions. The staff 

finds the exception acceptable because it is consistent with the recommendations in 

BWRVIP-190, and the program monitors other water chemistry parameters that are acceptable 

to mitigate aging in the auxiliary systems. 

Exception 3. LRA Section B.2.1.2 states an exception to the “scope of the program” and 

“parameters monitored or inspected” program elements. The applicant stated that 

“NUREG-1801 [the GALL Report] indicates that water quality (pH and conductivity) is 

maintained in accordance with established guidance. The pH is not monitored for torus water.” 

As part of the audit, the staff interviewed the applicant’s technical personnel to discuss this 

issue and reviewed guidance provided in BWRVIP-190 and BWRVIP-130. The applicant stated 

in its exception that BWRVIP-130, “BWR Water Chemistry Guidelines,” Section 8.2.1.11, 

indicates that pH measurement accuracy is unreliable in BWR streams because of the ionic 

strength of the samples. The applicant also stated that its Water Chemistry Program relies on 

monitoring conductivity, chlorides, and sulfates consistent with BWRVIP-190. 

The staff reviewed the Water Chemistry Program and finds the exception acceptable because: 

(1) it is consistent with the guidance provided in BWRVIP-190 because pH is not a diagnostic 

parameter for torus water recommended by the EPRI, whereas conductivity, chloride, and 

sulfate are all recommended by the EPRI as diagnostic parameters for torus water; and 

(2) BWRVIP-190 is a later revision of BWRVIP-29 and, therefore, following the guidance of 

BWRVIP-190 is consistent with the GALL Report, which recommends following the guidance of 

BWRVIP-29 or later revisions. 

Exception 4. LRA Section B.2.1.2 states an exception to the “scope of the program” and 

“detection of aging effects” program elements. The applicant stated that, “Aging of Standby 

Liquid Control system (SLC) components subject to the sodium pentaborate environment relies 

on control of SLC poison storage tank water chemistry. The sodium pentaborate solution is not 

monitored. The makeup water to the tank is monitored in lieu of the sodium pentaborate 

solution in the storage tank.” 

As part of its audit, the staff interviewed the applicant’s technical personnel to discuss this issue. 

During the interview, the applicant stated that because of the high concentration of sodium 

pentaborate contained in the SLC solution, analyses for relative trace impurities based on the 
Aging Management Review Results 

 3-73 

Water Chemistry Program would be ineffective in directly identifying impurities or potential 

degradation byproducts. In discussions with the applicant’s technical personnel, the staff 

determined that the SLC tank is a closed system from which impurities could only be introduced 

through makeup water additions. In addition, the applicant’s technical personnel stated that the 

purity of the sodium pentaborate was verified prior to introduction into the SLC system. 

The staff reviewed this exception and determined that the applicant will be able to adequately 

manage aging issues associated with this exception by being able to determine if impurities 

have been introduced into the SLC system by monitoring the chemistry of makeup water. In 

addition, the applicant stated that the effectiveness of the Water Chemistry Program will be 

verified by a one-time inspection of selected SLC system components as part of the One-Time 

Inspection Program. On this basis, the staff finds this exception acceptable because the 

applicant is able to monitor the impurities coming into the SLC system and it would verify the 

effectiveness of the Water Chemistry with a one-time inspection. 

Based on its audit, the staff finds that elements one through six of the applicant’s Water 

Chemistry Program, with acceptable exceptions, are consistent with the corresponding program 

elements of GALL AMP XI.M2 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.2 summarizes operating experience related to the 

Water Chemistry Program. The applicant stated that in June 1999, HCGS began service of full 

flow condensate pre-filters in response to high iron concentrations in feedwater. The operation 

of the pre-filters resulted in reduction in iron concentration to well below the maximum 

recommended concentrations. The performance of the pre-filters allowed the use of anion 

underlay, which allowed sulfate concentrations to be maintained at or below desired levels. The 

applicant stated that the net result of the pre-filter installation was drastically improved reactor 

water chemistry and lengthened resin bed life. 

In additional operating experience descriptions, the applicant noted a trend in increasing 

condensate demineralizer influent conductivity with an increase in chloride concentration to 

above recommended values. This increase in chloride prompted an Action Level 1 response of 

increased monitoring and the implementation of a corrective action plan. As a result of these 

actions, the applicant identified tube leaks in a waterbox, which were subsequently repaired. 

The applicant stated that this demonstrated how the Water Chemistry Program is effective in 

detecting unexpected parameters and in identifying and resolving issues responsible for 

chemistry beyond acceptable limits. 

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 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. 
Aging Management Review Results 

 3-74 

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.2.1.2 provides the UFSAR supplement for the Water 

Chemistry Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant committed 

(Commitment No. 2) to ongoing implementation of the existing Water Chemistry Program for 

managing aging of applicable components during 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 Water Chemistry Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determines that the AMP, with the exceptions, is adequate to manage the 

aging effects for which the LRA credits it. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.2 BWR Stress Corrosion Cracking 

Summary of Technical Information in the Application. LRA Section B.2.1.7 describes the 

existing BWR Stress Corrosion Cracking Program as consistent, with an enhancement, with 

GALL AMP XI.M7, “BWR Stress Corrosion Cracking.” The applicant stated that the BWR 

Stress Corrosion Cracking Program manages IGSCC in reactor coolant pressure boundary 

(RCPB) piping and piping components made of austenitic stainless steel and nickel based alloy 

components. The applicant further stated that the program follows the guidelines in 

NUREG-0313, Revision 2, and GL 88-01 and its Supplement 1 and includes the following: 

● preventive measures to mitigate IGSCC (the applicant has applied mechanical stress 

Improvement process (MSIP) to several reactor vessel nozzle welds) 

● augmented ISI according to BWRVIP-75-A, “BWR Vessel and Internals Project 

Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules” 

● flaw evaluation to monitor IGSCC and its effects 

● monitoring of reactor coolant water chemistry in accordance with the guidelines in 

BWRVIP-130, “BWR Water Chemistry Guidelines,” to reduce susceptibility to IGSCC 

(HCGS implemented HWC and NMCA) 

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 whether they are 

bounded by the conditions for which the GALL Report was evaluated. 
Aging Management Review Results 

 3-75 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL AMP XI.M7. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M7. The staff also 

conducted onsite interviews with the applicant to confirm these results. 

The staff also reviewed the portions of the “preventive actions” program element associated with 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of this enhancement are as follows. 

Enhancement. LRA Section B.2.1.7 states an enhancement to the “preventive actions” program 

element. The applicant stated that the program will be enhanced to clarify that, for the 

components within the scope of the BWR Stress Corrosion Cracking Program, resistant 

materials will be used for new and replacement components. The applicant further stated that 

this includes low carbon stainless piping and stainless steel weld material limited to a maximum 

carbon content 0.035 wt. percent and a minimum ferrite content of 7.5 percent. 

The staff noted that the “preventive actions” program element in GALL AMP XI.M7 states that 

the BWRVIP-75 report includes recommendations regarding selection of materials that are 

resistant to sensitization, use of special processes that reduce residual tensile stresses, and 

monitoring and maintenance of coolant chemistry. It further states that resistant materials are 

used for new and replacement components and include low-carbon grades of austenitic 

stainless steel and weld metal, with a maximum carbon of 0.035 wt. percent and a minimum 

ferrite of 7.5 percent in weld metal and CASS. 

Based on its review, the staff finds the applicant’s enhancement acceptable because the 

applicant will be selecting new and replacement components that include low carbon stainless 

piping and stainless steel weld material limited to a maximum carbon content 0.035 wt. percent 

and a minimum ferrite content of 7.5 percent, which is consistent with the recommendations in 

GALL AMP XI.M7. 

Based on its audit, the staff finds that elements one through six of the applicant’s BWR Stress 

Corrosion Cracking Program, with an acceptable enhancement, are consistent with the 

corresponding program elements of GALL AMP XI.M7 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.7 also summarizes operating experience related to 

the BWR Stress Corrosion Cracking Program. The applicant stated it has performed 

inspections of the IGSCC susceptible components and welds as delineated in NUREG-0313, 

and later modified by GL 88-01 and more recently by BWRVIP-75-A as part of the ASME 

Section XI ISI program. The applicant also stated that its ISI program identifies 386 augmented 

components that are inspected in accordance with GL 88-01. 

The applicant further stated that the inspections have been successful in detecting flaws in the 

past. The applicant stated that specifically, during refueling outages RF07, RF12, and RF14, 

nozzles N5B, N2K, and N2A, respectively, were determined to have flaws in the nozzle welds. 

The applicant further stated that in each instance, the deficiencies were entered into a corrective 

action program and corrected in a timely manner. The applicant further stated that subsequent 

inspection of the repaired nozzles did not detect any flaw indications. The staff noted that these 

inspections have detected only three flaws that exceeded the IWB-3500 acceptance standards 

and in each case, the flaws were evaluated, a root cause analysis was performed, and 

inspections of similar welds were performed to check for additional evidence of cracking. 
Aging Management Review Results 

 3-76 

The staff noted that starting with the initial design and construction of the plant and continuing 

on through current operations, the applicant has taken numerous actions to reduce the effects 

of IGSCC on the RCPB components and a partial list is included below: 

 (1) incorporated recommendations of NUREG-0313, Revision 1 at the time of construction 

(corrosion resistant materials were used for the RPV safe ends and extensions) 

 (2) eliminated thermal sleeves in vessel design 

 (3) applied corrosion resistant cladding to field welds for 304 stainless steel piping 

connections 

 (4) heat treated all of the shop welds before installation 

 (5) applied MSIP to several RPV nozzle welds 

 (6) implemented HWC and NMCA 

 (7) improved HWC system availability to over 90 percent 

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 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. LRA Section A.2.1.7 provides the UFSAR supplement for the BWR Stress 

Corrosion Cracking Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. 

The staff also notes that the applicant committed (Commitment No. 7) to enhance the BWR 

Stress Corrosion Cracking Program prior to entering the period of extended operation. 

Specifically, the applicant committed that for the components within the scope of the BWR 

Stress Corrosion Cracking Program, resistant materials will be used for new and replacement 

components. This includes low carbon stainless piping and stainless steel weld material limited 

to a maximum carbon content 0.035 wt. percent and a minimum ferrite content of 7.5 percent. 

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). 
Aging Management Review Results 

 3-77 

Conclusion. On the basis of its audit and review of the applicant’s BWR Stress Corrosion 

Cracking Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. Also, the staff reviewed the 

enhancements and confirmed that its implementation through Commitment No. 7 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). 

3.0.3.2.3 Flow-Accelerated Corrosion 

Summary of Technical Information in the Application. LRA Section B.2.1.11 describes the 

existing Flow-Accelerated Corrosion Program as consistent, with an exception, to GALL 

AMP XI.M17, “Flow-Accelerated Corrosion.” The applicant stated that the Flow-Accelerated 

Corrosion Program is based on EPRI guidelines in Nuclear Safety Analysis Center 

(NSAC)-202LR3, “Recommendations for an Effective Flow Accelerated Corrosion Program,” 

and that the program provides for predicting, detecting, and monitoring wall thinning in piping 

and fittings, valve bodies, and heat exchangers due to flow-accelerated corrosion. The 

applicant further stated that the program uses the EPRI computer program CHECWORKS, 

along with the implementing guidelines contained in NSAC-202L-R3, “Recommendations for an 

Effective Flow Accelerated Corrosion 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 whether 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 AMP XI.M17. The staff confirmed that these elements are consistent with the 

corresponding elements of GALL AMP XI.M17, with a common exception to the “scope of the 

program” and “detection of aging effects” program elements. The staff’s evaluation of this 

exception follows. 

Exception. LRA Section B.2.1.11 states that there is an exception to the “scope of the program” 

and “detection of aging effects” program elements. GALL AMP XI.M17 states that the “scope of 

the program” and “detection of aging effects” program elements of the Flow-Accelerated 

Corrosion Program relies on implementation of EPRI guidelines in NSAC-202L-R2; however, in 

the LRA, the applicant stated that the Flow-Accelerated Corrosion Program is based on the 

EPRI guidelines found in NSAC-202L-R3. The applicant stated that the new revision of the 

EPRI guidelines incorporate lessons learned and improvements to detection, modeling, and 

mitigation technologies that became available since NSAC-202L-R2 was published. The staff 

previously reviewed NSAC-202L-R3 (NUREG-1929, Volume 2) and determined that it is 

equivalent to NSAC-202L-R2 and in addition, allows the use of the Averaged Band Method, 

which is another method for determining wear of piping components from UT inspection. The 

staff notes that EPRI documents are created using industry experience over several years and 

finds that the Averaged Band Method provides another method to determine the wear of piping 

components from UT inspections. The staff finds this method to be more accurate, thereby 

resulting in better prediction of remaining life and less rework. The staff finds the use of 

NSAC-202L-R3 acceptable because it will continue to allow the applicant to manage wall 
Aging Management Review Results 

 3-78 

thinning due to flow-accelerated corrosion on the internal surfaces of carbon and low alloy steel 

piping and components that contain both single-phase and two-phase high-energy fluids. 

Based on its review, the staff finds that elements one through six of the applicant’s 

Flow-Accelerated Corrosion Program, with an acceptable exception, are consistent with the 

corresponding program elements of GALL AMP XI.M17 and are, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.11 summarizes operating experience related to the 

Flow-Accelerated Corrosion Program. The applicant stated that it implemented a piping 

replacement plan in 2006, to mitigate wall thinning, by upgrading to flow-accelerated corrosion 

resistant material. Since implementing the replacement program, the applicant has replaced 

portions of the piping in the main steam drains, reactor water feed pump turbine steam supply 

drains, extraction steam lines, seal steam lines, feedwater heater vent lines, reactor core 

isolation cooling (RCIC) and HPCI steam supply drain lines, and the plant heating system. The 

piping replacement plan continues to monitor for replacement, the operating vent lines for all the 

feedwater heaters, the main steam turbine control valve before seat drains and leak-off lines, 

the main steam lead drains, portions of reactor feed pump turbine steam drains, the steam jet 

air ejector runoff drain, portions of plant heating piping inside the turbine building steam tunnel, 

and the turbine bypass seal leak-off lines. 

The applicant also provided the following operational experience: 

As result of feedwater heater shell failures at other nuclear plants (OE-9941), as 

well as Salem Unit 1 plant experience with feedwater heaters (OE11020), 

feedwater heater shell inspections were instituted at Hope Creek. In 2000, the 

#5A, B & C feedwater heater shell area was replaced in the vicinity of the 

extraction steam inlet nozzles. A shell area was cut out of the heaters, and was 

replaced with carbon steel plate roll-bonded with 0.125” stainless steel cladding 

on the inside diameter. The extraction steam inlet nozzle was also replaced with 

the same configuration. All feedwater heaters (except the #1 heaters), have 

been inspected at least once. The shell area around two of the four #1C 

feedwater heater extraction steam inlet nozzles were inspected in 2007, and no 

problem was identified. In a letter dated January 19, 2011, the applicant stated 

that feedwater heater shell area adjacent to the remaining two extraction steam 

inlet nozzles for the #1C, and all the #1A and #1B feedwater heaters extraction 

steam inlet nozzles were inspected in 2010, and no problems were identified. 

As a part of the feedwater heater shell FAC [flow-accelerated corrosion] 

inspection program, stress evaluations are performed to obtain the allowable 

minimum wall thickness. This minimum allowable thickness is the basis for 

trending wall thinning and tracking when the next inspection is scheduled. The 

scope of the feedwater heater shell inspection project is to inspect every 

feedwater heater shell at least once in the vicinity of the extraction steam inlet 

nozzle. Wear rates are determined and wall thinning on the feedwater heaters 

are trended, and analyses are performed to determine appropriate inspections, 

which are scheduled prior to the shell reaching its minimum allowable wall 

thickness. 

In 2004, the Hope Creek FAC program prompted a wall thickness inspection of 

feedwater heater nozzles in response to OE17919, “Inspection Identifies Holes in 

#2 Heater Extraction at LaSalle Unit 1.” Based on ultrasonic testing (UT) and 
Aging Management Review Results 

 3-79 

visual inspection, significant wall thinning downstream of the piping/nozzle weld 

for the #2A feedwater heater nozzles was discovered. Extent of condition 

evaluation determined that #2B and #2C feedwater heaters had experienced the 

same kind of wall thinning. 

During internal weld repairs in April 2006, it was discovered that the nozzle had a 

stainless steel liner, which started at about 1/4” downstream of the pipe and 

nozzle weld, rather than being fully extended. The wall thinning was found to be 

caused by steam cutting of the nozzle between the inner liner and the outer 

diameter, indicating the degradation to the nozzle would have been less severe 

had the liner been fully extended to the top of the nozzle. So far eleven out of 

the twelve nozzles for the #2 feedwater heaters (FWHs) have been repaired by 

internal weld build-up. In the January 19, 2011, letter, the applicant stated that 

all three feedwater heaters were successfully replaced in RF 16 outage (October 

2010). The new FWHs have extraction steam inlet nozzles fabricated with alloy 

steel, which is resistant to FAC. To correct the root cause of this problem, the 

Hope Creek FAC Program will continue to monitor FAC-susceptible feedwater 

heater nozzles and make repairs or replacements as warranted. 

Extended Power uprate (EPU) at Hope Creek was implemented in 2008. In 

advance of this power uprate, in 2002, Hope Creek performed a FAC evaluation 

on CHECWORKS at 20 percent power uprate. Comparing the predicted 

CHECWORKS wear rates at EPU with wear rates at normal power, this 

evaluation revealed that the power uprate operating conditions would have a 

minimal impact on FAC wear rates. Also, results showed that the average 

predicted wear rate would not cause an increased need for physical 

modifications or replacements of the systems that are vulnerable to FAC. In 

2008, the CHECWORKS model at Hope Creek was revised to reflect the power 

uprate conditions, in compliance with the EPRI NSAC 202L-R3 Guidelines. 

Hope Creek has benefited from FAC related experience of other nuclear plants 

that have gone through EPU. Hope Creek actively participates in the 

CHECWORKS User Group (CHUG) and stays informed of the industry 

experience on FAC. So far, no industry experience has indicated any FAC 

related issues because of EPU that would have any impact on risk ranking by 

CHECWORKS. Hope Creek will enter its period of extended operation in 2026. 

This provides at least 18 years of additional plant experience at EPU conditions. 

In addition, it allows for monitoring experiences at other nuclear plants that have 

gone through EPU conditions. 

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. 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 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 
Aging Management Review Results 

 3-80 

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. LRA Section A.2.1.11 provides the UFSAR supplement for the 

Flow-Accelerated Corrosion Program. The staff reviewed this UFSAR supplement description 

of the program and notes that it does not explicitly conform to the recommended description for 

this type of program as described in SRP-LR Tables 3.2-2 and 3.4-2. The Flow-Accelerated 

Corrosion Program description in LRA Section A.2.1.11 does not specifically reference 

NSAC-202L-R2; however, as noted previously in the review of the AMP, the applicant is using 

the CHECWORKS program and NSAC-202L-R3 as the basis for the Flow-Accelerated 

Corrosion Program. The staff also notes that the applicant committed (Commitment No. 11) to 

ongoing implementation of the existing Flow-Accelerated Corrosion Program for managing 

aging of applicable components during the period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Flow-Accelerated Corrosion 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

with the justification and determines 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 has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.4 Bolting Integrity 

Summary of Technical Information in the Application. LRA Section B.2.1.12 describes the 

existing Bolting Integrity Program as consistent, with an exception and an enhancement, with 

GALL AMP XI.M18, “Bolting Integrity.” The applicant stated that the Bolting Integrity Program 

incorporates NRC and industry recommendations delineated in NUREG-1339, “Resolution of 

Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants;” EPRI 

TR-104213, “Bolted Joint Maintenance and Applications Guide;” and EPRI NP-5769, 

“Degradation and Failure of Bolting in Nuclear Power Plants.” The applicant also stated that the 

Bolting Integrity Program provides for condition monitoring of pressure retaining bolted joints 

within the scope of license renewal and that the program provides for managing cracking, loss 

of material, and loss of preload by performing visual inspections for pressure retaining bolted 

joint leakage in the environments of indoor and outdoor air, raw water, soil, and treated water. 

The applicant further stated that procurement controls and installation practices defined in plant 

procedures ensure that only approved lubricants, sealants, and proper torques are applied to 

bolting within the scope of the program and that the activities are implemented through station 

procedures. 

The applicant stated that: (1) for ASME Code class bolting, the extent and schedule of 

inspections is in accordance with ASME Code Section XI, Tables IWB-2500-1, IWC-2500-1, and 

IWD-2500-1; (2) bolting associated with ASME Code Class 1 vessel, valve, and pump flanged 
Aging Management Review Results 

 3-81 

joints receive VT-1 inspection; and (3) for other pressure retaining bolting, routine observations 

will document any leakage before the leakage becomes excessive. The applicant also stated 

that the integrity of non-ASME Class 1, 2, and 3 system and component pressure retaining 

bolted joints is evaluated by detection of visible leakage during maintenance or routine 

observation such as system walkdowns. The applicant further stated that high-strength bolts 

(actual yield strength greater than or equal to 150 thousands of pounds per square inch (ksi)) 

are not used on structural connections and that structural bolting and fasteners (actual yield 

strength less than 150 ksi) both inside and outside containment are inspected by the Structures 

Monitoring Program. The applicant identified various other AMPs that also provide or 

supplement the aging management of bolting and fasteners, including: (1) ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, IWD; (2) ASME Section XI, Subsection IWE; 

(3) ASME Section XI, Subsection IWF; (4) Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems; (5) External Surfaces Monitoring; (6) Buried Piping 

Inspection; and (7) Buried Non-Steel Piping Inspection. 

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 whether 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 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 elements of GALL 

AMP XI.M18, with the exception of the “scope of the program” and “preventive actions” program 

elements. For these elements, the staff determined the need for additional clarification, which 

resulted in the issuance of RAIs, which are discussed below. 

In GALL AMP XI.M18, the “scope of the program” program element states that the Bolting 

Integrity Program covers bolting within the scope of license renewal, including: (1) safety-related 

bolting, (2) bolting for NSSS component supports, (3) bolting for other pressure retaining 

components, including nonsafety-related bolting, and (4) structural bolting (actual measured 

yield strength greater than or equal to 150 ksi). The “preventive actions” program element 

states that preventive actions include proper torquing and application of an appropriate preload. 

Based on its review of the applicant’s documentation, the staff noted that aging of component 

support and structural bolting within the scope of license renewal may not be managed by the 

applicant’s Bolting Integrity Program but instead be managed by other AMPs such as the 

applicant’s Structures Monitoring Program. Also, it was not clear to the staff how the applicant 

would ensure that all elements of GALL AMP XI.M18 would be included in other AMPs credited 

to manage bolting not included in the Bolting Integrity Program. 

By letter dated May 14, 2010, the staff issued RAI B.2.1.12-01 requesting that the applicant: 

(1) explain why use of other AMPs to manage the aging effects of component support and 

structural bolting was not identified as an exception to GALL AMP XI.M18 “scope of the 

program” program element; and (2) explain how the applicant ensures that other AMPs credited 

for aging management of component support and structural bolting include the 

recommendations that are contained in GALL AMP XI.M18 “preventive actions” program 

element. 

In its response dated June 14, 2010, the applicant confirmed its understanding that GALL 

AMP XI.M18 recommends that component support bolting and structural bolting be included 

within the scope of the Bolting Integrity Program and that the 10 elements of GALL AMP XI.M18 

are applicable to component support bolting and structural bolting within the scope of license 
Aging Management Review Results 

 3-82 

renewal. The applicant stated that it did not identify an exception to recommendations in the 

GALL Report because the recommendations identified in the 10 elements of GALL AMP XI.M18 

are implemented through existing station procedures in its Bolting Integrity Program that are 

applicable to mechanical system closure bolting, as well as to component support bolting and 

structural bolting. The applicant also stated that the additional AMPs credited for aging 

management of component support bolting and structural bolting are primarily condition 

monitoring programs that supplement activities of the Bolting Integrity Program. In its response, 

the applicant further stated that to ensure continued implementation of all 10 elements of its 

Bolting Integrity Program through the period of extended operation, the LRA is revised to credit 

the Bolting Integrity Program for component support bolting and structural bolting in the cranes 

and hoists system, the fuel handling and storage system, the auxiliary boiler building, the 

auxiliary building control/diesel generator area, the auxiliary building service/radwaste area, the 

component supports commodity group, the fire water pump house, the primary containment, the 

reactor building, the service water intake structures, the switchyard, the turbine building, and the 

yard structures. 

In its response, the applicant provided a number of LRA changes which revised LRA 

Appendix A, Section A.2.1.12; the UFSAR supplement for the Bolting Integrity Program; and 

LRA Appendix B, Section B.2.1.12, the summary description for the Bolting Integrity Program, to 

describe the applicant’s Bolting Integrity Program as “an existing program that provides aging 

management of pressure retaining bolted joints, component support bolting and structural 

bolting within the scope of license renewal.” The applicant also revised a number of 

bolting-related lines in the Summary of Aging Management Evaluations tables in LRA Section 3. 

The changes in the LRA summary tables state that the Bolting Integrity Program manages aging 

effects in component support bolting and structural bolting and that other applicable AMPs 

include condition monitoring that supplements the Bolting Integrity Program. For affected AMR 

result lines that had previously cited generic Note E, indicating that an alternative to the AMP 

recommended in the GALL Report was credited, the applicant added a line item that credited 

the Bolting Integrity Program and cited generic Note B, indicating that the result is consistent 

with the GALL Report, but the AMP program elements include some acceptable exception to 

the GALL Report’s recommendations. 

In its review of the applicant’s RAI response, the staff determined that including component 

support bolting within the scope of other programs does not constitute an exception to the GALL 

Report results because station procedures referenced in the applicant’s Bolting Integrity 

Program that are applicable to mechanical system closure bolting are also applicable for 

component support bolting and structural bolting. The staff also determined that the applicant’s 

changes to the LRA are acceptable because they clarify that alternative condition monitoring 

AMPs are not used in lieu of, but are used to supplement the mitigation and monitoring 

elements of the Bolting Integrity Program. The staff finds that the applicant’s Bolting Integrity 

Program is consistent with the recommendations in GALL AMP XI.M18 with regard to the staff’s 

concerns expressed in RAI B.2.1.12-01 and that the applicant’s response resolves all issues 

raised in the RAI. 

By letter dated June 1, 2010, the staff issued RAI 3.3.2.3.10-01, related both to the applicant’s 

Buried Piping Inspection Program and the Bolting Integrity Program. The RAI requested the 

applicant to provide additional details regarding how bolting in buried piping is inspected. In its 

response dated June 24, 2010, the applicant stated that buried bolts are inspected during 

directed or opportunistic excavations of buried piping, in addition to a flow test, to confirm that 

there is no significant leakage from bolted pressure retaining piping joints in accordance with its 
Aging Management Review Results 

 3-83 

Buried Piping Inspection Program. The staff’s evaluation of the RAI response is documented in 

SER Section 3.3.2.3.10. 

By letter dated August 3, 2010, the staff issued RAI B.2.1.12-02 requesting that the applicant 

clarify what pressure joint bolting within the scope of the Bolting Integrity Program is exposed to 

raw water or treated water environments and to explain how visual inspections are performed to 

detect loss of preload for submerged bolted joints. In its response dated August 26, 2010, the 

applicant stated that the pressure retaining bolted joints exposed to raw water are limited to the 

service water pump bolting and that the submerged portion of the service water pump includes 

bolted connections attached with aluminum bronze bolts. The applicant further stated that the 

in-scope pressure retaining bolted joints exposed to treated water are limited to emergency core 

cooling system (ECCS) suction strainers and connecting piping located in the suppression 

chamber. 

The applicant stated that service water pump bolting is inspected during periodic maintenance, 

with each service water pump being removed and replaced with a refurbished spare pump on a 

10-year frequency. The applicant further stated that during disassembly, the pumps are 

inspected for loose or missing bolting, that the bolts are inspected for loss of material, and that 

during reassembly the bolting is torqued in accordance with design specifications to prevent 

loss of preload. 

The applicant stated that: (1) a walkdown and visual inspection of the suppression chamber is 

performed on an 18-month frequency; (2) this inspection includes observation of submerged 

ECCS suction strainers, including bolted connections, from the catwalk inside the suppression 

chamber; and (3) the suppression pool floor and the suction strainers are inspected for loose 

objects and debris, including any bolting that may have become unattached. The applicant 

further stated that the submerged suppression pool shell is subject to periodic ISI in accordance 

with ASME Code Section XI requirements by divers certified to perform VT-1 and VT-3 

inspections and that during this activity, the divers also inspect the submerged ECCS suction 

strainers and associated piping for general condition, debris accumulation, and mechanical 

damage. 

In its response to RAI B.2.1.12-02, the applicant submitted changes that provide additional 

details in LRA Sections A.2.1.12 and B.2.1.12, the UFSAR supplement and the program 

evaluation, respectively, for the Bolting Integrity Program. In both LRA sections, the changes 

add a statement that the aging management activities directed by the Bolting Integrity Program 

include visual inspections for pressure retaining bolted joint leakage and preventive measures 

implemented during bolted joint maintenance and installation. In addition, in LRA 

Section B.2.1.12, the applicant added statements that normally inaccessible bolted connections 

are inspected for degradation when they are made accessible during maintenance activities and 

that inspection activities for submerged bolting are performed in conjunction with associated 

component maintenance activities. 

The staff notes that the applicant’s aging management activities for all submerged bolting within 

the scope of license renewal includes inspection of the submerged bolts and bolted joints on a 

frequency determined by periodic maintenance or inspection of associated components. The 

staff finds this feature of the Bolting Integrity Program acceptable because periodic inspections 

provide opportunity for the applicant to find, evaluate, and correct any degraded conditions 

associated with submerged bolting before failure of the bolting to perform its intended function 

occurs. The staff also finds the applicant’s changes to the LRA acceptable because they 

provide additional detail and clarification describing implementation of the Bolting Integrity 
Aging Management Review Results 

 3-84 

Program. On this basis, the staff finds that the applicant’s response to RAI B.2.1.12-02 resolves 

all issues addressed in the RAI. 

The staff also reviewed the portions of the “monitoring and trending” and the “corrective actions” 

program elements associated with the exception and the enhancement to determine whether 

the program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of the exception and enhancement follows. 

Exception. LRA Section B.2.1.12 states an exception to the “monitoring and trending” program 

element. The applicant stated that the GALL Report indicates that if a bolting connection for 

pressure retaining components (not covered by ASME Code Section XI) is reported to be 

leaking, then it may be inspected daily and that, if the leak rate does not increase, the inspection 

frequency may be decreased to biweekly or weekly. The applicant stated that it uses its 

corrective action program to determine an appropriate inspection frequency for identified leaks 

in bolting connections. 

The applicant provided justification for this exception by stating that for other than ASME 

Classes 1, 2, or 3 bolting, it uses its corrective action program to document and manage 

locations where leakage is identified during routine observations, including engineering 

walkdowns and equipment maintenance activities. The applicant stated that based on the 

severity of the leak and the potential to impact plant operations and nuclear or industrial safety, 

a leak will be repaired immediately, scheduled for repair, or monitored for change. The 

applicant stated that if the leak rate changes (increases, decreases, or stops) the monitoring 

frequency is re-evaluated and may be revised and that its operating experience has not 

indicated a need for a set frequency (e.g., daily) of leakage inspections involving bolting. 

The staff noted that the applicant’s corrective action program is consistent with the requirements 

of 10 CFR 50, Appendix B and includes provisions for reporting, documenting, evaluating safety 

significance, trending, and implementing corrective actions for bolted pressure boundary 

components reported to be leaking. Because the applicant’s corrective action program is 

consistent with 10 CFR 50, Appendix B and has provisions to determine an appropriate 

inspection frequency for a bolted pressure boundary component found to be leaking, the staff 

finds the applicant’s exception to be acceptable. 

Enhancement. The applicant stated that prior to the period of extended operation the 

“corrective actions” program element will be revised to state that the following bolts and nuts 

should not be reused: (a) galvanized bolts and nuts, (b) ASTM A490 bolts, and (c) any bolts and 

nuts tightened by the turn-of-nut method. 

The staff noted that the applicant’s enhancement to its Bolting Integrity Program is listed as 

Commitment No. 12 in LRA Table A.5, License Renewal Commitment List. The staff also noted 

that the applicant’s proposed enhancement is consistent with EPRI TR-104213, 

Section 16.11.2, which provides recommendations regarding bolting material that should not be 

reused. On the basis that guidelines in EPRI TR-104213 are endorsed by GALL AMP XI.M18, 

and the applicant’s enhancement is consistent with a recommendation in the EPRI guidance 

document and is listed in the applicant’s License Renewal Commitment List, the staff finds the 

applicant’s enhancement to its Bolting Integrity Program to be acceptable. 

Based on its audit and review of the applicant’s responses to RAIs B.2.1.12-01 and B.2.1.12-02, 

the staff finds that elements one through six of the applicant’s Bolting Integrity program, with an 
Aging Management Review Results 

 3-85 

acceptable exception and an enhancement, are consistent with the corresponding program 

elements of GALL AMP XI.M18 and, therefore, the staff finds it acceptable. 

Operating Experience. LRA Section B.2.1.12 summarizes operating experience related to the 

Bolting Integrity Program. The applicant stated that it has experienced isolated cases of bolt 

corrosion, loss of bolt preload, and bolt torquing issues, and that in all cases, the existing 

inspection and testing methodologies have discovered the deficiencies and corrective actions 

were implemented prior to loss of system or component intended functions. The applicant also 

stated that in 2004, an inspection of the torus lateral seismic restraint bolting washers showed 

scaling and that after the scale was removed, pitting was found on the washers. The applicant 

further stated that the corrective action was to remove scaling from all washers and apply a 

protective coating and that follow-up inspections have not found any rust or scaling. 

The applicant stated that in 2004, during a system walkdown, a bolt was found to be missing on 

a nonsafety-related pipe support base plate in the safety auxiliaries cooling system (SACS) and 

that further investigation determined that the bolt was in place but rusted. The applicant also 

stated that an engineering evaluation determined that operability of the SACS was not affected 

and that new bolts were installed and properly torqued. The applicant further stated that these 

examples demonstrate that problems are discovered before intended function is affected and 

that corrective actions are taken to prevent recurrence. 

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 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 of SRP-LR Section A.1.2.3.10 

and, therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A.2.1.12 provides the UFSAR supplement for the Bolting 

Integrity Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant committed 

(Commitment No. 12) to enhance the Bolting Integrity Program prior to entering the period of 

extended operation. Specifically, the applicant committed to enhance the Bolting Integrity 

Program prior to the period of extended operation to include a requirement that the following 

bolts and nuts should not be reused: (1) galvanized bolts and nuts, (2) ASTM A490 bolts, and 

(3) any bolts and nuts tightened by the turn-of-nut method. The GALL AMP XI.M18 endorses 

EPRI TR-104213 which recommends that these nuts and bolts should not be reused. 

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). 
Aging Management Review Results 

 3-86 

Conclusion. On the basis of its audit and review of the applicant’s Bolting Integrity Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the exception and its justification 

and determines that the AMP, with the exception, 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. 12 prior to the period of extended operation would 

make the existing AMP consistent with the GALL Report AMP to which it is 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).

3.0.3.2.5 Closed-Cycle Cooling Water System 

Summary of Technical Information in the Application. LRA Section B.2.1.14 describes the 

existing Closed-Cycle Cooling Water Program as consistent, with an exception and 

enhancements, with GALL AMP XI.M21, “Closed-Cycle Cooling Water System.” The applicant 

stated that the Closed-Cycle Cooling Water Program manages the aging of piping, piping 

components, piping elements, and heat exchangers. The applicant also stated that its program 

incorporates mitigation, including addition of corrosion inhibitors, the use of water purity 

standards based on EPRI TR-1007820, and monitoring activities including inspections and 

NDEs for heat exchangers exposed to closed-cycle cooling water. The applicant further stated 

that it monitors performance trends of system pumps and heat exchangers to determine if or 

when any corrective actions are required and that it will perform a one-time inspection of low or 

stagnant flow areas to verify the effectiveness of the Closed-Cycle Cooling Water Program in 

mitigating aging effects in these areas. 

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 whether 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 AMP XI.M21. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M21. 

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements 

associated with the exception and enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of this 

exception and these enhancements are as follows. 

Exception. LRA Section B.2.1.14 states an exception to the “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “monitoring and trending” program 

elements. The applicant stated that it will implement the guidance provided in EPRI 

TR-1007820, which is the 2004 Revision to EPRI TR-107396, which is the report recommended 

by GALL AMP XI.M21. The applicant also stated that the new revision provides more 

prescriptive guidance, has a more conservative monitoring approach, and meets the same 

requirements of TR-107396 for effectively managing loss of material, cracking, and reduction of 

heat transfer. 
Aging Management Review Results 

 3-87 

The staff reviewed this exception to the GALL Report and noted that the applicant took the 

exception because the EPRI Closed Cooling Water Chemistry Guidelines have been updated 

from the version cited in the GALL Report. The staff finds this exception acceptable because 

the newer version of the above EPRI guidelines contains more recent operating experience 

information and applies a more conservative approach to managing aging than the previous 

version. 

Enhancement 1. LRA Section B.2.1.14 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements. The 

applicant stated that new recurring tasks will be established for enhancing the performance 

monitoring of the closed-cycle cooling water system. 

During the onsite audit, the staff interviewed HCGS technical staff, which indicated that the 

applicant would establish new recurrent tasks as enhancements to the performance monitoring 

of the closed-cycle cooling water system. On the basis of this review, the staff finds this 

enhancement acceptable because performance monitoring demonstrates system operability 

and confirms program effectiveness, and when it is implemented (Commitment No. 14), it will 

make the program consistent with the recommendations in GALL AMP XI.M21. 

Enhancement 2. LRA Section B.2.1.14 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements. The 

applicant stated that new recurring tasks will be established for enhancing the performance 

monitoring of the chilled water system. 

During the onsite audit, the staff interviewed HCGS technical staff, which indicated that the 

applicant would establish new recurrent tasks as enhancements to the performance monitoring 

of the chilled water system. On the basis of this review, the staff finds this enhancement 

acceptable because performance monitoring demonstrates system operability and confirms 

program effectiveness, and when it is implemented (Commitment No. 14), it will make the 

program consistent with the recommendations in GALL AMP XI.M21. 

Enhancement 3. LRA Section B.2.1.14 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements. The 

applicant stated that a one-time inspection of selected Closed-Cycle Cooling Water Program 

components in low or stagnant flow areas will be conducted to confirm the effectiveness of the 

Closed-Cycle Cooling Water Program. The applicant also stated that these inspections will be 

performed prior to the period of extended operation. 

During the onsite audit, the staff interviewed HCGS technical staff, which indicated that the 

applicant would establish one-time inspections of selected Closed-Cycle Cooling Water 

Program components in low or stagnant flow areas. On the basis of this review, the staff finds 

this enhancement acceptable because it will ensure the effectiveness of the program since the 

control of water chemistry does not preclude corrosion at low or stagnant flow locations, and 

when it is implemented (Commitment No. 14), it will make the program consistent with the 

recommendations in GALL AMP XI.M21. 

Enhancement 4. LRA Section B.2.1.14 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements. The 

applicant stated that a one-time inspection of selected chemical mixing tanks and associated 

piping in the Closed-Cycle Cooling Water Program will be conducted to confirm the 
Aging Management Review Results 

 3-88 

effectiveness of the Closed-Cycle Cooling Water Program on the interior surfaces of the tanks 

and associated piping. 

During the onsite audit, the staff interviewed HCGS technical staff, which indicated that the 

applicant would establish one-time inspections of selected Closed-Cycle Cooling Water 

Program mixing tanks and associated piping. On the basis of this review, the staff finds this 

enhancement acceptable because it will ensure the effectiveness of the chemistry controls, and 

when it is implemented (Commitment No. 14), it will make the program consistent with the 

recommendations in GALL AMP XI.M21. 

Enhancement 5. LRA Section B.2.1.14 states an enhancement to the “preventive actions,” 

“detection of aging effects,” and “monitoring and trending” program elements. The applicant 

stated that the program will be enhanced such that the plant auxiliary building chilled water 

system, which is part of the control area chilled water system, will comply with the pure water 

control program in accordance with EPRI TR-1007820 prior to the period of extended operation. 

During the onsite audit, the staff interviewed HCGS technical staff, which indicated that the 

applicant would identify consequences resulting from changes to the control area chilled water 

system to bring it into compliance with EPRI TR-1007820. On the basis of this review, the staff 

finds this enhancement acceptable because implementation of the EPRI guidelines will ensure 

satisfactory control of corrosion in pure water systems, and when it is implemented 

(Commitment No. 14), it will make the program consistent with the recommendations in GALL 

AMP XI.M21. 

Enhancement 6. LRA Section B.2.1.14 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements. The 

applicant stated that a one-time inspection of selected control area chilled water system 

components, including the plant auxiliary building chilled water system, will be conducted to 

confirm the effectiveness of the Closed-Cycle Cooling Water Program. The applicant stated 

that these inspections will be performed prior to the period of extended operation. 

During the onsite audit, the staff interviewed HCGS technical staff, which indicated that the 

applicant would establish one-time inspections of selected control area chilled water system 

components, including the auxiliary building chilled water system. On the basis of this review, 

the staff finds this enhancement acceptable because it will ensure the effectiveness of the 

chemistry controls, and when it is implemented (Commitment No. 14), it will make the program 

consistent with the recommendations in GALL AMP XI.M21. 

Based on its audit, the staff finds that elements one through six of the applicant’s Closed-Cycle 

Cooling Water Program, with an acceptable exception and acceptable enhancements, are 

consistent with the corresponding program elements of GALL AMP XI.M21 and, therefore, 

acceptable. 

Operating Experience. LRA Section B.2.1.14 summarizes operating experience related to the 

Closed-Cycle Cooling Water Program. The applicant stated that during a monthly surveillance 

test of the emergency diesel generator (EDG), a higher than normal lube oil temperature was 

observed. The applicant also stated that an investigation was performed, which identified the 

increase in temperature was due to an improperly positioned throttle valve that had been 

adjusted during recent safety auxiliaries cooling system flow balancing. The applicant further 

stated that the elevated temperatures in the EDG did not result in any material degradation and 

that this was an example of the effectiveness of monthly surveillance tests. 
Aging Management Review Results 

 3-89 

The applicant stated that several action reports were generated as a result of elevated metal 

contaminants in the diesel generator jacket water. The applicant also stated that it performed 

further investigations and determined that the cause of the elevated metal contaminants was the 

long-term reuse of the jacket water after maintenance. As a result, the applicant stated that it 

now uses a new corrosion inhibitor, which has resulted in significantly fewer incidents of metal 

contaminants in the diesel jacket water. 

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 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. LRA Section A.2.1.14 provides the UFSAR supplement for the 

Closed-Cycle Cooling Water Program. The staff reviewed this UFSAR supplement description 

of the program and notes that it conforms to the recommended description for this type of 

program as described in SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, and 3.4-2. 

The staff also notes that the applicant committed (Commitment No. 14) to enhance the 

Closed-Cycle Cooling Water Program prior to entering the period of extended operation. 

Specifically, the applicant committed to: (1) establish new recurring tasks to enhance the 

performance monitoring of the closed-cycle cooling water and chilled water systems; (2) perform 

one-time inspections of selected components in low or stagnant flow areas and interior surfaces 

of selected chemical mixing tanks and associated piping; (3) implement a pure water control 

program; and (4) perform a one-time inspection of selected components for the control area 

chilled water 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) 

Conclusion. On the basis of its audit and review of the applicant’s Closed-Cycle Cooling Water 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determines 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 No. 14 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 
Aging Management Review Results 

 3-90 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.6 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

Summary of Technical Information in the Application. LRA Section B.2.1.15 describes the 

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program with enhancements as consistent with GALL AMP XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.” The applicant 

stated that the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems Program manages loss of material for all cranes, trolley and hoist structural 

components, fuel handling systems and applicable rails that are within the scope of license 

renewal. The applicant also stated that visual inspections will be used to assess the conditions 

such as loss of material due to corrosion and visible signs of wear. 

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 whether 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 AMP XI.M23. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding element of GALL AMP XI.M23. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with the enhancement to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of the enhancements 

follows. 

Enhancement 1. LRA Section B.2.1.15 states that an enhancement will be made to the “scope 

of the program” and “parameters monitored or inspected” program elements. The applicant 

stated in the LRA that this enhancement expands on the existing program element by adding 

visual inspection of structural components and structural bolts for loss of material due to general 

corrosion, pitting, and crevice corrosion and structural bolting for loss of preload due to 

self-loosening. The GALL Report “scope of the program” program element states that, “The 

program manages the effects of general corrosion on the crane and trolley structural 

components for those cranes that are within the scope of 10 CFR 54.4, and the effects of wear 

on the rails in the rail system.” The GALL Report “parameters monitored or inspected” program 

element states that the program evaluates the effectiveness of the maintenance monitoring 

program and the effects of past and future usage on the structural reliability of cranes. The staff 

finds this enhancement to be acceptable because it makes this existing program consistent with 

the GALL Report and expands on the program elements to make them more specific. 

Enhancement 2. LRA Section B.2.1.15 states that an enhancement will be made to the “scope 

of the program” and “parameters monitored or inspected” program elements. The applicant 

stated that this enhancement expands on the existing program element by adding the 

requirement for visual inspection of the rails and the rail system for loss of material due to wear. 

The GALL Report “scope of the program” program element states that, “The program manages 

the effects of general corrosion on the crane and trolley structural components for those cranes 

that are within the scope of 10 CFR 54.4, and the effects of wear on the rails in the rail system.” 

The GALL Report “parameters monitored or inspected” program element states that the 
Aging Management Review Results 

 3-91 

program evaluates the effectiveness of the maintenance monitoring program and the effects of 

past and future usage on the structural reliability of cranes. The staff finds this enhancement to 

be acceptable because it makes this existing program consistent with the GALL Report and 

expands on the program elements to make them more specific. 

Enhancement 3. LRA Section B.2.1.15 states that an enhancement will be made to the 

“acceptance criteria” program element. The applicant stated that this enhancement expands on 

the existing program element by adding the requirement for evaluation of significant loss of 

material due to corrosion for structural components and structural bolts, and significant loss of 

material due to wear of rails in the rail system. The GALL Report “acceptance criteria” program 

element states, “Any significant visual indication of loss of material due to corrosion or wear is 

evaluated according to applicable industry standards and good industry practice.” The staff 

finds this enhancement to be acceptable because it makes this existing program consistent with 

the GALL Report. 

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 

AMP XI.M23 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.15 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program. The applicant stated that no occurrences of unacceptable corrosion for components 

within the scope of the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program have been identified. Additionally, the applicant stated 

that since HCGS cranes, hoists, trolleys, and fuel handling equipment have not been operated 

outside their design limits nor beyond their design lifetime, no fatigue-related structural failures 

have occurred. 

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 no 

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. 

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 of SRP-LR Section A.1.2.3.10 

and, therefore, the staff finds it acceptable. 

UFSAR Supplement. LRA Section A.2.1.15 provides the UFSAR supplement for the Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems 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. 
Aging Management Review Results 

 3-92 

The staff also notes that the applicant committed (Commitment No. 15) to enhance the 

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 use the 

existing program for license renewal and to inspect for loss of material due to corrosion or rail 

wear. 

The staff determines 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 Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed that its 

implementation through Commitment No. 15 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 also reviewed the UFSAR supplement for this AMP and concludes that it provides an 

adequate summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.7 Fire Protection 

Summary of Technical Information in the Application. LRA Section B.2.1.17 describes the Fire 

Protection Program as an existing program that is consistent, with an exception and 

enhancements, with GALL AMP XI.M26, “Fire Protection.” The applicant stated that the 

program manages the effects of aging for fire barriers, diesel fire pumps, fuel oil supply lines, 

the halon and carbon dioxide (CO2) systems, and associated components, through the use of 

periodic inspections and functional testing to detect aging effects prior to loss of intended 

functions. The applicant also stated that the program provides for: (1) visual inspections of fire 

barrier penetration seals for signs of degradation (e.g., change in material properties, loss of 

materials, cracking, and hardening); (2) visual examinations of the barrier walls, ceilings, and 

floors in structures within the scope of license renewal at a frequency of once each refueling 

outage; and (3) periodic visual and functional tests to manage the aging effects of fire doors and 

dampers and the external surfaces of the halon and CO2 fire suppression system components. 

The applicant further stated that performance tests of the diesel driven fire pump will be used to 

provide data for trending purposes and to detect degradation (corrosion) of the fuel supply lines 

before the loss of the component intended function occurs. 

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 whether 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 AMP XI.M26. 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 

AMP XI.M26, with the exception of the “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. 

The “detection of aging effects” program element of GALL AMP XI.M26 recommends that visual 

inspections of the halon and CO2 fire suppression systems be performed to detect any sign of 

degradation, such as corrosion, mechanical damage, or damage to dampers, and that a 

periodic functional test and inspection be performed at least once every 6 months. The 
Aging Management Review Results 

 3-93 

“acceptance criteria” program element of GALL AMP XI.M26 recommends that any sign of 

corrosion or mechanical damage of the halon and CO2 fire suppression systems be considered 

unacceptable. During its review of the program basis document and procedures used to verify 

the operation of the total flooding CO2 system, the staff noted that there were no visual 

inspection activities to check for degradation, such as corrosion or mechanical damage. The 

staff also noted that the acceptance criteria identified in the procedure did not address 

corrosion. 

By letter dated May 14, 2010, the staff issued RAI B.2.1.17-2 requesting that the applicant 

confirm how this is considered consistent with GALL AMP XI.M26, and if it is not, justify why this 

is not an exception or an enhancement. 

In its response dated June 14, 2010, the applicant added an additional enhancement to the 

program and stated that the Fire Protection Program will be enhanced to include visual 

inspection activities to check for degradation during performance of the halon and CO2 fire 

suppression system functional tests. The staff’s evaluation of this enhancement is addressed 

under Enhancement 3. 

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” and “acceptance criteria” program elements 

associated with the exception and enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of the 

exception and enhancements follows. 

Exception. LRA Section B.2.1.17 states an exception to the “parameters monitored or 

inspected” and “detection of aging effects” program elements. The exception states that the 

halon and CO2 fire suppression systems currently undergo functional testing every refueling 

cycle (18 months). The “parameters monitored or inspected” and “detection of aging effects” 

program elements of GALL AMP XI.M26 recommend that periodic visual inspections and 

functional testing be performed at least once every 6 months to examine halon and CO2 fire 

suppression systems for signs of degradation. 

The applicant stated that in addition to the 18-month functional testing, the halon fire 

suppression system is subject to visual inspections for system charge (storage tank weight) 

every 6 months, and the low-pressure CO2 fire suppression system is subject to weekly visual 

storage tank level and pressure checks. The applicant also stated that these test and 

inspection frequencies are considered sufficient to ensure system availability and operability 

based on the station operating history (e.g., corrective actions, completed surveillance test 

results) that shows no aging related events have been found that have adversely affected 

system operation. 

The staff reviewed the applicant’s CLB and confirmed that functional testing of the halon and 

CO2 fire suppression systems is performed once every 18 months. The staff also reviewed 

plant operating experience reports and did not find any evidence of age-related degradation in 

the halon or CO2 systems. However, during review of the applicant’s procedures referenced in 

the program basis document, the staff noted that neither the 6-month inspection for system 

charge nor the weekly inspection for tank level and pressure include inspection for signs of 

degradation, such as corrosion or damper damage, as recommended by GALL AMP XI.M26 for 

the visual inspections. Therefore, it was not clear to the staff if the exception applied to both the 

functional testing and visual inspections or to only the functional testing. 
Aging Management Review Results 

 3-94 

By letter dated May 14, 2010, the staff issued RAI B.2.1.17-1 requesting that the applicant 

clarify whether the exception applies to both functional testing and visual inspections or only 

applies to functional testing, which would indicate that the Fire Protection Program performs 

visual inspections at least once every 6 months for signs of degradation of the halon and CO2

fire suppression systems. If the visual inspection is not performed once every 6 months, the 

staff also requested that the applicant justify why this is not an exception to GALL AMP XI.M26. 

In its response dated June 14, 2010, the applicant stated that the GALL Report recommended 

visual inspections for corrosion and mechanical damage be performed during the system 

functional tests and that this exception was intended to apply to both the functional testing and 

the visual inspection frequencies. The applicant revised the exception to state that the halon 

and CO2 fire suppression systems currently undergo functional testing and inspection every 

refueling cycle (18 months). 

The staff finds the exception to visually inspect and functionally test the halon and CO2

suppression systems once every 18 months acceptable because the applicant is performing 

inspections and testing in accordance with its CLB. Plant operating experience has shown that 

the testing frequency is adequate to maintain system function. Visual inspections for system 

charge (storage tank weight) are performed every 6 months, and the CO2 fire suppression 

system storage tank level and pressure are checked weekly. 

Enhancement 1. LRA Section B.2.1.17 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements. In the enhancement, the applicant stated that it will expand on the existing 

program elements by providing additional inspection guidance to identify degradation of fire 

barrier walls, ceilings, and floors for aging effects, such as cracking, spalling, and loss of 

material caused by freeze-thaw, chemical attack, and reaction with aggregates. The staff 

confirmed that the applicant included this enhancement as Commitment No. 17 in LRA 

Appendix A, Table A.5. 

This enhancement, when implemented, will make the Fire Protection Program consistent with 

GALL AMP XI.M26, which recommends that visual inspection of the fire barrier walls, ceilings, 

and floors be examined for any sign of degradation, such as cracking, spalling, and loss of 

material caused by freeze-thaw, chemical attack, and reaction with aggregates. Based on its 

review, the staff finds the enhancement acceptable because it will make the program consistent 

with the GALL Report. 

Enhancement 2. LRA Section B.2.1.17 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements to expand on the existing program elements by providing specific guidance 

for examining the exposed external surfaces of the fire pump diesel fuel oil supply line for 

corrosion during pump tests. The staff confirmed that the applicant included this enhancement 

as Commitment No. 17 in LRA Appendix A, Table A.5. 

The staff notes that this enhancement, when implemented, will make the Fire Protection 

Program consistent with GALL AMP XI.M26, which recommends that performance of the fire 

pump is monitored during the periodic test to detect any signs of degradation in the fuel supply 

lines and to provide data for trending, and that the acceptance criteria include that no corrosion 

is acceptable in the fuel supply line for the diesel driven fire pump. Based on its review, the staff 

finds the enhancement acceptable because it will make the program consistent with the GALL 

Report. 
Aging Management Review Results 

 3-95 

Enhancement 3. By letter dated June 14, 2010, the applicant added an enhancement to the 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements to enhance the halon and CO2 fire suppression system 

functional test to include: (1) visual inspection of system piping and component external 

surfaces for signs of corrosion or other age-related degradation, and for mechanical damage; 

and (2) acceptance criteria stating that identified corrosion or mechanical damage will be 

evaluated, with corrective action taken as appropriate. The staff confirmed that the applicant 

included this enhancement in a revision to Commitment No. 17 in LRA Appendix A, Table A.5. 

The staff notes that this enhancement, when implemented, will make the Fire Protection 

Program consistent with GALL AMP XI.M26, which recommends that visual inspections of the 

halon and CO2 fire suppression system be performed to detect any sign of degradation, such as 

corrosion, mechanical damage, or damage to dampers, and that any signs of corrosion or 

mechanical damage of the halon and CO2 fire suppression system should be considered 

unacceptable. Based on its review, the staff finds the enhancement acceptable because it will 

make the program consistent with the GALL Report. 

Based on its audit and review of the applicant’s responses to RAIs B.2.1.17-1 and B.2.1.17-2, 

the staff finds that elements one through six of the applicant’s Fire Protection Program, with 

acceptable exception and enhancements, are consistent with the corresponding program 

elements of GALL AMP XI.M26 and, therefore, the staff finds it acceptable. 

Operating Experience. LRA Section B.2.1.17 summarizes operating experience related to the 

Fire Protection Program. The applicant stated that during routine fire door inspections using 

existing surveillance procedures, rust and corrosion were found on the exterior door surface and 

lower door frame of a fire door and that the door and frame were repaired and painted 

satisfactorily. The applicant also stated that in September 2006, the CO2 system fire dampers 

failed to reposition as required during a simulated functional test due to failure of an electronic 

signal that prevented an electronic relay from latching and that the applicant replaced the 

defective electronic control board and retested the system satisfactorily. The applicant further 

stated that in January 2006, a fire barrier was found damaged, so the applicant inspected areas 

in the vicinity of the damage to determine if any additional areas were affected and repaired the 

fireproofing material to acceptable conditions. 

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 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. 
Aging Management Review Results 

 3-96 

UFSAR Supplement. LRA Section A.1.17, as amended by letter dated June 14, 2010, provides 

the UFSAR supplement for the Fire Protection Program. The staff reviewed this UFSAR 

supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR Table 3.3-2. The staff also notes 

that the applicant committed (Commitment No. 17) to enhance the Fire Protection Program prior 

to entering the period of extended operation. Specifically, the applicant committed to enhance: 

(1) the routine inspection procedures to provide additional inspection guidance to identify 

degradation of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, 

and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates; 

(2) the fire pump supply line functional tests to provide specific guidance for examining exposed 

external surfaces of the fire pump diesel fuel oil supply line for corrosion during pump tests; and 

(3) the halon and CO2 fire suppression system functional test procedures to include visual 

inspection of system piping and component external surfaces for signs of corrosion or other 

age-related degradation, and for mechanical damage, and to include acceptance criteria stating 

that identified corrosion or mechanical damage will be evaluated, with corrective action taken as 

appropriate. 

The staff determines that the information in the UFSAR supplement, as amended by letter dated 

June 14, 2010, 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 and 

the applicant’s responses to the staff’s RAIs, the staff determines that those program elements 

for which the applicant claimed consistency with the GALL Report are consistent. The staff 

reviewed the exception and its justification and determines that the AMP, with the exception, is 

adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the 

enhancements and confirmed that their implementation through Commitment No. 17 prior to the 

period of extended operation will 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 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). 

3.0.3.2.8 Fire Water System 

Summary of Technical Information in the Application. LRA Section B.2.1.18 describes the 

existing Fire Water System Program as consistent, with enhancements, with GALL 

AMP XI.M27, “Fire Water System.” The applicant stated that the program manages aging for 

the water-based fire protection systems through periodic inspections, monitoring, and 

performance testing and that system functional tests, flow tests, flushes, and inspections are 

performed in accordance with the applicable guidance from National Fire Protection Association 

(NFPA) codes and standards. The applicant also stated that the program includes fire system 

main header flow tests, sprinkler system inspections, yard hydrant visual inspections, fire 

hydrant hose inspections, hydrostatic tests, gasket inspections, volumetric inspections, fire 

hydrant flow tests, and pump capacity tests performed periodically to assure that loss of 

material due to corrosion, microbiologically-influenced corrosion (MIC), or biofouling are 

managed such that the system intended functions are maintained. The applicant further stated 

that selected portions of the fire protection system piping, located aboveground and exposed to 
Aging Management Review Results 

 3-97 

water, will be inspected by non-intrusive volumetric examinations to ensure that aging effects 

are managed and that wall thickness is within acceptable limits. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether 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 AMP XI.M27. As discussed in the audit report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M27. 

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “acceptance criteria,” and “corrective actions” program 

elements associated with the enhancements to determine whether the program will be adequate 

to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows. 

Enhancement 1. LRA Section B.2.1.18 states an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements to inspect selected portions of the water-based fire 

protection system piping located aboveground and exposed internally to fire water using 

non-intrusive volumetric examinations. The applicant stated that these inspections will be 

performed prior to the period of extended operation and every 10 years thereafter. The staff 

confirmed that the applicant included this enhancement as Commitment No. 18 in LRA 

Appendix A, Table A-5. 

GALL AMP XI.M27 recommends that wall thickness evaluations of fire protection piping be 

performed on system components using non-intrusive techniques (e.g., volumetric testing) to 

identify evidence of loss of material due to corrosion 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. The staff finds this enhancement acceptable because performing 

non-intrusive examinations on the aboveground fire water piping every 10 years will make the 

program consistent with the recommendations in GALL AMP XI.M27. 

Enhancement 2. LRA Section B.2.1.18 states an enhancement to the “detection of aging 

effects” program element to replace or perform 50-year sprinkler head inspections and testing 

using the guidance of NFPA-25, “Standard for the Inspection, Testing and Maintenance of 

Water-Based Fire Protection Systems” (2002 Edition), Section 5-3.1.1. The applicant stated 

that these inspections will be performed by the 50-year inservice date and every 10 years 

thereafter. The staff confirmed that the applicant included this enhancement as Commitment 

No. 18 in LRA Appendix A, Table A-5. 

GALL AMP XI.M27 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. The staff finds this enhancement acceptable because it will make the 

program consistent with the recommendations in GALL AMP XI.M27. 

Based on its audit, 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 AMP XI.M27 and, therefore, the staff finds it acceptable. 
Aging Management Review Results 

 3-98 

Operating Experience. LRA Section B.2.1.18 summarizes operating experience related to the 

Fire Water System Program. The applicant stated that during routine monthly fire hydrant 

inspections in August 2001, water was found in the barrel of a hydrant that could not be drained 

and, therefore, the applicant replaced the hydrant with a new unit. The applicant inspected 

other hydrants, and none were found to have a leaking barrel. The applicant also stated that 

the motor-driven fire pump discharge flow became unstable during routine capacity testing in 

May 2002, so the applicant terminated the testing and performed troubleshooting that revealed 

the temporary startup strainer was still installed in the suction line leading to the pump and had 

become fouled. The applicant further stated that the startup strainer was removed, and all other 

fire pumps on site were inspected with no other startup strainers found installed. 

The applicant stated that the fire protection system manager has performed visual inspections 

of piping internal conditions when exposed during maintenance activities, and observed the 

piping internals to be in good condition with no significant internal fouling or corrosion buildup. 

The applicant also stated that the external piping condition is also routinely inspected and 

maintained by station procedures. 

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 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. In LRA Section A.2.1.18, the applicant provided the UFSAR supplement 

for the Fire 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 Table 3.3-2. The staff also notes that the applicant 

committed (Commitment No. 18) to enhance the Fire Water System Program prior to entering 

the period of extended operation. Specifically, the applicant committed to enhance the program 

to: (1) inspect selected portions of the water-based fire protection system piping located 

aboveground by non-intrusive volumetric examinations; these inspections shall be performed 

prior to the period of extended operation and will be performed every 10 years thereafter; 

(2) replace or perform 50-year sprinkler head inspections and testing using the guidance of 

NFPA-25, “Standard for the Inspection, Testing and Maintenance of Water-Based Fire 

Protection Systems” (2002 Edition), Section 5-3.1.1. These inspections will be performed prior 

to the 50-year inservice date and every 10 years thereafter. 
Aging Management Review Results 

 3-99 

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 Fire Water System Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed 

that their implementation through Commitment No. 18 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 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). 

3.0.3.2.9 Aboveground Steel Tanks 

Summary of Technical Information in the Application. LRA Section B.2.1.19 describes the 

existing Aboveground Steel Tanks Program as consistent, with enhancements, with GALL 

AMP XI.M29, “Aboveground Steel Tanks.” The applicant stated that the Aboveground Steel 

Tanks Program will be used to manage loss of material for the outdoor carbon steel tanks used 

for fire protection system water, fire diesel fuel oil, and CO2 pressurized gas. The applicant also 

stated that this is a condition monitoring program and it credits the application of paint and 

coatings to the external surfaces of the in-scope tanks as a corrosion prevention measure, and 

that the condition of the painted or coated external surfaces, as well as the condition of any 

exposed base metal, is monitored by this program. The applicant further stated that thickness 

measurements of the bottom of the fire water storage tank, the only in-scope tank in contact 

with the ground, will be conducted. The staff notes that the applicant’s inspection procedures 

ensure that the caulk/sealant joint between the tank and foundation interface is visually 

inspected during the inspection of the tank. 

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 whether 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 AMP XI.M29. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M29. 

The staff also reviewed the portions of the “preventive actions,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements associated with 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.2.1.19 states an enhancement to the “detection of aging 

effects,” “monitoring and trending,” and “acceptance criteria” program elements. The applicant 

stated that the program will be enhanced (Commitment No. 19) to require UT to obtain tank wall 

thickness measurements for the fire water storage tank. The applicant also stated that these 

measurements will be monitored and trended and the results would be evaluated against design 

thickness and the corrosion allowance. 
Aging Management Review Results 

 3-100 

The staff reviewed this enhancement against the corresponding program elements in GALL 

AMP XI.M29. On the basis of its review, the staff finds this enhancement acceptable because 

UT provides direct, quantitative measurement of the tank bottom thickness and this method 

addresses the GALL Report recommendation for an acceptable verification program to consist 

of thickness measurement of the tank bottom surface, evaluation of measurements against 

design thickness and corrosion allowance, and trended results. 

Enhancement 2. LRA Section B.2.1.19 states an enhancement to the “preventive actions,” 

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria” program 

elements. The applicant stated that the program will be enhanced to provide routine visual 

inspections of the external surfaces of the in-scope tanks including removal of insulation from 

the fire water storage tank. The applicant also stated that the inspections will be performed to 

detect degraded paint and coatings and any resulting metal degradation. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

AMP XI.M29. On the basis of its review, the staff finds this enhancement acceptable because it 

will provide adequate monitoring of the external surfaces of in-scope tanks, and the routine 

visual inspection methods address the GALL Report recommendation for periodic system 

walkdowns to monitor degradation of the protective paint or coating. 

Based on its audit, 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 AMP XI.M29 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.19 summarizes operating experience related to the 

Aboveground Steel Tanks Program. The applicant provided two examples of operating 

experience related to early detection of corrosion on steel tank surfaces through its routine 

visual inspections. In one example, the applicant stated that degraded coating and minor 

corrosion on the exposed surface of a fire water storage tank was detected during a walkdown 

associated with a semi-annual fire protection inspection. The applicant also stated that no 

leakage was observed and, based on an engineering evaluation, the integrity of the tank was 

not impacted. The applicant further stated that the deficient condition was entered into the 

corrective action program, and repairs were performed. In another instance of operating 

experience, the applicant described how corrective action was prompted when deteriorated 

paint was detected by routine visual inspection of a diesel fuel oil day tank. The applicant stated 

that the deficient condition was entered into the corrective action program and repairs were 

performed. 

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 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 
Aging Management Review Results 

 3-101 

of aging on SCCs 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. LRA Section A.2.1.19 provides the UFSAR supplement for the 

Aboveground Steel Tanks Program. 

The staff reviewed this UFSAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Tables 3.3-2 and 3.4-2. 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). 

The staff also notes that the applicant committed (Commitment No. 19) to enhance the 

Aboveground Steel Tanks Program prior to entering the period of extended operation. 

Specifically, the applicant committed to include internal UT measurements of the wall thickness 

on the bottom of the fire water storage tanks, and these measurements will be monitored, 

trended, and evaluated against design thickness and corrosion allowance to ensure that 

significant degradation does not occur. The program will also be enhanced to provide routine 

visual inspections of tank external surfaces, including removal of tank insulation from the fire 

water storage tank, to detect degraded paint and coatings and any resulting metal degradation. 

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 Aboveground Steel Tanks 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation through Commitment No. 19 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). 

3.0.3.2.10 Fuel Oil Chemistry 

Summary of Technical Information in the Application. LRA Section B.2.1.20 describes the 

existing Fuel Oil Chemistry Program as consistent, with exceptions and enhancements, with 

GALL AMP XI.M30, “Fuel Oil Chemistry.” The applicant stated that the Fuel Oil Chemistry 

Program includes preventive activities to provide assurance that contaminants are maintained at 

acceptable levels in fuel oil for systems and components within the scope of license renewal, to 

prevent loss of material. The program includes procedures for testing and maintaining the 

quality of stored and new fuel oil, inspection of the fuel oil storage tanks, and a one-time sample 

inspection (under the One-Time Inspection Program) of components in systems that contain fuel 

oil. 
Aging Management Review Results 

 3-102 

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 whether 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 AMP XI.M30. For these elements, the staff determined the need for 

additional clarification, which resulted in the issuance of an RAI. 

The staff also reviewed the portions of the “scope of the 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 whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these exceptions and enhancements follows. 

Exception 1. LRA Section B.2.1.20 states exceptions to the “scope of the program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements. The GALL Report AMP recommends periodic sampling of tanks in 

accordance with the manual sampling standards of ASTM D 4057-95 (2000). The applicant 

stated that the 280-gallon diesel fire pump fuel oil tank (T-565) samples are single point 

samples obtained from the tank drain line located off of the bottom of the tank. This sample is 

not in accordance with the manual sampling standards as described in ASTM D 4057. The 

applicant further stated that for fuel oil storage tanks of less than 159 cubic meters, spot 

sampling recommendations in ASTM D 4057-95 (2000) include a single sample from the middle 

(a distance of one-half of the depth of liquid below the liquid’s surface). The 280-gallon fire 

pump day tanks are 1.06 cubic meters, so the spot sampling recommendations in ASTM D 4057 

are applicable. Although the actual sample location for tanks is lower than prescribed by the 

ASTM D 4057 standard, the sample results are more likely to capture contaminants, water, and 

sediment, thus making this a conservative sample location for fuel oil containments. 

Additionally, the applicant stated that the diesel generator is run on a weekly basis (taking 

suction from the bottom of the tank) and significant stratification is unlikely in such a small tank 

that is mixed weekly. The staff reviewed this exception and found it acceptable because the 

sample location is lower, and thus more conservative, than that described in the ASTM 

standard, and because the generator is run weekly, which reduces the potential for significant 

stratification. 

Exception 2. LRA Section B.2.1.20 states exceptions to the “scope of the program,” “preventive 

actions,” “parameters monitored or inspected,” “detection of aging effects,” “monitoring and 

trending,” and “acceptance criteria” program elements. The GALL Report AMP recommends 

periodic sampling, draining, cleaning, and internal inspection of tanks to reduce the potential for 

loss of material by exposure to fuel oil contaminated with water and microbiological organisms. 

The applicant stated that multilevel sampling, tank bottom draining, cleaning, and internal 

inspection of the 550-gallon diesel fuel oil day tanks (1A-T-404, 1B-T-404, 1C-T-404, and 

1D-T-404) is not periodically performed. Instead, the applicant stated that fuel oil from the 

550-gallon day tanks is recirculated back to the 26,500-gallon storage tanks quarterly. To 

confirm the absence of any significant aging effects, the applicant will perform a one-time 

inspection of each of the 550-gallon day tanks and the condition will be entered into the 

corrective action program for resolution. The staff reviewed this exception and found it 

acceptable because: (1) the fuel oil contained within the tanks is analyzed prior to being placed 

in the tanks, (2) the fuel oil in the tanks is regularly replaced with fuel oil from a tank that is 

regularly analyzed for water and indications of microbiological growth, and (3) the applicant will 

verify the absence of any significant aging effects with a one-time inspection. 
Aging Management Review Results 

 3-103 

Exception 3. LRA Section B.2.1.20 states exceptions to the “scope of the program,” “preventive 

actions,” “parameters monitored or inspected,” “monitoring and trending,” and “acceptance 

criteria” program elements. The GALL Report AMP recommends the additions of biocides, 

stabilizers, and corrosion inhibitors to prevent degradation of the fuel oil quality. The Fuel Oil 

Chemistry Program does not require the addition of biocides, stabilizers, and corrosion 

inhibitors, but instead requires their use only in response to test results that indicate biocides, 

stabilizers, and corrosion inhibitors are needed. The staff reviewed this exception and found it 

acceptable because the Fuel Oil Chemistry Program includes analysis of new fuel oil prior to the 

addition to the fuel oil storage tanks, and analysis of existing fuel oil for particulate, water, and 

indications of biological growth. Additionally, the fuel oil tanks are drained of water and 

sediment during the regular fuel oil sample draws (in preparation for analysis), and the Fuel Oil 

Chemistry Program procedures require the addition of biocides, stabilizers, and corrosion 

inhibitors if testing results indicate their presence. 

Enhancement 1. LRA Section B.2.1.20 states enhancements to the “scope of the program,” 

“preventive actions,” “parameters monitored or inspected,” and “detection of aging effects” 

program elements. These enhancements provide equivalent requirements for fuel oil purity and 

fuel oil testing, as described by the Standard TSs. The staff compared these enhancements to 

the appropriate program elements in GALL AMP XI.M30, and because the enhancements are 

consistent with the program elements in GALL AMP XI.M30, the staff finds them acceptable. 

Enhancement 2. LRA Section B.2.1.20 states enhancements to the “scope of the program,” 

“preventive actions,” “parameters monitored or inspected,” and “corrective actions” program 

elements. The applicant stated that prior to the period of extended operation, the procedures 

will be enhanced to require the addition of biocides, stabilizers, and inhibitors if sampling or 

inspection activities detect biological activity, biological breakdown of the fuel, or corrosion 

products. The applicant further stated that the analysis for particulate contamination will be in 

accordance with modified ASTM D2276-00, Method A and analysis using this method is 

sufficient for the detection of corrosion products at an early stage. The staff compared these 

enhancements to the appropriate program elements in GALL AMP XI.M30 and finds them 

acceptable for providing adequate assurance that aging effects will be managed during the 

period of extended operation. 

Enhancement 3. LRA Section B.2.1.20 states an enhancement to the “scope of the program,” 

“preventive actions,” “parameters monitored or inspected,” and “detection of aging effects” 

program elements. The applicant stated that prior to the period of extended operation, an 

internal inspection of the diesel fire pump fuel oil 280-gallon tank (T-565) using visual 

inspections and ultrasonic thickness examination of the tank bottom will be performed. The staff 

compared these enhancements to the appropriate program elements in GALL AMP XI.M30, and 

because the enhancements are consistent with the program elements in GALL AMP XI.M30, 

the staff finds them acceptable. 

Enhancement 4. LRA Section B.2.1.20 states an enhancement to the “scope of the program,” 

“preventive actions,” “parameters monitored or inspected,” and “detection of aging effects” 

program elements. The applicant stated that prior to the period of extended operation, the 

procedures will be enhanced to provide quarterly water and sediment multilevel sampling on the 

diesel fuel oil storage tanks in accordance with ASTM D2709. During the audit, the staff 

questioned the applicant about an unclear testing requirement in a proposed procedure that was 

being developed as part of Enhancement 4. 
Aging Management Review Results 

 3-104 

By letter dated June 14, 2010, the staff issued RAI 3.0.3.2.10-01 which stated there was 

insufficient detail in the proposed procedure to provide reasonable assurance that the procedure 

would allow for effective detection of water in the fuel oil system. 

In its response dated July 12, 2010, the applicant responded by stating that the Fuel Oil 

Chemistry Program includes existing procedures for sampling new fuel oil deliveries and stored 

fuel oil, and that these procedures require analysis of the sampled fuel oil for the presence of 

water and sediment by a qualified laboratory in accordance with ASTM Standard D2709, which 

is consistent with GALL AMP XI.M30. The applicant further stated that the unclear testing 

requirement in the proposed procedure would be removed and the wording from the existing 

Fuel Oil Chemistry Program procedure would be retained. The staff compared these 

enhancements to the appropriate program elements in GALL AMP XI.M30, and because the 

enhancements are consistent with the program elements in GALL AMP XI.M30, the staff finds 

them acceptable. 

Enhancement 5. LRA Section B.2.1.20 states an enhancement to the “scope of the program,” 

“preventive actions,” “parameters monitored or inspected,” and “detection of aging effects” 

program elements. The applicant stated that prior to the period of extended operation, the 

procedures will be enhanced to provide for internal inspection of the diesel fuel oil storage tanks 

using visual inspections and ultrasonic thickness examination of the tank bottoms. The staff 

compared these enhancements to the appropriate program elements in GALL AMP XI.M30, and 

because the enhancements are consistent with the program elements in GALL AMP XI.M30, 

the staff finds them acceptable. 

Enhancement 6. LRA Section B.2.1.20 states an enhancement to the “scope of the program,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements. The applicant stated that prior to the period of 

extended operation, the procedures will be enhanced to provide quarterly particulate sampling 

of the diesel fire pump fuel oil 280-gallon tank (T-565) in accordance with modified ASTM 

D2276-00, Method A. The modification consists of using a filter with a pore size of 3.0 microns 

instead of 0.8 microns. The staff compared these enhancements to the appropriate program 

elements in GALL AMP XI.M30, and because the enhancements are consistent with the 

program elements in GALL AMP XI.M30, the staff finds them acceptable. 

Enhancement 7. LRA Section B.2.1.20 states an enhancement to the “scope of the program,” 

“parameters monitored or inspected,” and “detection of aging effects” program elements. The 

applicant stated that prior to the period of extended operation, the procedures will be enhanced 

to provide a one-time inspection of each of the 550-gallon diesel fuel oil day tanks, to verify the 

absence of any significant aging effects. The staff compared these enhancements to the 

appropriate program elements in GALL AMP XI.M30, and because the enhancements are 

consistent with the program elements in GALL AMP XI.M30, the staff finds them acceptable. 

Based on its audit and review of the applicant’s response to RAI 3.0.3.2.10-01, 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 AMP XI.M30 and are, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.20 summarizes operating experience related to the 

Fuel Oil Chemistry Program. The applicant stated that its operating experience has shown that 

loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion and 
Aging Management Review Results 

 3-105 

fouling are being adequately managed. The applicant also provided the following operational 

experience: 

 (1) On November 5, 2003, during routine sampling of the diesel fuel oil tank (1G-T-403), 

sediment was observed in the purge volume prior to obtaining the fuel oil sample from 

the bottom drain valve. After performing the proper flushes, a sample was obtained and 

sent to an offsite laboratory for analysis. Additionally, 8-gallons were purged from the 

sample line, thus removing any remaining sediment from the bottom of the tank. After 

further investigation it was determined that there was a discrepancy in the two sampling 

techniques used during the routine task (bottom sample and a sample bomb, which is 

taken 6–12 inches from the tank bottom). Typically, the bottom drain sample is placed in 

a glass bottle (to accommodate visual inspection) and the sample bomb is typically 

transferred to a poly bottle. In the case of the samples taken on November 5, 2003, the 

bottles used were reversed from those typically used. As a result, along with inadequate 

labeling of the sample point, the wrong analysis was performed on the samples. The 

sample drawn using the sample bomb (the one in the glass bottle) was visually 

inspected and there was no water or sediment observed. The sample drawn from the 

bottom drain (the one in the poly bottle) was being analyzed for particulate amount. This 

analysis result was likely to be unsatisfactory because the particulates settle at the 

bottom of the tank. This is why regular particulate sampling is done via the bomb 

method and not from the bottom of the tank. Additional samples were drawn on 

November 6, 2003, and were analyzed. For the bottom drain sample, no sediment and 

no water was observed. For the bomb sample, analysis results were less than 

0.01 milligrams per liter (mg/L), which is well below the 10 mg/L specification. The 

sampling procedure was enhanced to specify the type of bottle used and the 

expectations on sample labeling. This operating experience provides objective evidence 

that the Fuel Oil Chemistry Program identifies unsatisfactory results through routine 

sampling of the fuel oil tanks and provides timely investigation and resolution of the 

issue. Additionally, the Fuel Oil Chemistry Program initiates corrective actions to 

prevent reoccurrence of the similar events. 

 (2) On February 4, 2004, it was identified that the particulate concentration of the 1HT-403 

diesel fuel oil tank increased from less than 0.01 mg/L to 3.86 mg/L. The sample that 

showed the increase to 3.86 mg/L was taken on January 30, 2004. The previous 

sample of less than 0.01 mg/L was taken on November 6, 2003. Sample results were 

verified with duplicate testing. However, further investigation revealed that the samples 

taken on January 30, 2004, were processed incorrectly. This was due to a bad sampling 

technique. The procedure was then analyzed, and the chemistry department decided to 

add a pre-job brief prior to the sampling evolutions to enhance the quality of the testing. 

New samples were taken and particulate concentration was found to be less than 

0.01 mg/L. This operating experience provides objective evidence that the fuel oil 

chemistry sampling activities identify abnormal test results due to improper techniques or 

procedures and puts barriers in place to prevent reoccurrence in the future. 

 (3) In September 2004, an inspection and cleaning of the diesel fire pump fuel oil tank 

(T-565) identified that the inside of the tank was corroded and the liner was degraded. 

The diesel fire pump fuel oil tank was drained, steam cleaned, and inspected. The 

inspection showed minor internal surface rust and scaling at some joints, but it was not 

excessive. The minor rust and scaling would in no way affect the structural integrity of 

the tank. The apparent cause of the rust was water in the bottom of the tank. 

Preventive maintenance activities were put into place to drain water and sediment from 
Aging Management Review Results 

 3-106 

the bottom of the tank to prevent reoccurrence. This provides objective evidence that 

periodic inspection of the tanks identifies degradation prior to the loss of intended 

function. In addition, this example illustrates the implementation of corrective actions in 

order to prevent degraded conditions from occurring in the future. 

During the audit, the staff reviewed operating experience information in the application 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. 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 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. LRA Section A.2.1.20 provides the UFSAR supplement for the Fuel Oil 

Chemistry Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.3-2. The staff also notes that the applicant committed (Commitment No. 20) to 

enhance the Fuel Oil Chemistry Program and perform one-time inspections, prior to entering the 

period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Fuel Oil Chemistry Program, 

the staff finds 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 finds 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 No. 20, 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). 
Aging Management Review Results 

 3-107 

3.0.3.2.11 Reactor Vessel Surveillance 

Summary of Technical Information in the Application. LRA Section B.2.1.21 describes the 

existing Reactor Vessel Surveillance Program as consistent, with enhancements, with GALL 

AMP XI.M31, “Reactor Vessel Surveillance.” 

The applicant stated that its program manages the loss of fracture toughness due to neutron 

irradiation embrittlement of the reactor vessel beltline materials. The applicant also stated that 

its program meets the requirements of 10 CFR 50, Appendix H. The applicant stated further 

that its program evaluates neutron embrittlement by projecting USE for reactor materials and 

impact on adjusted reference temperature (ART) for the development of P-T limit curves. 

The applicant stated that embrittlement evaluations are performed in accordance with RG 1.99, 

Revision 2 and its program is also part of the BWRVIP ISP described in BWRVIP-86-A and 

BWRVIP-116, and approved by the staff. The applicant stated that the schedule for removing 

surveillance capsules is in accordance with the timetable specified in BWRVIP-86-A for the 

current operating term and in accordance with BWRVIP-116 for the period of extended 

operation. 

The applicant stated the program monitors plant operating conditions to ensure appropriate 

steps are taken if reactor vessel exposure conditions are altered, such as the review and 

updating of 60-year fluence projections to support USE calculations and P-T limit curves. The 

applicant also stated that its program includes condition monitoring by removal and analysis of 

surveillance capsules as part of the BWRVIP ISP. 

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 whether 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 AMP XI.M31. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M31. 

The applicant described its program for monitoring irradiation embrittlement of the RPV through 

testing that monitors the properties of the beltline materials. LRA Section B.2.1.21 states that 

the Reactor Vessel Surveillance Program will follow the requirements of the BWRVIP ISP and 

will apply the ISP data to the HCGS unit. 

10 CFR Part 50, Appendix H requires that an ISP, which is used as a basis for a facility’s 

reactor vessel surveillance program, be reviewed and approved by the staff. The staff noted 

that the ISP to be used by the applicant is a program that was developed by the BWRVIP, and 

the applicant will apply the BWRVIP ISP as the method by which HCGS will comply with the 

requirements of 10 CFR Part 50, Appendix H. 

The applicant has implemented the BWRVIP ISP based on the BWRVIP-86-A report. The staff 

noted that this report is consistent with GALL AMP XI.M31 for the period of its current license. 

The staff concluded that the BWRVIP ISP in BWRVIP-86-A is acceptable for BWR licensee 

implementation provided that all participating licensees use one or more compatible neutron 

fluence methodologies. The staff’s acceptance of the BWRVIP ISP for the current license 

period at HCGS is documented in the staff’s SER dated July 23, 2004, which is addressed in 

License Amendment 151. 
Aging Management Review Results 

 3-108 

In addition, the BWRVIP developed an updated version of the ISP in the BWRVIP-116 report, 

which provides guidelines for an ISP to monitor neutron irradiation embrittlement of the RPV 

beltline materials for all U.S. BWR power plants for the period of extended operation. The 

BWRVIP ISP identifies capsules that must be tested to monitor neutron radiation embrittlement 

for all licensees participating in the ISP and identifies capsules that are available on a 

“contingency” basis (deferred capsules). However, the staff noted that no guidance is provided 

in the BWRVIP-116 for continued use, storage, or testing of deferred capsules. Table 3-3 of the 

BWRVIP-116 report indicates that HCGS has two capsules in the reactor that are scheduled to 

be removed and tested, one before and one after the beginning of the period of extended 

operation. 

The applicant stated in its Reactor Vessel Surveillance Program and LRA Section A.2.1.21 that 

the Reactor Vessel Surveillance Program is part of the ISP described in BWRVIP-86-A and 

BWRVIP-116 and it will follow the requirements of the BWRVIP ISP and all of the conditions 

described in the SE, dated February 24, 2006. 

The staff also reviewed the portions of the “detection of aging effects,” “acceptance criteria,” 

“confirmation process,” and “administrative controls” program elements associated with the 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.2.1.21 states an enhancement to the “acceptance criteria” and 

“confirmation process” program elements of GALL AMP XI.M31 as follows: 

Hope Creek will implement the requirements of BWRVIP-116, “BWR Vessel and 

Internals Project Integrated Surveillance Program (ISP) Implementation for 

License Renewal,” including the conditions specified by the NRC in its Safety 

Evaluation dated February 24, 2006. 

Based on its review, the staff finds this enhancement acceptable because the applicant is 

implementing BWRVIP-116, which is a program approved by the staff in its SE dated 

February 24, 2006, which adequately addresses the requirements of 10 CFR Part 50, 

Appendix H for BWR licensees through the end of the facility’s proposed 60-year operating 

license. 

Enhancement 2. LRA Section B.2.1.21 states an enhancement to the “detection of aging 

effects” and “administrative controls” program elements of GALL AMP XI.M31 as follows: 

If future plant operations exceed the limitations specified in RG 1.99, the impact 

of plant operation changes on the extent of reactor vessel embrittlement will be 

evaluated and the NRC will be notified. Similarly, if future plant operation 

exceeds the bounds established by surveillance data that are to determine Upper 

Shelf Energy or P-T limits, then the impact of plant operation changes on the 

extent of reactor vessel embrittlement will be evaluated and the NRC will be 

notified. Additionally, if all the surveillance capsules are removed, then operating 

restrictions will be established to ensure that the plant is operated within the 

conditions to which the surveillance capsules were exposed. If the reactor vessel 

exposure conditions (neutron flux, spectrum, irradiation temperature, etc.) are 

altered, then the basis for the projection to 60 years is reviewed; and, if deemed 

appropriate, a revised fluence projection is prepared and the effects of the 

revised fluence analysis on neutron embrittlement calculations will be evaluated. 

If necessary an active surveillance program will be reinstituted for Hope Creek. 
Aging Management Review Results 

 3-109 

The employment of additional surveillance specimens will be coordinated through 

the BWRVIP Integrated Surveillance Program (ISP). Any changes to the reactor 

vessel exposure conditions and the potential need to re-institute a vessel 

surveillance program will be discussed with the NRC staff prior to changing the 

plant's licensing basis. 

The staff reviewed the “detection of aging effects” and “administrative controls” program 

elements of GALL AMP XI.M31. Based on its review, the staff finds this enhancement 

acceptable because when enhanced, the applicant’s program will be consistent with the 

recommendations of the “detection of aging effects” and “administrative controls” program 

elements of GALL AMP XI.M31, and the program, when enhanced, meets the criteria for an 

acceptable reactor vessel surveillance program as recommended in GALL AMP XI.M31. 

On the basis of its review, the staff finds the applicant has demonstrated that the effects of 

aging due to loss of fracture toughness of the RPV beltline region will be adequately managed 

so that the intended functions will be maintained consistent with the CLB for the period of 

extended operation, in accordance with 10 CFR 54.21(a)(3). 

Based on its audit, the staff finds that elements one through six of the applicant’s Reactor 

Vessel Surveillance Program, with acceptable enhancements, are consistent with the 

corresponding program elements of GALL AMP XI.M31 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.21 summarizes operating experience related to the 

Reactor Vessel Surveillance Program. LRA Section B.2.1.21 contains two examples of relevant 

operating experience. The staff noted that the first capsule at HCGS was removed in 1994 and 

tested prior to the implementation of the ISP. The staff further noted that the analysis of the 

results indicated that the capsule received an average fast neutron fluence (E > 1.0 MeV) that 

was equivalent to a 32 EFPY fluence at the inner wall of the vessel, and the projected Charpy 

USE and ART for 32 EFPY were more than adequate to continue safe operation. 

The staff noted that in 2004, the plant was granted an EPU, which resulted in an increase in the 

projected neutron fluence value for the limiting beltline materials at the end of the 40-year life of 

the plant. The applicant reanalyzed the USE and ART calculations in RG 1.99, Revision 2 to 

confirm that the projected toughness of the vessel remained at acceptable levels for the 

remainder of the current license period. The staff noted that the results were used to generate 

new P-T limits for normal operations of the plant. The staff confirmed the updated analyses with 

independent calculations. 

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 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 
Aging Management Review Results 

 3-110 

“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.2.1.21 provides the UFSAR supplement for the Reactor 

Vessel Surveillance Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. The staff also notes that the applicant committed 

(Commitment No. 21) to enhance the Reactor Vessel Surveillance Program prior to entering the 

period of extended operation. Specifically, the applicant committed to the actions as described 

above in Enhancements 1 and 2. The staff reviewed the applicant’s proposed UFSAR 

supplement and Commitment No. 21 and determined that the applicant is in accordance with 

10 CFR Part 50, Appendix H. 

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 Reactor Vessel Surveillance 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements 

and confirmed that their implementation through Commitment No. 21 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). 

3.0.3.2.12 Buried Piping Inspection 

Summary of Technical Information in the Application. LRA Section B.2.1.24 as supplemented 

by letters dated September 1, 2010, and October 29, 2010, describes the existing Buried Piping 

Inspection Program as consistent, with an enhancement, with GALL AMP XI.M34, “Buried 

Piping and Tanks Inspection.” The applicant stated that the program provides aging 

management of carbon steel, ductile cast iron, and gray cast iron buried piping susceptible to 

general corrosion, pitting, crevice corrosion, and microbiologically-influenced corrosion. The 

applicant also stated that the program relies on the visual inspection of excavated piping, 

including the associated coatings and wrappings. The applicant further stated that there are no 

in–scope buried tanks. 

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 whether 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 AMP XI.M34. As discussed in the Audit Report, the staff confirmed that 

these elements are consistent with the corresponding elements of GALL AMP XI.M34. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with an enhancement to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this enhancement follows: 
Aging Management Review Results 

 3-111 

Enhancement. LRA Section B.2.1.24 states an enhancement to the “detection of aging effects” 

program element. The applicant stated that the program will be enhanced to include at least 

one inspection each of carbon steel, gray cast iron, and ductile iron piping within the period of 

10 years prior to the beginning of the period of extended operation. The applicant also stated 

that the enhancement specifies that access to each buried piping to be inspected will be 

conducted as part of either an opportunistic or a focused excavation and inspection. The 

applicant further stated that the enhancement specifies that a minimum of one additional 

inspection will be conducted for each material type within the first 10 years of the period of 

extended operation. 

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 AMP XI.M34. 

Based on its audit, the staff finds that elements one through six of the applicant’s Buried Piping 

Inspection Program, with acceptable enhancements are consistent with the corresponding 

program elements of GALL AMP XI.M34 and, therefore, acceptable. The staff notes that even 

though the applicant has demonstrated consistency with each of the program elements in GALL 

AMP XI.M34, based on recent industry operating experience, the staff needed further 

information related to cathodic protection, coatings, and backfill quality in the vicinity of buried 

piping. The staff issued RAIs B.2.1.24 and B.2.1.24-02 and their evaluations are documented in 

the “operating experience” program element. 

The applicant subsequently revised its enhancement in its response dated October 29, 2010, to 

RAI B.2.1.24-02. The revised enhancement states: 

At least one opportunistic or focused excavation and inspection will be performed 

on each of the material groupings, which include carbon steel, ductile cast iron, 

and gray cast iron piping and components during each ten year period, beginning 

ten years prior to entry in the period of extended operation. A second 

opportunistic or focused excavation and inspection on a carbon steel piping 

segment, which is not cathodically protected, will be performed on the service 

water system during each ten year period, beginning ten years prior to entry into 

the period of extended operation. A different segment will be inspected in each 

ten year period. 

The staff finds this enhancement acceptable because the applicant has demonstrated 

consistency with each of the program elements in GALL AMP XI.M34 and based its 

enhancement on recent industry operating experience 

Operating Experience. LRA Section B.2.1.24 summarizes operating experience related to the 

Buried Piping Inspection Program. The applicant stated that risk ranking methods were used to 

identify locations where susceptibility to corrosion could be anticipated, specifically citing 

planned inspections for the carbon steel service water piping. The applicant also stated that 

opportunistic inspections were performed during excavations for piping repairs, and no 

significant age–related deficiencies were documented. 

Given that there have been a number of recent industry events involving leakage from buried or 

underground piping, the staff needs further information to evaluate the impact that these recent 

industry events might have on the applicant’s Buried Piping and Tanks Inspection Program. By 

letter dated August 6, 2010, the staff issued RAI B.2.1.24 requesting that the applicant provide 
Aging Management Review Results 

 3-112 

information regarding how the applicant will incorporate the recent industry operating 

experience into its aging management reviews and programs. 

In its response dated September 1, 2010, the applicant stated that there have been no leaks of 

buried in-scope piping as a result of external piping corrosion, and inspections of coatings that 

have occurred during opportunistic inspections of ductile cast iron fire protection piping have 

also found the coatings to be in acceptable condition. The applicant also stated that it has risk 

ranked all buried piping in accordance with NACE and EPRI guidelines and the NEI Industry 

Initiative on Buried Piping. Based on these risk rankings, inspections of the coating and 

external surfaces of the pipe were conducted. The applicant further stated that portions of the 

in-scope steel fire protection system are cathodically protected; the rectifiers for the cathodic 

protection system are monitored on a semi-monthly basis and inspected and tested on an 

annual basis; and for the past 5 years, cathodic protection availability has exceeded 90 percent. 

The applicant stated that when conducting visual inspection, it will conduct excavated visual 

inspections of at least 8 linear feet, when practical, of buried piping. The applicant commited to 

at least one opportunistic or focused excavation and inspection to be performed on each of the 

material groupings, which include carbon steel, galvanized steel, ductile cast iron, and gray cast 

iron piping and components during each 10-year period, beginning 10 years prior to entry in the 

period of extended operation. 

By letter dated October 12, 2010, the staff issued follow-up RAI B.2.1.24-02 requesting that the 

applicant: (a) define what is meant by excavating 8 feet of pipe when practical, state what 

alternative means will be utilized to determine the condition of the buried pipe and its coatings, 

or justify why inspecting less than 8 feet is sufficient to provide a reasonable assurance of the 

condition of the pipe and coatings; (b) clarify what portions of buried steel piping are protected 

by cathodic protection; if some portions of steel piping are not protected by a cathodic protection 

system, justify the scope of planned inspections; (c) clarify the periodicity of NACE potential 

surveys and if not conducted on an annual basis, provide justification; and (d) provide details on 

the quality of backfill in the vicinity of in-scope buried pipes. This was considered to be open 

item OI 3.0.3.2.12-1 during the issuance of the SER with open items. 

In its response dated October 29, 2010, the applicant stated that, in reviewing candidate 

inspection sites, the applicant had determined that there is no need to have the phrase “when 

practical” in relation to examining 8 feet of pipe and the RAI response was subsequently revised 

accordingly to retract the word “when practical.” Therefore, the applicant concluded that there is 

no need to provide alternative inspection details for less than 8-foot inspections. 

Also, the applicant stated that portions of the fire protection system are not cathodically 

protected. The applicant identified an error in its LRA and stated that there is no galvanized 

steel fire protection piping exposed to an external soil environment; LRA Table 3.3.2-10 was 

revised accordingly. The applicant further stated that it has also revised the LRA to inspect a 

buried carbon steel pipe segment in the non-cathodically protected portion of fire protection 

system in place of the stated inspection of buried galvanized steel piping. The applicant noted 

that HCGS contains only two systems (service water and fire protection) within the scope of 

license renewal that contains buried carbon steel piping that are not cathodically protected. 

Furthermore, the applicant identified an error in the LRA and stated that the condensate storage 

and transfer system has no steel pipe sleeves within the scope of license renewal; LRA 

Table 3.4.2-1 was revised accordingly. 
Aging Management Review Results 

 3-113 

Additionally, the applicant stated that the service water system has four 36-inch diameter steel 

piping spools that provide a transition from the reinforced concrete pipe to steel piping where 

the service system headers penetrate the service water intake structure and reactor building. 

The total length of these four piping spools is 12 feet and the piping spools are not cathodically 

protected. The applicant stated that it will inspect two of the four piping spools during the 

October 2010 refueling outage and one different piping spool of the four piping spools in each 

10-year period starting 10 years prior to the period of extended operation. Specifically, the 

applicant committed to perform an opportunistic or focused excavation and inspection on a 

carbon steel piping segment, which is not cathodically protected, on the service water system 

during each 10-year period, beginning 10 years prior to entry into the period of extended 

operation. A different segment will be inspected in each 10-year period. The applicant later 

informed the staff (ADAMS Accession No. ML110540526) that during the October 2010 outage, 

two of the four service water system segments, located at the service water intake structure and 

the reactor building, were inspected. The applicant found that both pipes were coated and the 

coating was in good to excellent condition. The coatings were removed on each pipe to expose 

the bare metal, and the applicant found that the exposed metal surfaces of the pipes were also 

in excellent condition. 

Also, to clarify the periodicity of NACE potential surveys, the applicant stated that annual 

cathodic protection system effectiveness testing is conducted in accordance with NACE 

SP0169-2007. The testing results are documented and trended by the cathodic protection 

system manager and adverse trends are entered into the corrective action program. The 

applicant also stated that HCGS will maintain the annual testing frequency. 

Finally, the applicant stated that buried piping were backfilled during original construction in 

accordance with construction backfill specification. The applicant stated the construction backfill 

specifications as: 

Bedding material within six inches of the buried coated piping will consist of sand, 

or an approved well graded granular material free from stones greater than 3/8 

inches in diameter, or a lean fillcrete or sandcrete. The backfill requirements for 

the Service Water System pre-stressed concrete pipe were difference than 

requirements for coated metallic pipe since coating damage is not a concern. 

Bedding material for this piping (within 6 inches of the pipe) was required to be 

lean concrete or crushed stones not greater that 1 inch diameter. 

The buried pipe inspection procedures require that the condition of backfill and coatings be 

documented. Review of inspection records note that coatings were found in acceptable 

condition. 

Based on its review, the staff finds the applicant’s response to RAI B.2.1.24 and 

RAI B.2.1.24-02 acceptable because: (a) the applicant will excavate a minimum of 8 feet of pipe 

during each inspection; (b) current inspections have demonstrated that coatings are in 

acceptable condition; (c) although portions of the fire protection system are not cathodically 

protected, the applicant has committed to perform inspections of buried fire protection piping in 

each 10-year period starting 10 years prior to entry into the period of extended operation; (d) the 

applicant has committed to perform inspections of buried service water system piping, that are 

not cathodically protected, in each 10-year period starting 10 years prior to entry into the period 

of extended operation; (e) the applicant has committed to perform inspections of buried piping of 

ductile cast iron piping and gray cast iron piping in each 10-year period starting 10 years prior to 

entry into the period of extended operation; (f) the rectifiers for the cathodic protection system 
Aging Management Review Results 

 3-114 

are monitored on a semi-monthly basis and inspected and tested on an annual basis; annual 

cathodic protection system effectiveness testing is conducted in accordance with NACE 

SP0169-2007; and for the past 5 years, cathodic protection availability has exceeded 

90 percent; and (g) the applicant has appropriate backfill specifications, with inspections to 

demonstrate that coatings are in acceptable condition. The staff’s concerns described in 

RAI B.2.1.24 and RAI B.2.1.24-02 are resolved. Open item OI 3.0.3.2.12-1 is closed. 

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

RAIs B.2.1.24 and B.2.1.24-02, 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. LRA Section A.2.1.24 provides the UFSAR supplement for the Buried 

Piping Inspection Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. 

The staff also notes that the applicant committed (Commitment No. 24) to enhance the Buried 

Piping Inspection Program prior to entering the period of extended operation. Specifically, the 

applicant committed to include: 

At least one opportunistic or focused excavation and inspection will be performed 

on each of the material groupings, which include carbon steel, ductile cast iron, 

and gray cast iron piping and components during each ten year period, beginning 

ten years prior to entry in the period of extended operation. A second 

opportunistic or focused excavation and inspection on a carbon steel piping 

segment, which is not cathodically protected, will be performed on the service 

water system during each ten year period, beginning ten years prior to entry into 

the period of extended operation. A different segment will be inspected in each 

ten year period. 

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 Buried Piping Inspection 

Program, the resolution of RAI B.2.1.24 and RAI B.2.1.24-02, and closure of open item 

OI 3.0.3.2.12-1, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. Also, the staff reviewed the 

enhancement and confirmed that its implementation through Commitment No. 24 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). 
Aging Management Review Results 

 3-115 

3.0.3.2.13 Lubricating Oil Analysis 

Summary of Technical Information in the Application. LRA Section B.2.1.27 describes the 

existing Lubricating Oil Analysis Program as consistent, with an exception, with GALL 

AMP XI.M39, “Lubricating Oil Analysis Program.” The applicant stated that the Lubricating Oil 

Analysis Program provides oil condition monitoring activities to manage the loss of material and 

the reduction of heat transfer in piping, piping components, piping elements, heat exchangers, 

and tanks within the scope of license renewal exposed to a lubricating oil environment. The 

program includes procedures for sampling, analysis, and condition monitoring activities to 

identify specific wear products and contamination and determine the physical properties of 

lubricating oil within operating machinery. 

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 whether 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 AMP XI.M39. The staff confirmed that these elements are consistent with the 

corresponding elements of GALL AMP XI.M39, with the exception of the “parameters monitored 

or inspected” program element. 

The staff reviewed the portions of the “parameters monitored or inspected” program element 

associated with the exception to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of the exception follows. 

Exception. LRA Section B.2.1.27 states an exception to the “parameters monitored or 

inspected” program element. The GALL Report AMP recommends the determination of 

viscosity, neutralization number, and flash point for components that do not have regular oil 

changes, to verify the oil is suitable for continued use. The applicant stated that the 

determination of flash point in lubricating oil is used to indicate the presence of highly volatile or 

flammable materials in a relatively nonvolatile or nonflammable material, such as found with fuel 

contamination in lubricating oil. The existing Lubricating Oil Analysis Program includes flash 

point analysis for the in-service EDG lubricating oil (the only potential application for the 

introduction of highly volatile or flammable materials) and for all new lubricating oil. The 

applicant stated further that for the remaining components within the scope of the program 

determination of flash point is not measured. The staff reviewed this exception and found it 

acceptable because the analyses proposed by the applicant address flash point for all new lube 

oil and for all existing lube oil that has the potential for fuel contamination, which meets the 

intent of the corresponding GALL Report program element. 

Based on its audit, the staff finds that elements one through six of the applicant’s Lubricating Oil 

Analysis Program, with an acceptable exception, are consistent with the corresponding program 

elements of GALL AMP XI.M39 and are, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.27 summarizes operating experience related to the 

Lubricating Oil Analysis Program. The applicant stated that its operating experience has shown 

that aging effects/mechanisms are being adequately managed and that the Lubricating Oil 

Analysis Program will be effective in assuring that intended functions will be maintained 

consistent with the CLB for the period of extended operation. The applicant also provided the 

following operational experience: 
Aging Management Review Results 

 3-116 

 (1) In March 2008, a lubricating oil sample was taken from the “D” emergency diesel engine 

crankcase in accordance with the predictive maintenance program. The total base 

number (TBN) was in the Fault range for the type of oil. This was an unexpected step 

change from past experience. The condition was entered into the corrective action 

program. An additional sample was taken in April 2008 to monitor the condition of the 

lubricating oil and to ensure that the results of the March 2008 sample were accurate. 

Split samples were sent to two laboratories. Replacement of the lubricating oil was 

unnecessary because the TBN results from the two laboratories were consistent and 

within the normal range for the type of oil. Therefore, this example provides objective 

evidence that the Lubricating Oil Analysis Program is capable of making prudent 

recommendations based on sample results, performing additional sampling to monitor 

critical lubricating oil parameters and to verify the validity of earlier samples, and 

adjusting corrective actions based on all of the analytical information to ensure that 

intended functions are maintained. 

 (2) In July 2005, a lubricating oil sample was taken from the “B” primary condensate pump 

motor upper bearing in accordance with the predictive maintenance program. The total 

acid number (TAN) was just above the Alert limit. The viscosity value was normal. The 

condition was entered into the corrective action program. A recommendation was made 

to change the lubricating oil in the following refueling outage. The lubricating oil was 

changed and the subsequent TAN value returned to the normal range. Therefore, this 

example provides objective evidence that the Lubricating Oil Analysis Program is 

capable of sampling lubricating oils, analyzing the samples for critical lubricating oil 

parameters, recognizing a condition adverse to quality, and implementing corrective 

actions to restore the critical parameters to the normal ranges. 

 (3) In 2002, a lubricating oil sample was taken from the “C” RHR pump motor upper bearing 

assembly in accordance with the predictive maintenance program. The results indicated 

high moisture content. A confirmatory analysis was performed, and the result was lower 

moisture content but one still above the limit. The condition was entered into the 

corrective action program. The extent of the condition was limited to the “C” RHR pump 

motor. HCGS entered a TS Limited Condition Operation (LCO) 02-629 due to a 

degraded ECCS pump. The cause of the elevated moisture content was determined to 

be a degraded lube oil cooler that allowed cooling water to contaminate the lubricating 

oil. The motor was removed, the lube oil cooler repaired, the bearing housings cleaned, 

and new lubricating oil added. The moisture content returned to the normal range. The 

RHR pump motor was restored, and the LCO exited. Therefore, this example provides 

objective evidence that the Lubricating Oil Analysis Program is capable of sampling 

lubricating oils, analyzing the samples for critical lubricating oil parameters, recognizing 

a condition adverse to quality, and implementing corrective actions to restore the critical 

parameters to the normal ranges. 

During the audit, the staff reviewed operating experience information in the application 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. 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 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. 
Aging Management Review Results 

 3-117 

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. LRA Section A.2.1.27 provides the UFSAR supplement for the Lubricating 

Oil Analysis Program. The staff reviewed this UFSAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.3-2. The staff also notes that the applicant committed 

(Commitment No. 27) to ongoing implementation of the existing Lubricating Oil Analysis 

Program for managing aging of applicable components during the period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

Conclusion. On the basis of its audit and review of the applicant’s Lubricating Oil Analysis 

Program, the staff finds that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the applicant’s 

one exception and its justifications and finds 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 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.14 ASME Section XI, Subsection IWE 

Summary of Technical Information in the Application. LRA Section B.2.1.28 describes the 

existing ASME Section XI, Subsection IWE Program as consistent, with enhancements, with 

GALL AMP XI.S1, “ASME Section XI, Subsection IWE.” In the LRA, the applicant stated that its 

ASME Section XI, Subsection IWE Program is a condition monitoring program that provides for 

inspection of primary containment components including steel containment shells and their 

integral attachments, containment hatches and airlocks, penetration sleeves, pressure retaining 

bolting, and other pressure retaining components for loss of material and fretting or lockup in an 

indoor air or treated water environment. The applicant also stated that the scope of this AMP is 

consistent with the scope identified in Subsection IWE-1000 and includes Class MC pressure 

retaining components and their integral attachments including wetted surfaces of submerged 

areas of the pressure suppression chamber and vent system, containment pressure retaining 

bolting, and metal containment surface areas, including welds and base metal. The applicant 

included 10 enhancements to its ASME Section XI, Subsection IWE Program for further 

assurance that Class MC components are not exposed to potentially corrosive environments. 

Six of these enhancements were included in the LRA, and the remaining four enhancements 

were added in a letter dated June 14, 2010 (ADAMS Accession No. ML101680503), in 

response to RAI B.2.1.28. In response to staff concerns, the applicant revised Enhancement 9 

by letter dated January 19, 2011 (ADAMS Accession No. ML110210677). In response to further 

staff concerns regarding the current configuration of the drywell air gap drains, the applicant 

revised the program by letter dated May 19, 2011 (ADAMS Accession No. ML11144A016). The 

applicant further stated that this AMP complies with ASME Code Section XI, Subsection IWE, 
Aging Management Review Results 

 3-118 

2001 Edition including 2003 Addenda, for steel containment (Class MC) pressure retaining 

components and their integral attachments, in accordance with the provisions of 

10 CFR 50.55a. 

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 whether they are 

bounded by the conditions for which the GALL Report was evaluated. In addition, the applicant 

included 10 enhancements to its ASME Section XI, Subsection IWE Program. Six of these 

enhancements were included in the LRA, and the remaining four enhancements were added in 

a letter dated June 14, 2010, in response to RAI B.2.1.28. 

Also, in response to staff concerns, the applicant revised Enhancement 9 by letter dated 

January 19, 2011. The applicant included in its response that through boroscope inspection of 

each of the four drywell air gap drains, it discovered that covers were in place in each drain line 

that “may limit or prevent proper drainage of the drywell air gap.” As a result of this finding, the 

applicant indicated that it planned to futher investigate one of the drain lines to better 

understand the configuration in order to properly clear the four drain line openings. The 

applicant stated that its plan would allow it to “restore the functionality of the four air gap drains 

prior to flood-up of the reactor cavity during the refueling outage in Spring 2012.” 

Subsequently, during a May 9, 2011, telephone conference call, the applicant informed the staff 

that its further investigation of one of the drywell air gap drain lines indicated that the location of 

the blockage (where covers were installed) did not coincide with the drain line’s entrance into 

the air gap. The applicant was unable to identify, through boroscope inspection from the air gap 

side, an opening that coincided with the drain line. Due to the level of radiation exposure 

involved in performing such inspections, the applicant was not able to perform the same 

investigation for the remaining three drain lines for the air gap. 

The staff notes that the actual configuration from the drain line blockage to the air gap is 

unknown. Based on the new information provided by the applicant by telephone conference call 

dated May 9, 2011, the staff revised its finding and conclusion of the ASME Section XI, 

Subsection IWE Program. The acceptance of the program, with Enhancements 4, 6, and 8, 

along with items 4, 6, and 8 of Commitment No. 28, was based on having a drain path for the air 

gap (as stated in the LRA supplement and RAI response dated June 14, 2010). Since the drain 

path for the air gap does not currently exist, the staff could no longer accept the program as 

stated. 

In response to the staff’s concerns regarding the configuration of the drywell air gap drains, the 

applicant revised the ASME Section XI, Subsection IWE Program by letter dated May 19, 2011, 

which included revisions to Enhancements 4, 6, 7, 8, and 9. 

In order to ensure that the drywell drains are cleared and the drywell can perform its intended 

function, the staff will issue a license condition to the applicant. The license condition will 

require the applicant to establish drainage capability from the bottom of the drywell air gap on or 

before June 30, 2015. The license condition also states that until drainage is established from 

all four drains, during each refueling outage, the applicant will perform boroscope inspections 

and ultrasonic thickness (UT) measurements to identify potential corrosion of the steel 

containment shell exterior surface. After drainage is established from all four drains, the 

applicant will be required to perform UT measurements during each of the three subsequent 

refueling outages at the same locations. The license condition also requires the applicant to 
Aging Management Review Results 

 3-119 

submit a report to the NRC staff summarizing the results of the boroscope inspections and UT 

measurements and if applicable, corrective actions. 

The staff compared elements one through six of the applicant’s program to the corresponding 

elements of GALL AMP XI.S1. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.S1. 

The staff also reviewed the portions of the “scope of the program,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements associated with the 

revised enhancements associated with the RAI responses to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

these enhancements follows. 

Enhancement 1. LRA Section B.2.1.28 states an enhancement to the “scope of the program” 

program element. The enhancement involves the installation of an internal moisture barrier at 

the junction of the concrete floor and the steel containment shell prior to the period of extended 

operation. The original design for HCGS did not have an internal moisture barrier at the junction 

of the concrete floor and drywell (steel containment shell). 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1. The staff finds the enhancement acceptable because the installation of a moisture 

barrier will prevent ingress of water below the concrete floor and preclude the potential for future 

corrosion of the metal containment shell at the concrete floor junction. 

Enhancement 2. LRA Section B.2.1.28 states an enhancement to the “scope of the program” 

program element. The enhancement involves revision of the applicant’s ASME Section XI, 

Subsection IWE Program implementing documents to require inspection of the moisture barrier 

after it is installed for loss of sealing in accordance with Subsection IWE-2500. 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1. The staff finds the enhancement acceptable because GALL AMP XI.S1 

recommends inspection of moisture barrier in accordance with ASME Code Section XI, 

Subsection IWE-2500. 

Enhancement 3. LRA Section B.2.1.28 states an enhancement to the “scope of the program” 

program element. The enhancement involves verification that the reactor cavity seal rupture 

drain lines are clear from blockage and that the monitoring instrumentation is functioning 

properly. The enhancement also states that the inspection of reactor cavity drain lines will be 

conducted once prior to the period of extended operation and one additional time during the first 

10 years of the period of extended operation. 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1. In addition, in a letter dated May 19, 2011, the applicant stated that the reactor 

cavity seal rupture drain lines have been verified to be clear and the associated leakage 

monitoring instrumentation has been tested and verified functional. 

The staff noted that Enhancements 5 through 8, described below, require that when any 

leakage occurs during the period the reactor cavity is flooded, the reactor cavity will be 

monitored and investigated. These actions will identify if the reactor cavity seal rupture drain 

lines are clear from blockage and the monitoring instrumentation is functioning properly. 

Therefore, the staff finds the Enhancement 3 acceptable because the inspection of reactor 
Aging Management Review Results 

 3-120 

cavity seal rupture drain lines, once prior to the period of extended operation and one additional 

time during the first 10 years of the period of extended operation, will preclude the potential for 

water to backup and cause drywell shell corrosion. 

Enhancement 4. LRA Section B.2.1.28 states an enhancement to the “scope of the program” 

program element. The enhancement involves verification that the drains at the bottom of the 

drywell air gap are clear from blockage. The enhancement also states that inspections to verify 

that the drains at the bottom of the drywell air gap will be conducted once prior to the period of 

extended operation, and one additional time during the first 10 years of the period of extended 

operation. 

Due to the unknown configuration of the drywell air gap, the applicant revised Enhancement 4 

by letter dated May 19, 2011, to include: 

Establish drainage capability from the bottom of the drywell air gap on or before 

June 30, 2015. The drywell air gap will be divided into four approximately equal 

quadrants. Drainage consists of one drain in each quadrant for a total of four 

drains. Each drain will be open at the bottom of the drywell air gap and be 

capable of draining water from the air gap. 

Verify that drains at the bottom of the drywell air gap are clear from blockage 

once prior to the period of extended operation, and one additional time during the 

first ten years of the period of extended operation. 

The staff finds the enhancement acceptable because drainage capability from the bottom of the 

drywell air gap will be established and verified on or before June 30, 2015, and inspection of the 

drains at the bottom of the drywell air gap for blockage, once prior to the period of extended 

operation and one additional time during the first 10 years of the period of extended operation, 

will preclude the potential for water to backup and cause steel containment shell corrosion. In 

addition, Enhancement 9, as decribed below, the applicant committed to perform UT 

measurement of the drywell, establish corrosion rate, and demonstrate that the effects of aging 

will be managed such that the drywell performs its intended function during the period of 

extended operation. 

Enhancement 5. LRA Section B.2.1.28 states an enhancement to the “scope of the program” 

program element. The enhancement involves investigation of the source of any leakage 

detected by the reactor cavity seal rupture drain line instrumentation and assessment of its 

impact on the drywell shell. 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1. The staff finds the enhancement acceptable because investigating the source of 

leakage detected by the reactor cavity seal rupture drain line instrumentation and accessing its 

impact on the drywell shell will provide the basis for initiating corrective actions to reduce or 

eliminate the potential for metal containment shell corrosion. 

Enhancement 6. LRA Section B.2.1.28 states an enhancement to the “scope of the program” 

program element. The enhancement involves monitoring the drains at the bottom of the drywell 

air gap for leakage in the event leakage is detected by the reactor cavity seal rupture drain line 

instrumentation. 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1 and found that the enhancement did not specify the frequency for monitoring the 
Aging Management Review Results 

 3-121 

drains at the bottom of the drywell air gap for leakage. By letter dated Auguest 9, 2010, the 

applicant supplemented its LRA to revise the enhancement to state that leakage from the drains 

at the bottom of the drywell air gap will be monitored daily. 

Due to the unknown configuration of the drywell air gap, the applicant revised Enhancement 6 

by letter dated May 19, 2011, to include: 

After drainage has been established from the bottom of the air gap from all four 

drains, monitor the drains at the bottom of the drywell air gap daily for leakage in 

the event leakage is detected by the reactor cavity seal rupture drain line 

instrumentation. 

The staff found the revised enhancement acceptable because drainage capability from the 

bottom of the drywell air gap will be established and verified on or before June 30, 2015, and 

monitoring the drains at the bottom of the drywell air gap daily for leakage, in the event leakage 

is detected by the reactor cavity seal rupture drain line instrumentation, will provide an indication 

of possible steel containment shell corrosion and the basis for initiating corrective actions that 

would reduce the potential for steel containment shell corrosion. 

Enhancement 7. By letter dated June 14, 2010, in response to RAI B.2.1.28-1, regarding 

leakage from the drywell penetration sleeve J13, the applicant added Enhancement 7 to the 

“scope of the program” program element. The enhancement involves periodically monitoring 

penetration sleeve J13 for water leakage when the reactor cavity is flooded up until corrective 

actions are taken to prevent leakage through J13. 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1 and found that the enhancement did not provide a timeline for periodic monitoring of 

leakage from penetration sleeve J13 and addressed this concern with the applicant in a 

conference call dated June 21, 2010. Therefore, by letter dated August 9, 2010, the applicant 

supplemented its LRA to revise the enhancement to state that leakage from the penetration J13 

will be monitored daily when the reactor cavity is flooded. 

The applicant included an addition to Enhancement 7 by letter dated May 19, 2011, as follows: 

Monitor penetration sleeve J13 daily for water leakage when the reactor cavity is 

flooded up. In addition, perform a walkdown of the torus room to detect any 

leakage from other drywell penetrations. These actions shall continue until 

corrective actions are taken to prevent leakage through J13 or through the four 

air gap drains. 

The staff finds the revised enhancement for daily inspection of penetration J13 and walkdowns 

of the torus room to detect any leakage from other drywell penetrations acceptable because if 

the accumulation of water below J13 or in the torus room is discovered, the root cause analysis 

will reveal whether there are cracks in the welds of reactor cavity seal plates, refueling bellows, 

or in the reactor cavity drain lines. This will lead to further examination and investigation to find 

the source of the leakage, repair of the leak, or additional testing as per Enhancements 9 and 

10 noted below to ensure that the drywell can perform its intended function. 

Enhancement 8. By letter dated June 14, 2010, in response to RAI B.2.1.28-1, regarding 

leakage from the drywell penetration sleeve J13, the applicant added Enhancement 8 to the 

“scope of the program” program element. The enhancement involves periodic monitoring of the 

lower drywell air gap drains for water leakage when the reactor cavity is flooded up. 
Aging Management Review Results 

 3-122 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1 and found that the enhancement did not provide a timeline for periodic monitoring of 

water leakage from the lower drywell air gap drains and addressed this concern with the 

applicant in a conference call dated June 21, 2010. Therefore, by letter dated August 9, 2010, 

the applicant supplemented its LRA to revise the enhancement to state that leakage from the 

lower drywell air gap drains will be monitored daily when the reactor cavity is flooded. 

Due to the unknown configuration of the drywell air gap, the applicant revised Enhancement 8 

by letter dated May 19, 2011, to include: 

Until drainage is established from all four drains, when the reactor cavity is 

flooded up, perform boroscope examination of the bottom of the drywell air gap 

through penetrations located at elevation 93’ in four quadrants, 90 degrees apart. 

The personnel performing the boroscope examination shall be certified as VT-1 

inspectors in accordance ASME Section XI, Subsection IWA-2300, requirements. 

The examiners will look for signs of water accumulation and drywell shell 

corrosion. Adverse conditions will be documented and addressed in the 

corrective action program. 

After drainage has been established from the bottom of the air gap from all four 

drains, monitor the lower drywell air gap drains daily for water leakage when the 

reactor cavity is flooded up. 

The staff finds this revised enhancement acceptable because until drainage is established from 

all four drains, boroscope examinations will be perfomed during each refueling outage, and the 

boroscope examination will verify that water accumulation and drywell shell corrosion has not 

occurred. After drainage has been established from the bottom of the air gap from all four 

drains, this enhancement will provide an indication of possible water ingress into the drywell air 

gap. This will lead to further examination and investigation to find the source of the leakage, 

repair of the leak, or additional testing as per Enhancements 9 and 10 noted below to ensure 

that the drywell can perform its intended function. 

Enhancement 9. By letter dated June 14, 2010, in response to RAI B.2.1.28-1, regarding 

leakage from the drywell penetration sleeve J13, the applicant added Enhancement 9 to the 

“detection of aging effects” program element. The enhancement involves performing one-time 

UT thickness measurements from inside the drywell in the accessible area of the drywell shell 

directly below penetration sleeve J13. The applicant stated that inspection and acceptance 

criteria will be in accordance with IWE-2000 and IWE-3000, respectively, and that in the event 

significant corrosion is detected, the condition will be entered in the corrective action program 

for evaluation and extent of condition determination. 

During the refueling outage in October 2010, the applicant observed leakage from penetration 

sleeve J13 and the adjacent penetration sleeve J14. As stated by the applicant, the J14 

penetration sleeve is horizontally adjacent to the J13 penetration sleeve with centerlines offset 

by approximately 21 inches. UT thickness measurements of the drywell shell in the area below 

penetrations J13 and J14 indicated an area of interest with slightly lower shell thickness 

readings. The applicant also determined that all four drains at the bottom of the drywell, 

including one directly below penetrations J13 and J14, were blocked. 

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.S1 and found that the one-time UT thickness measurement from inside the drywell in 

the accessible area of the drywell shell directly below penetration sleeve J13 and the adjacent 
Aging Management Review Results 

 3-123 

J14 penetration sleeve may not provide enough data points to establish a corrosion rate in the 

drywell. By letter dated January 3, 2011, the staff issued RAI B.2.1.28-3 requesting that the 

applicant provide information on establishing a corrosion rate and projected loss of drywell 

thickness before the period of extended operation based on a one-time UT thickness 

measurement. 

In its response dated January 19, 2011, the applicant revised Enhancement 9 to increase the 

number and frequency of UT thickness measurements. Due to the unknown configuration of 

the drywell air gap, the applicant further revised Enhancement 9 by letter dated May 19, 2011, 

to include: 

Until drainage is established from all four drains, perform UT thickness 

measurements each refuel outage from inside the drywell in the area of the 

drywell shell below the J13 penetration sleeve area to determine if there is a 

significant corrosion rate occurring in this area due to periodic exposure to 

reactor cavity leakage. In addition, UT measurements shall be perfomed each 

refuel[ing] outage around the full 360 degree circumference of the drywell 

between elevations 86’-11” and 88’-0” (underside of the torus [downcomer] vent 

piping penetrations). Inspection and acceptance criteria will be in accordance 

with IWE-2000 and IWE-3000[,] respectively. The results of the UT 

measurements shall be used to establish a corrosion rate and demonstrate that 

the effects of aging will be adequately managed such that the drywell can 

perform its intended function until April 11, 2046. Evidence of drywell shell 

degradation will be documented and addressed in the corrective action program. 

After drainage has been established from the bottom of the air gap from all four 

drains, UT thickness measurements will be taken each of the next three refueling 

outages at the same locations as those previously examined as described above. 

These UT thickness measurements will be compared to the results of the 

previous UT inspections and, if corrosion is ongoing, a corrosion rate will be 

determined for the drywell shell. In the event a significant corrosion rate is 

detected, the condition will be entered in the corrective action process for 

evaluation and extent of condition determination. 

The staff finds the revised enhancement acceptable because UT thickness measurements of 

the drywell in the area of the drywell shell, directly below the J13 penetration sleeve, and around 

the full 360 degree circumference of the drywell between elevations 86’-11” and 88’-0” 

(underside of the torus downcomer vent piping penetrations), during each refueling outage, until 

drainage is established from all four drains, will detect any indication of steel containment shell 

corrosion. The boroscope examinations, as described in Enhancement 8, can also detect if 

standing water is trapped below penetration sleeves J13 and J14 in the drywell air gap over the 

long term. Similarly, increasing the number and frequency of UT thickness measurements can 

establish a method to determine a corrosion rate, if corrosion is ongoing. Additionally, the 

applicant has committed to use the inspection and acceptance criteria recommended in 

IWE-2000 and IWE-3000. Furthermore, the applicant has committed to perform UT thickness 

mearurements after drainage has been established from the bottom of the air gap from all four 

drains during the subsequent three refueling outages to provide further staff assurance that the 

drywell shell steel exterior surface is not degradated. Finally, in the event a significant corrosion 

rate is detected, the corrective action process will be used for evaluation and extent of condition 

determination. Enhancement 10 describes actions planned by the applicant to monitor, trend, 
Aging Management Review Results 

 3-124 

and evaluate long term degradation of the drywell shell due to water leakage around 

penetrations J13 and J14. 

Enhancement 10. By letter dated June 14, 2010, in response to RAI B.2.1.28-1, regarding 

leakage from the drywell penetration sleeve J13, the applicant added Enhancement 10 which 

states an enhancement to the “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements. The enhancement involves incorporating the following 

three aging management activities, as recommended in the final Interim Staff Guidance (ISG) 

LR-ISG-2006-01, if repairs to address the reactor cavity water leakage cannot be made prior to 

the period of extended operation. 

The first activity involves identifying drywell surfaces requiring examination and implementing 

augmented inspections for the period of extended operation in accordance with IWE-1240, as 

identified in Table IWE-2500-1, Examination Category E-C. 

The second activity involves demonstrating through the use of augmented inspections that 

corrosion is not occurring or that corrosion is progressing so slowly that the age-related 

degradation will not jeopardize the intended function of the drywell shell through the period of 

extended operation. 

The third activity involves developing a corrosion rate that can be inferred from past UT 

examinations and evaluating the drywell shell using the developed corrosion rate to 

demonstrate that the drywell shell will have sufficient wall thickness to perform its intended 

function through the period of extended operation, if degradation has occurred. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

AMP XI.S1, “ASME Section XI, Subsection IWE.” The staff found the enhancement acceptable 

because drywell shell examinations and augmented inspections for the period of extended 

operation will be conducted in accordance with IWE requirements as recommend in GALL 

AMP XI.S1. This will include UT examination of the drywell area directly below penetration J13 

after the UT inspection during October 2010 and the next three refueling outages followed by 

regular IWE examination during each inspection period (3 times in 10 years) until the reactor 

cavity water leakage from penetrations J13 and J14 is repaired. In addition, augmented 

inspection results will be used to verify that corrosion is not occurring or progressing at a rate 

that will not jeopardize the intended function of the drywell shell through the period of extended 

operation. Development of a corrosion rate to estimate the magnitude of drywell corrosion at 

the end of the period of extended operation provides a method for assuring that the drywell shell 

will have sufficient wall thickness to perform its intended function through the period of extended 

operation. 

Based on its audit, resolution to the RAIs, clarifications provided during a conference call, and 

the applicant’s supplement to the LRA, the staff finds that elements one through six of the 

applicant’s ASME Section XI, Subsection IWE Program, with 10 enhancements, are consistent 

with the corresponding program elements of GALL AMP XI.S1 and, therefore, acceptable. 

Furthermore, to ensure that the drywell drains are cleared and drywell can perform its intended 

function, the staff will issue a license condition to the applicant. The license condition will 

confirm that the applicant has implemented the different enhancements, as described above, 

and require that the applicant submit a report to the NRC staff, after each refueling outage, 

summarizing the results of the UT measurements and boroscope inspections performed. The 

applicant shall continue to submit these reports to the NRC for three refueling outages after the 

air gap drains are cleared and if applicable, corrective action. 
Aging Management Review Results 

 3-125 

Operating Experience. LRA Section B.2.1.28 summarizes operating experience related to the 

applicant’s ASME Section XI, Subsection IWE Program. The applicant has described examples 

of operating experience for the HCGS metal containment in LRA Section B.2.1.28. These 

discussions include ISI findings performed in accordance with ASME Code Section XI, 

Subsection IWE requirements. 

The applicant stated in the LRA that the torus shell and interior coatings were inspected in 2004 

by divers performing underwater IWE program inspections resulting in identification of coating 

deficiencies with general corrosion and pitting. There were 16 areas with metal loss reported to 

range up to 30 mils (0.030 inches). The minimum torus shell thickness in these areas is 1 inch 

thick. The staff noted that the degradation and loss of material thickness of the torus at 16 local 

areas did not exceed 10 percent of the nominal plate thickness of the torus shell. In addition, 

the applicant cleaned and recoated the 16 local areas in the subsequent outage to prevent 

further degradation. The applicant also plans to re-inspect these 16 areas during the future IWE 

underwater inspections. 

In order to evaluate the potential impacts of these deficiencies and assess consistency of the 

applicant’s ASME Section XI, Subsection IWE Program with GALL AMP XI.S1, the staff issued 

RAI B.2.1.28-2, dated May 14, 2010, requesting that the applicant provide additional details of 

the underwater inspections performed during 2004 including: (1) the maximum depth of 

degradation due to corrosion, (2) corrosion allowance thickness incorporated in the original 

design of the torus, (3) general condition of the coating applied to the inside surface of the torus, 

and (4) normal design life of the Amercoat 90 coating that was applied to the inside surface of 

the torus. 

In its response to RAI B.2.1.28-2 (items 1 and 2), by letter dated June 14, 2010, the applicant 

stated that during the most recent underwater inspection of the torus and coating, 99.99 percent 

of the coating was found to be smooth and tightly adhered to the base metal with no significant 

effects. The identified coating deficiencies were primarily small localized areas of mechanical or 

impact damage. Other than minor general corrosion of the exposed surfaces, there was no 

damage to the base metal. The maximum metal loss identified at one location was 30 mils. All 

exposed substrate locations were subsequently repaired with epoxy coating. The applicant also 

stated that the original design of the torus incorporated a corrosion allowance of 125 mils (1/8 

inch). 

The staff reviewed the applicant’s response to RAI B.2.1.28-2 (items 1and 2) and finds it 

acceptable because the maximum metal loss in thickness at 16 small areas of the torus is 

30 mils, which is significantly less than 10 percent of the nominal thickness of the torus 

(100 mils) allowed by ASME Code Section XI, Subsection IWE, Article IWE-3122.3. In addition, 

the original design of the torus incorporated a corrosion allowance of 125 mils. 

In its response to RAI B.2.1.28-2 (items 3 and 4), by letter dated June 14, 2010, the applicant 

stated that the Amercoat 90 coating system applied to the inside surface of the torus was 

observed to be in excellent condition. However, there has been random localized mechanical 

damage to the coating. The typical damage area is not more than 3⁄4-inch diameter, accounting 

for an approximate total affected area of 151 square inches (0.0062 percent of the submerged 

portion of the torus shell). In addition, indications of minor general corrosion without pitting of 

the torus were identified during the most recent inspection in 2004. The Amercoat 90 coating 

system is a Service Level 1 coating and is being managed in accordance with GALL 

AMP XI.S8, “Protective Coating Monitoring and Maintenance Program.” The applicant also 

stated the Amercoat 90 coating system does not have a specified normal design life, and if 
Aging Management Review Results 

 3-126 

properly installed and maintained, will have a minimum service life of 20–25 years. The 

applicant further stated that with proper monitoring, maintenance, and repairs, the coating 

system could last through the period of extended operation. 

The staff reviewed the applicant’s response to RAI B.2.1.28-2 (items 3 and 4) and finds it 

acceptable because the applicant is managing the aging of the torus consistent with GALL 

AMP XI.S1. The staff notes that there have been indications of minor general corrosion without 

loss of base metal thickness of the torus, and random localized mechanical and impact damage 

of the coating in 16 small areas, which were repaired and recoated, is not likely to affect the 

torus structural integrity and leak tightness during the period of extended operation. 

The application stated in the LRA that in 2004, rust was identified during IWE program 

inspections on various components inside the torus shell, including a number of penetrations 

and downcomer supports. The applicant also stated that the condition of the base metal was 

acceptable; however, the applicant recoated the inside of numberous penetrations and 

32 downcomer supports to prevent further degradation. The staff finds this approach to recoat 

penetrations and downcomers acceptable because it will prevent further degradation of the 

containment pressure boundary. 

In 2007 and 2009, the applicant performed UT thickness measurements of the drywell shell at 

various locations including near the interface of the concrete and the drywell shell. This 

interface was accessible because the original design of HCGS did not include a moisture barrier 

at this location. The as-found UT thickness measurement results were in excess of nominal 

thickness requirements and were considered acceptable. The applicant concluded that 

inspections of the shell area immediately adjacent to the floor found no indications of significant 

corrosion damage. In addition, the applicant enhanced its ASME Section XI, Subsection IWE 

Program (Enhancements 1 and 2) to include installation of a moisture barrier before the period 

of extended operation and to perform inspections in accordance with IWE-2500 during the 

period of extended operation. The staff finds this proactive approach to aging management of 

material loss due to corrosion acceptable because it will prevent ingress of water below the 

concrete floor at the drywell shell interface. 

The “operating experience” program element for the applicant’s ASME Section XI, Subsection 

IWE Program describes water leakage during the 2009 refueling outage from the seal rupture 

drain line penetration sleeve J13 which is located in the drywell air gap region. Because water 

may be trapped between the concrete and the drywell steel below the penetration sleeve J13, 

which is located approximately 8 feet above the drywell lower air gap drains, corrosion of the 

drywell steel containment is possible. By letter dated May 14, 2010, the staff issued 

RAI B.2.28-1 requesting that the applicant provide: (1) plans for determining the root cause for 

the water leak, (2) an explanation for why the water did not travel below the penetration sleeve 

J13 and exit from the drywell lower air gap drains located approximately 8 feet below, (3) plans 

to perform NDE of the drywell area below the penetration sleeve J13 to demonstrate that water 

is not trapped in the 2-inch annular space between the drywell and concrete shield wall, and 

(4) plans to quantify the effects of water leakage on the drywell including volumetric examination 

and a detailed engineering analysis and evaluation of the drywell. 

In its response to RAI B.2.28-1 (item 1), by letter dated June 14, 2010, the applicant stated that 

a small amount of leakage was first observed during the 2009 refueling outage exiting from 

penetration J13. The applicant further stated that the leakage involved about a 1⁄4-inch wide 

trickle of water exiting the penetration sleeve and forming a small puddle. The leakage stopped 

when the reactor cavity was drained. The applicant performed various activities prior to restart 
Aging Management Review Results 

 3-127 

from the 2009 refueling outage and determined that the leakage is due to a small crack or 

cracks in either the welds of the reactor cavity seal plates, refueling bellows, or reactor cavity 

drain lines. Additional activities were planned and conducted during the October 2010 outage to 

determine the root cause. These activities included: (1) inspecting reactor cavity seal rupture 

drain lines for blockage monitoring leakage daily from penetration sleeve J13, drywell air gap 

drain lines, and reactor cavity seal rupture drain lines; (2) observing variations in water leakage 

and characterizing how it is affected by the water levels in the reactor cavity; and (3) performing 

boroscope inspections below penetration sleeve J13 for conditions that prevent water leakage 

from reaching the drywell lower air gap drains. In addition, the applicant performed UT 

examinations of the drywell shell directly below penetration J13 and evaluated the results. The 

results of these activities are discussed below. 

In its response to RAI B.2.28-1 (item 2), by letter dated June 14, 2010, the applicant stated that 

the water leakage did not travel below penetration sleeve J13 due the geometrical configuration 

of the drywell, air gap, and penetration sleeve. The staff reviewed the applicant’s detailed 

response to RAI B.2.28-1 (item 2) and finds the explanation provided by the applicant plausible 

because water leakage was not observed from penetration J37 which is located directly below 

penetration J13. The staff also finds that additional activities planned by the applicant during 

the October 2010 refueling outage to confirm the root cause and leakage flow path, including 

the boroscope examination of the area below the penetration J13, will provide additional 

information about the leakage path. 

In its response to RAI B.2.28-1(item 3), the applicant stated that one-time UT thickness 

measurements of the drywell shell in the area below penetration sleeve J13 will be performed to 

demonstrate that significant loss of material due to corrosion has not occurred on the drywell 

shell. These measurements will provide evidence that water is not trapped in the 2-inch air gap 

between the drywell and concrete shield wall. The inspection and acceptance criteria will be in 

accordance with IWE-2000 and IWE-3000, respectively. In the event significant corrosion is 

detected, the condition will be entered into the applicant’s corrective action program. In 

addition, the area will be designated for augmented examination in accordance with IWE-1240 

requirements. 

The staff reviewed the applicant’s response to RAI B.2.28-1 (item 3) and was concerned that 

the applicant did not specifically address the need for periodic examination of the drywell shell 

area below penetration sleeve J13 in case the reactor cavity water leakage is not stopped 

during the October 2010 refueling outage. 

By letter dated January 3, 2011, the staff issued RAI B.2.1.28-3 requesting that the applicant 

provide information on establishing a corrosion rate and projected loss of drywell thickness to 

demonstrate that significant loss of material due to corrosion has not occurred on the drywell 

shell before the period of extended operation based on a one-time UT thickness measurement. 

In its response dated January 19, 2011, the applicant revised Enhancement 9 to increase the 

number and frequency of UT thickness measurements. UT thickness measurement will be 

taken for the next three refueling outages at the same locations as those examined in 2010. 

These UT thickness measurements will be compared to the results of the initial UT inspections 

performed during the October 2010 refueling outage and, if corrosion is ongoing, a corrosion 

rate will be determined for the drywell shell. 

In its response to RAI B.2.28-1 (item 4), by letter dated June 14, 2010, and amended by letter 

dated January 19, 2011, the applicant stated that the reactor cavity leakage will be repaired, if 
Aging Management Review Results 

 3-128 

practical, before the period of extended operation. If repairs cannot be made prior to the period 

of extended operation, the applicant will perform augmented inspections of the affected area of 

the drywell surface and demonstrate through the use of augmented inspections that corrosion is 

not occurring or corrosion is progressing so slowly that age-related degradation will not 

jeopardize the intended function of the drywell through the period of extended operation, as 

described above. In addition, the applicant will develop a corrosion rate based on UT thickness 

measurements. The applicant will use this rate to project loss of drywell thickness through the 

period of extended operation and evaluate the results to determine if the drywell can perform its 

intended function during the period of extended operation with reduced thickness. 

In the October 2010 refueling outage, the applicant observed leakage from penetration sleeve 

J13 and an adjacent penetration sleeve J14. In addition, UT thickness measurements of the 

drywell shell in the area below penetrations J13 and J14 indicated an area of interest with 

slightly lower shell thickness readings. Furthermore, the applicant determined that all four 

drains at the bottom of the drywell, including one directly below penetrations J13 and J14 were 

blocked. Therefore, the staff issued RAI B.2.28-3 requesting that the applicant provide: 

1. Plans and schedule for removing the blockage of the four drains at the 

bottom of the drywell or if the blockage cannot be removed, details of 

alternative measures such as coredrills from inside drywell or torus room 

to remove water that may be trapped in the annular space between the 

drywell shell and concrete shield wall. 

2. Revision to Enhancements 9 and 10 to increase the number and 

frequency of UT examinations to establish a corrosion rate and projected 

loss of drywell thickness before the period of extended operation. 

3. Plans and a schedule for examination and investigation to find the source 

of the leakage, and repair of the leak. 

In its response to RAI B.2.28-3 (item 1) dated January 19, 2011, the applicant stated that the 

current plan is to initially investigate one of the drain line openings, in either the 180° or 270° 

azimuth drain line, in the first half of 2011 to better understand the configuration such that the 

four drain line openings can be properly cleared. The conditions at the bottom of the drywell air 

gap will also be evaluated. Containment penetrations J13 and J14 are within the 210° to 240° 

azimuths. To provide access for inspection, the drain line piping will be disassembled from the 

torus room side. The information obtained from the investigation and clearing of the first drain 

line opening will be used to plan and implement the restoration of the remaining three drain line 

openings. This plan will restore the functionality of the four air gap drains prior to flood-up of the 

reactor cavity during the next refueling outage in the spring of 2012. The applicant further 

stated that it is confident that the drains can be cleared, and there are no current plans to 

perform alternate measures such as coredrills. In addition, the applicant has entered the 

blockage of the drains in the corrective action process to evaluate and implement corrective 

actions to restore the functionality of the drain lines. 

Subsequently, during a May 9, 2011, telephone conference call, the applicant informed the staff 

that its further investigation of one of the drywell air gap drain lines indicated that the location of 

the blockage (where covers were installed) did not coincide with the drain line’s entrance into 

the air gap. The staff was concerned about this new finding and requested the applicant to 

describe in detail the existing configuarion of the air gap blocked drains, its impact on the 

applicant’s plans to clear these drains by the spring of 2012, and any revisions to the 
Aging Management Review Results 

 3-129 

enhancements and commitment 28 for the ASME Section XI, Subsection IWE Program. In 

response to this request, by letter dated May 19, 2011, the applicant stated: 

The drywell air gap drain line as-built configuration is not in accordance with the 

existing design configuration, and the non-conforming condition has been 

entered into the corrective action process. Field investigation of the as-built 

configuration performed to date has confirmed that all four of the air gap drain 

lines are blocked and incapable of providing a drain path for water that could 

potentially accumulate inside the air gap space. The air gap drain line located at 

azimuth 0° was investigated further by erecting a temporary platform and cutting 

the drain line pipe at a location near where the pipe becomes embedded in the 

concrete wall, allowing better access to the suspected location of the blockage. 

A pole was inserted into the cut drain line pipe, and it was determined that the 

pipe was obstructed at a point that is approximately the midpoint between the 

outer surface of the concrete wall in the torus room, and the inner surface of the 

concrete wall located inside the air gap space. 

The as-built configuration of this drain was further investigated by lowering a 

boroscope into the air gap through a penetration located above the area where 

the entrance to the air gap drain is shown on the design drawing. The boroscope 

inspection did not indicate the existence of an air gap drain opening or evidence 

of a drain cover. The boroscope inspection was repeated by lowering the 

boroscope through a different penetration in the same area and again the 

inspection could not locate the air gap drain opening or evidence of a drain 

cover. There was no indication of water accumulation at the bottom of the air 

gap. However, an accumulation of loose debris material at the bottom of the air 

gap was observed. The observation of foreign material, along with the inability to 

locate the expected drain line openings, was entered into the corrective action 

process. Although some uncertainty remains regarding the as-built configuration 

of the air gap drain lines, there are no indications of water accumulation inside 

the drywell air gap space and no indications of corrosion of the containment steel 

shell exterior surface. 

This new finding about the drain line blockage location has impacted the initial 

plans to establish clearing the four drain lines by Spring of 2012. Due to the 

uncertainty described above and the engineering evaluations necessary to safely 

clear existing drains or design and install alternate drains, PSEG Nuclear will 

now establish drainage capability from the bottom of the drywell air gap no later 

than June 30, 2015. 

Based on the new information provided by the applicant, the staff could no longer accept the 

program as stated. The acceptance of the program with Enhancements 4, 6, and 8, along with 

items 4, 6, and 8 of Commitment No. 28 was based on having a drain path for the air gap (as 

stated in the LRA supplement and RAI response dated June 14, 2010). As described by the 

applicant, in its May 19, 2011, letter, the drain path for the air gap does not exist. 

In response to the staff’s concerns regarding the current configuration of the drywell air gap 

drains, the applicant revised the program by letter dated May 19, 2011, which included revisions 

to Enhancements 4, 6, 7, 8, and 9. 

The staff reviewed the applicant’s revision to the program and finds it acceptable because the 

applicant has plans to remove the blockage in the four air gap drains on or before 
Aging Management Review Results 

 3-130 

June 30, 2015. Until the blockage is removed, the applicant’s corrective action process will 

evaluate and implement corrective actions to restore functionality of the drains. In addition, the 

plate under the J13 and J14 penetration area has been established as an area of interest for UT 

measurements each refueling outages, including UT measurements performed each refueling 

outage around the full 360 degree cifcumference of the drywell between elevation 86’-11” and 

88’-0”, until drainage from the four air gap drains is estabilished, to ensure that drywell shell 

integrity is maintained through the period of extended operation. These UT measurements will 

provide sufficient data to establish a corrosion rate. In case corrosion is found to be ongoing, 

the applicant will ensure that the drywell shell thickness is adequate to perform its intended 

function through the period of extended operation, and perform root cause analysis to determine 

the source of corrosion and water leakage. In the event a significant corrosion rate is detected, 

the condition will be entered in the corrective action process for evaluation and extent of 

condition determination. In addition, the applicant will perform boroscope examination of the 

bottom of the drywell air gap through penetrations located at elevation 93’ in four quadrants, 90 

degrees apart, from all four drains, until drainage is established. These boroscope 

examinations will verify that water accumulation and drywell shell corrosion has not occurred. In 

case significant corrosion is detected, the applicant will manage the drywell in accordance with 

the recommendations of Final ISG LR-ISG-2006-01. 

The staff notes augmented UT thickness measurements were taken during the October 2010 

refueling outage to determine if leakage from the reactor cavity has resulted in external 

corrosion of the drywell shell. Drywell thickness measurements were all above nominal plate 

thickness except the 1.5-inch thick plate under the J13 and J14 penetrations. This plate had UT 

readings below nominal plate thickness, but the average readings were well above the plate 

minimum allowable manufacturing tolerance. The individual and average thickness 

measurements on the plate under the J13 and J14 penetrations during the October 2010 outage 

were all above the plate thickness used in the design analysis (1.4375 inches). 

The applicant also stated that it will monitor penetration sleeve J13 daily for water leakage when 

the reactor cavity is flooded-up. In addition, the applicant will perform a walkdown of the torus 

room to detect any leakage from other drywell penetrations. These actions shall continue until 

corrective actions are taken to prevent leakage through J13 or through the four air gap drains. 

The staff finds it acceptable because if accumulation of water below J13 or in the torus room is 

discovered, the root cause analysis will reveal whether there are cracks in the welds of reactor 

cavity seal plates, refueling bellows, or in the reactor cavity drain lines. 

Additionally, the applicant stated that it has initiated numerous activities to investigate the 

source of the leakage. These activities include: (1) performing inspections to confirm prior to 

the spring 2012 refueling outage that reactor cavity seal drain lines are clear and monitoring 

instrumentation for the drains is functioning properly, (2) monitoring the J13 and J14 

penetrations area when the reactor cavity is flooded, (3) obtaining water leakage data to see 

how it varies with water level in the reactor cavity, (4) exploring the possibility of performing 

NDE of the reactor cavity bellows area during the spring 2012 refueling outage and restoring 

functionality of the drywell air gap drains on or before June 30, 2015, and (5) performing an 

engineering evaluation to address post spring 2012 outage conditions. The applicant further 

stated that if the reactor cavity leakage cannot be repaired prior to entering the period of 

extended operation, then the monitoring activities and evaluations of the Final ISG 

LR-ISG-2006-01 will be implemented in accordance with Enhancement 10. 

The staff reviewed the applicant’s plans and finds it acceptable because the applicant’s plans 

and schedule for examination and investigation to find the source of the leakage and repair of 
Aging Management Review Results 

 3-131 

the leak are acceptable. In addition, the applicant performed approximately 350 UT thickness 

measurements during the October 2010 outage which determined that the minimum measured 

thickness of the drywell was 1.49 inches. This measurement is greater than the 1.4375 inches 

used for the design of the drywell. Also, the applicant plans to establish a corrosion rate based 

on UT measurements and perform boroscope examinations during each refueling outage, until 

drainage is established from the four air gap drains and subsequent UT measurements in the 

next three refueling outages, after drainage is established from the four air gap drains. Finally, 

the applicant plans to perform a new engineering evaluation in the spring of 2012 to address the 

post-outage conditions. 

Additionally, due to the unknown configuration of the the drywell air gap drains, the staff will 

issue a license condition to the applicant. The license condition will require the applicant to 

establish drainage capability from the bottom of the drywell air gap on or before June 30, 2015. 

The license condition also states that until drainage is established from all four drains to identify 

potential corrosion of the steel containment shell exterior surface, the applicant will perform 

boroscope inspections and ultrasonic thickness (UT) measurements. After drainage is 

established from all four drains, the applicant will perform UT measurements each of the 

subsequent three refueling outages at the same locations. The license condition also requires 

the applicant to submit a report to NRC staff summarizing the results of the boroscope 

inspections and UT measurements and if applicable, corrective action. 

Based on its audit, review of the LRA and LRA supplements, resolution to the RAIs, and 

establishment of a license condition, 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. LRA Section A.2.1.28, as supplemented by letter dated May 19, 2011, 

provides the UFSAR supplement for the ASME Section XI, Subsection IWE 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 3.5-2. 

The staff also notes that the applicant committed (Commitment No. 28) to enhance the ASME 

Section XI, Subsection IWE Program prior to entering and during the period of extended 

operation. Specifically, Commitment No. 28 states: 

1. Install an internal moisture barrier at the junction of the drywell concrete 

floor and the steel drywell shell prior to the period of extended operation. 

2. Require inspection of the moisture barrier for loss of sealing in 

accordance with IWE 2500 after it is installed. 

3. Verify that the reactor cavity seal rupture drain lines are clear from 

blockage and that the monitoring instrumentation is functioning properly 

once prior to the period of extended operation, and one additional time 

during the first ten years of the period of extended operation. 

4. Establish drainage capability from the bottom of the drywell air gap on or 

before June 30, 2015. The drywell air gap will be divided into four 
Aging Management Review Results 

 3-132 

approximately equal quadrants. Drainage consists of one drain in each 

quadrant for a total of four drains. Each drain will be open at the bottom 

of the drywell air gap and be capable of draining water from the air gap. 

Verify that drains at the bottom of the drywell air gap are clear from 

blockage once prior to the period of extended operation, and one 

additional time during the first ten years of the period of extended 

operation. 

5. Investigate the source of any leakage detected by the reactor cavity seal 

rupture drain line instrumentation and assess its impact on the drywell 

shell. 

6. After drainage has been established from the bottom of the air gap from 

all four drains, monitor the drains at the bottom of the drywell air gap daily 

for leakage in the event leakage is detected by the reactor cavity seal 

rupture drain line instrumentation. 

7. Monitor penetration sleeve J13 daily for water leakage when the reactor 

cavity is flooded up. In addition, perform a walkdown of the torus room to 

detect any leakage from other drywell penetrations. These actions shall 

continue until corrective actions are taken to prevent leakage through J13 

or through the four air gap drains. 

8. Until drainage is established from all four drains, when the reactor cavity 

is flooded up, perform boroscope examination of the bottom of the drywell 

air gap through penetrations located at elevation 93’ in four quadrants, 90 

degrees apart. The personnel performing the boroscope examination 

shall be certified as VT-1 inspectors in accordance ASME Section XI, 

Subsection IWA-2300, requirements. The examiners will look for signs of 

water accumulation and drywell shell corrosion. Adverse conditions will 

be documented and addressed in the corrective action program. 

After drainage has been established from the bottom of the air gap from 

all four drains, monitor the lower drywell air gap drains daily for water 

leakage when the reactor cavity is flooded up. 

9. Until drainage is established from all four drains, perform UT thickness 

measurements each refuel outage from inside the drywell in the area of 

the drywell shell below the J13 penetration sleeve area to determine if 

there is a significant corrosion rate occurring in this area due to periodic 

exposure to reactor cavity leakage. In addition, UT measurements shall 

be perfomed each refuel[ing] outage around the full 360 degree 

circumference of the drywell between elevations 86’-11” and 88’-0” 

(underside of the torus [downcomer] vent piping penetrations). Inspection 

and acceptance criteria will be in accordance with IWE-2000 and 

IWE-3000[,] respectively. The results of the UT measurements shall be 

used to establish a corrosion rate and demonstrate that the effects of 

aging will be adequately managed such that the drywell can perform its 

intended function until April 11, 2046. Evidence of drywell shell 
Aging Management Review Results 

 3-133 

degradation will be documented and addressed in the corrective action 

program. 

After drainage has been established from the bottom of the air gap from 

all four drains, UT thickness measurements will be taken each of the next 

three refueling outages at the same locations as those previously 

examined as described above. These UT thickness measurements will 

be compared to the results of the previous UT inspections and, if 

corrosion is ongoing, a corrosion rate will be determined for the drywell 

shell. In the event a significant corrosion rate is detected, the condition 

will be entered in the corrective action process for evaluation and extent 

of condition determination. 

10. The cause of the reactor cavity water leakage will be investigated and 

repaired, if practical, before [the] PEO [period of extended operation]. If 

repairs cannot be made prior to the PEO, the program will be enhanced 

to incorporate the following aging management activities, as 

recommended in the Final Interim Staff Guidance LR-ISG-2006-01. 

a. Identify drywell surfaces requiring examination and implement 

augmented inspections for the period of extended operation in 

accordance with IWE-1240, as identified in Table IWE-2500-1, 

Examination Category E-C. 

b. Demonstrate through the use of augmented inspections that 

corrosion is not occurring or that corrosion is progressing so 

slowly that the age-related degradation will not jeopardize the 

intended function of the drywell shell through the period of 

extended operation. 

c. Develop a corrosion rate that can be inferred from past UT 

examinations. If degradation has occurred, evaluate the drywell 

shell using the developed corrosion rate to demonstrate that the 

drywell shell will have sufficient wall thickness to perform its 

intended function through the period of extended operation. 

Based on its review, the staff finds the UFSAR supplement for the applicant’s ASME Section XI, 

Subsection IWE Program acceptable because it is consistent with the corresponding program 

description in SRP-LR Table 3.5-2. In addition, 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, review of the applicant’s ASME Section XI, Subsection 

IWE Program, and review of the applicant’s RAI responses and LRA supplements, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the applicable enhancements and 

confirmed that their implementation through a license condition and Commitment No. 28 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 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 
Aging Management Review Results 

 3-134 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.15 Masonry Wall Program 

Summary of Technical Information in the Application. LRA Section B.2.1.31 describes the 

existing Masonry Wall Program as being consistent, with enhancement, with GALL AMP XI.S5, 

“Masonry Wall Program.” The applicant’s Masonry Wall Program was developed to meet the 

regulatory requirements of 10 CFR 50.65, (Maintenance Rule); RG 1.160; and NUMARC 93-01, 

“Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.” 

The LRA states that HCGS has no safety-related masonry walls or masonry walls whose failure 

during a seismic event could adversely impact a safety-related function. The LRA further states 

that NRC IE Bulletin 80-11, “Masonry Wall Design,” and IN 87-67 do not directly apply at HCGS. 

The LRA states that the program includes masonry walls determined to be within the scope of 

the Maintenance Rule and has been enhanced to include masonry walls within the scope of 

license renewal. Masonry walls are monitored under the Structures Monitoring Program to 

ensure that a loss of intended function does not occur. Monitoring frequency depends on safety 

significance and the condition of the structure as specified in RG 1.160. The LRA further states 

that the monitoring frequency of masonry walls used as fire barriers is 10 years; however, the 

program has been enhanced to change the 10-year frequency to 5 years to allow for early 

detection and evaluation of potential degradation. Provisions are included for more frequent 

inspections for masonry walls that are degraded to the extent that the masonry wall may not 

meet its design basis or the masonry wall has been degraded to the extent that if the 

degradation were allowed to continue uncorrected until the next normally scheduled 

assessment, the masonry wall may not meet its design basis. Qualified personnel visually 

inspect masonry walls. The LRA states that the qualified personnel are experienced engineers, 

qualified per Structures Monitoring Program requirements, have a B.S. degree and/or 

Professional Engineer license, with a minimum of 4 years experience working on building 

structures. 

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 whether 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 AMP XI.S5. 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 

AMP XI.S5. 

The staff also reviewed the portions of the “scope of the program,” “parameters monitored or 

inspected,” and “detection of aging effects” associated with an enhancement to determine 

whether the program will be adequate to manage the aging effects for which it is credited. The 

staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.2.1.31 states an enhancement to the “scope of the program” 

program element that includes addition of the following SCs that have been determined to be 

within the scope of license renewal: auxiliary boiler building, fire water pump house, masonry 

wall fire barriers, switchyard, and turbine building. 

The staff finds this enhancement acceptable because, when implemented, the applicant’s 

Masonry Wall Program will include all masonry walls within the scope of license renewal and will 
Aging Management Review Results 

 3-135 

be consistent with GALL AMP XI.S5 relative to including all masonry walls identified as 

performing intended functions in accordance with 10 CFR 54.4. 

Enhancement 2. LRA Section B.2.1.31 states an enhancement to the “parameters monitored or 

inspected” program element that includes the addition of an examination checklist for masonry 

wall inspection requirements. 

The staff finds this enhancement acceptable because, when implemented, the applicant’s 

Masonry Wall Program will be in compliance with GALL AMP XI.S5 relative to conduction of 

visual inspections for cracking and loss of material, and guidance in the form of a checklist on 

what to look for and assessment criteria of inspection findings. This enhancement will help 

provide assurance that the effects of aging will be adequately managed in a timely manner. 

Enhancement 3. LRA Section B.2.1.31 states an enhancement to the “detection of aging 

effects” program element that includes the specification of an inspection frequency of not 

greater than 5 years for the masonry walls. 

The staff finds this enhancement acceptable because, when implemented, the applicant’s 

Masonry Wall Program will be conservative and compliant with GALL AMP XI.S5 inspection 

frequency recommendations. This enhancement will help provide assurance that the effects of 

aging will be adequately managed in a timely manner. 

Based on its audit, the staff finds that elements one through six of the applicant’s Masonry Wall 

Program, with acceptable enhancements, are consistent with the corresponding program 

elements of GALL AMP XI.S5 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.31 summarizes operating experience related to the 

applicant’s Masonry Wall Program. The LRA states that masonry walls that perform an 

intended function in accordance with 10 CFR 54.4 have been systematically identified in 

accordance with the scoping and screening methodology described in the LRA. Internal and 

external operating experiences are used to enhance plant programs, prevent repeat events, and 

prevent events that have occurred at other plants from occurring at HCGS. The LRA states that 

the Masonry Wall Program shows that detection of cracks and other aging effects in masonry 

walls are being adequately managed. The inspection history revealed minor degradation of 

masonry block walls, but none that could impact their intended function. The checklist from the 

Structures Monitoring Program was used in 2006 for the main and power transformer masonry 

walls that perform a fire barrier intended function with no significant degradation identified. In 

2007, cracks in a masonry wall near the turbine building that performed a fire barrier intended 

function were identified, evaluated, found to have no impact on the design basis, and sealed. 

The LRA further states that procedures used to identify and document conditions adverse to 

quality in accordance with the corrective action program demonstrate that the Masonry Wall 

Program is effectively managing the aging effects of masonry walls. 

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. 
Aging Management Review Results 

 3-136 

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. LRA Section A.2.1.31 provides the UFSAR supplement for the Masonry 

Wall Program. The staff reviewed this UFSAR supplement description and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.5-2. The staff also notes that the applicant committed (Commitment No. 31) to enhance 

the Masonry Wall Program prior to entering the period of extended operation. Specifically, the 

applicant committed to: (1) include additional buildings and masonry walls as described in LRA 

Section A.2.1.31, (2) add an examination checklist for masonry wall inspection requirements, 

and (3) specify an inspection frequency of not greater than 5 years for masonry walls. 

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 Masonry Wall Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation through Commitment No. 31 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). 

3.0.3.2.16 Structures Monitoring Program 

Summary of Technical Information in the Application. LRA Section B.2.1.32 describes the 

existing Structures Monitoring Program as being consistent, with enhancement, with GALL 

AMP XI.S6, “Structures Monitoring Program.” The objective of the Structures Monitoring 

Program is to manage aging effects of structures or structural components such that there is no 

loss of intended function and was developed and implemented to meet regulatory requirements 

of 10 CFR 50.65, “Requirements for Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants;” RG 1.160 (Revision 2); and NUMARC 93-01, “Industry Guideline for Monitoring 

the Effectiveness of Maintenance at Nuclear Power Plants.” The LRA states that the program 

includes masonry walls determined to be within the scope of license renewal; however, HCGS 

has no safety-related masonry walls or masonry walls whose failure during a seismic event 

could adversely impact a safety-related function, so NRC IE Bulletin 80-11, “Masonry Wall 

Design,” does not directly apply. The Structures Monitoring Program incorporates all elements 

of the Masonry Wall Program and RG 1.127, “Inspection of Water-Control Structures Associated 

with Nuclear Power Plants.” The program also relies on plant procedures that are based on 

guidance contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide,” to 
Aging Management Review Results 

 3-137 

ensure proper specification of bolting material, lubricant, and installation torque. The applicant 

stated that structures and structural components are periodically inspected visually by qualified 

personnel having a B.S. Engineering degree and/or Professional Engineer license and a 

minimum of 4 years working on building structures. The applicant also stated that protective 

coatings are not relied upon to manage the effects of aging for structures included within the 

scope of the AMP, so they are not addressed. 

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 whether 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 AMP XI.S6. 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 

AMP XI.S6, with the exception of “detection of aging effects.” 

While reviewing the “detection of aging effects” program element, the staff noted that the LRA 

addresses the underground reinforced concrete structures and structures in contact with raw 

water subjected to an aggressive environment. In 2008, the groundwater and raw water 

chemistry results indicated chloride levels up to 15,000 parts per million (ppm). These chloride 

levels exceed the threshold limit for chlorides (less than 500 ppm) in the GALL Report. 

Inspection of below-grade structures will be conducted when exposed during plant excavations 

done for construction or maintenance activities. The LRA states that the HCGS Structures 

Monitoring Program has been enhanced to require periodic sampling, testing, and analysis of 

groundwater chemistry for pH, chlorides, and sulfates, and assessing its impact on buried 

structures. The LRA also states that the service water intake structure will be monitored to 

provide a bounding condition and indicator of the likelihood of concrete degradation for 

inaccessible portions of concrete structures. During the onsite audit, the applicant was asked if 

it had any plans for inspections of inaccessible reinforced concrete areas prior to the period of 

extended operation to confirm the absence of concrete degradation. The applicant responded 

that it did not and that operating experience indicates that there is no evidence of corrosion 

appearing on the interior surfaces of the concrete structures having inaccessible exterior 

surfaces. Since the applicant does not have plans for inspections of inaccessible areas, and the 

interior of the walls may not indicate the condition of the exterior walls, it is unclear to the staff 

that this is an adequate approach to managing aging of inaccessible concrete structures 

subjected to aggressive groundwater. 

By letter dated May 14, 2010, the staff issued RAI B.2.1.32-1 requesting that the applicant 

provide: (1) locations where groundwater test samples were/are taken relative to safety–related 

and important-to-safety embedded concrete walls and foundations and provide historical results 

(i.e., pH, chloride content, and sulfate content) including seasonal variation of results; and 

(2) plans for inspections in locations adjacent to embedded reinforced concrete structures, 

where chloride levels exceed limits in the GALL Report, or, if no inspections or coring of 

concrete is planned to evaluate the condition of structures (e.g., presence of steel corrosion or 

determination of chloride profiles), provide a basis to demonstrate that the current level of 

chlorides in the groundwater is not causing structural degradation of embedded walls or 

foundations. 

By letter dated June 14, 2010, the applicant responded by providing the groundwater sampling 

locations, as well as the sampling results for 2008. The provided data demonstrated that the 

wells adequately represent the groundwater present on the site and that the pH and sulfates are 
Aging Management Review Results 

 3-138 

within the GALL Report limits, while the chlorides are beyond the limit of 500 ppm. The 

applicant’s response also explained that the chloride levels in the river can be as high as 

11,000 ppm, well above the levels found in the groundwater. Based on this fact, the applicant 

explained that the service water intake structure splash zones, which are exposed to the river 

water, will serve as a limiting condition or “leading indicator” of potential degradation of 

below-grade concrete. The splash zone will be inspected on a frequency not to exceed 5 years, 

and any degradation determined to be due to aggressive chemical attack will be assessed for 

applicability to below-grade structures to determine if excavation of below-grade concrete for 

inspection is necessary. The applicant stated that since 2000, three inspections have been 

conducted of the service water intake structures and no indications of aggressive chemical 

attack have been recorded. The applicant further explained that this “leading indicator” 

approach is adequate because the river water has higher chloride levels than the groundwater, 

the service water intake structures were built with the same concrete mix as other safety-related 

structures, and the concrete cover over the reinforcing steel in the service water intake 

structures is the same as other safety-related structures. 

The staff reviewed the applicant’s response and finds it acceptable because it clearly explains 

why the service water intake structure concrete can be used as an indicator of possible 

below-grade concrete degradation. The concrete mix design used for the intake structures was 

the same as the rest of the plant, the concrete cover is the same as the rest of the plant 

structures, and the intake structures are exposed to a more aggressive environment. These 

characteristics make the service water intake structure an appropriate indicator of the condition 

of below-grade concrete. In addition, the intake structures will be inspected on a frequency not 

to exceed 5 years, which aligns with the GALL Report recommendations. The staff’s concern in 

RAI B.2.1.32-1 is resolved. 

The staff also reviewed the portions of the “scope of the program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of the enhancements follows. 

Enhancement 1. LRA Section B.2.1.32 states an enhancement to the “scope of the program” 

program element that includes the addition of the following SCs: auxiliary boiler building; fire 

water pump house; shoreline protection dike and sheet piles (RG 1.127); switchyard; turbine 

building; transmission towers; yard structures (foundations for fire water tanks, manholes, 

transformer foundations credited for SBO); masonry walls, including fire barriers; building 

penetrations that perform flood barrier, pressure boundary, shelter and protection intended 

functions; miscellaneous steel (catwalks, vents, louvers, platforms, etc.); pipe whip restraints, jet 

impingement, and missile shields; ice barriers, trash rack (RG 1.127); panels, racks, cabinets, 

and other enclosures; metal-enclosed bus; component supports (including electrical cable trays; 

electrical conduit; tubing; heating, ventilation, and air conditioning (HVAC) ducts; instrument 

racks; battery racks; and supports for piping and components that are not within the scope of 

ASME Section XI, Subsection IWF); and duct banks that contain safety-related cables and 

cables credited for SBO and anticipated transient without scram (ATWS). 

The staff finds this enhancement acceptable because, when implemented, the Structures 

Monitoring Program will include all structures considered by the applicant to require monitoring 

during the period of extended operation and will be in compliance with GALL AMP XI.S6, 

relative to the applicant specifying the structure/aging effect combinations that are managed by 

its Structures Monitoring Program. 
Aging Management Review Results 

 3-139 

Enhancement 2. LRA Section B.2.1.32 states an enhancement to the “parameters monitored or 

inspected” program element that includes: 

 (1) Observe concrete structures for reduction in equipment anchor capacity due to local 

concrete degradation by visual inspections of concrete surfaces around anchors for 

cracking and spalling. 

 (2) Clarify that inspections are performed for loss of material due to corrosion and pitting of 

additional steel components, such as embedments, panels and enclosures, doors, 

siding, metal deck, and anchors. 

 (3) Perform a one-time inspection of the external stainless steel surfaces of the expansion 

bellows at the condensate storage tank dike for loss of material due to corrosion, within 

the 10-year period prior to the period of extended operation. 

 (4) Require inspection of penetration seals, structural seals, and elastomers for degradation 

(hardening, shrinkage, and loss of strength) that will lead to loss of sealing. 

 (5) Require monitoring of vibration isolators associated with component supports other than 

those covered by ASME Code Section XI, Subsection IWF. 

 (6) Add an examination checklist for masonry wall inspection requirements. 

 (7) Enhance parameters to be monitored for wooden components to include change in 

material properties and loss of material due to insect damage and moisture damage. 

The staff finds this enhancement acceptable because, when implemented, the Structures 

Monitoring Program will be in compliance with GALL AMP XI.S6, relative to parameters 

monitored or inspected being commensurate with industry codes, standards, and guidelines. 

This enhancement will help provide assurance that aging degradation leading to loss of 

intended functions will be detected and the extent of degradation determined so that the 

degradation can be adequately managed in a timely manner. 

Enhancement 3. LRA Section B.2.1.32 states an enhancement to the “detection of aging 

effects” program element that includes: 

 (1) Specify an inspection frequency of not greater than 5 years for the structures including 

submerged portions of the service water intake structure. 

 (2) Require individuals responsible for inspections and assessments for structures to have a 

B.S. degree and/or Professional Engineer license and a minimum of 4 years experience 

working on building structures. 

 (3) Perform periodic sampling, testing, and analysis of groundwater chemistry for pH, 

chlorides, and sulfates on a frequency of 5 years. 

 (4) Require supplemental inspections of the affected in-scope structures within 30 days 

following an extreme environmental or natural phenomena (large floods, significant 

earthquakes, hurricanes, and tornadoes). 

 (5) Perform a chemical analysis of ground or surface water in-leakage when there is 

significant in-leakage or there is reason to believe that the in-leakage may be damaging 

concrete elements or reinforcing steel. 
Aging Management Review Results 

 3-140 

The staff found this enhancement acceptable because, when implemented, the Structures 

Monitoring Program will be in compliance with GALL AMP XI.S6 relative to inspection methods, 

inspection schedule, and inspector qualifications being commensurate with industry codes, 

standards, and guidelines, and inclusion of industry and plant-specific operating experience. 

This enhancement will help provide assurance that the aging degradation will be detected and 

quantified before there is a loss of intended functions. 

Enhancement 4. LRA Section B.2.1.32 states an enhancement to the “acceptance criteria” 

program element that includes additional acceptance criteria as contained in American Concrete 

Institute (ACI) 349.3R-96. The staff found this enhancement acceptable, because when 

implemented, the Structures Monitoring Program will be in compliance with GALL AMP XI.S6 

relative to ACI 349.3R-96 being used to provide an acceptable basis for developing acceptance 

criteria for concrete structural elements, steel liners, joints, coatings, and waterproofing 

membranes. This enhancement will help provide assurance that the need for corrective actions 

will be identified before loss of intended functions. 

The staff reviewed the enhancements to the program elements “scope of the program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria,” and 

determined that, with these enhancements, the applicant’s Structures Monitoring Program is 

consistent with the GALL Report. 

Based on its audit and review of the applicant’s response to RAI B.2.1.32-1, the staff finds that 

elements one through six of the applicant’s Structures Monitoring Program, with acceptable 

enhancements, are consistent with the corresponding program elements of GALL AMP XI.S6 

and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.32 summarizes operating experience related to the 

Structures Monitoring Program. The LRA states that operating experience is used to enhance 

plant programs, prevent repeat events, and prevent events that have occurred at other plants 

from occurring at HCGS. Operating experience screens, evaluates, and acts on operating 

experience documents and information to prevent or mitigate consequences of similar events. 

The LRA states that the Structures Monitoring Program inspection history has revealed minor 

degradation of structural components, but none was significant enough to impact their intended 

function. Deficiencies identified were evaluated and corrected. Baseline inspections of all 

structures within the scope of the Maintenance Rule were completed in 1997. In 2007, 

condition monitoring inspections of the reactor building, including the primary containment and 

torus, were performed and indicated satisfactory results. Some minor rust was found on the 

torus horizontal restraint end plates that connect to the wall, and minor rust was found on the 

building floor framing steel, but conditions were not found to warrant immediate repair. 

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 the audit, the staff discussed 

spent fuel leakage with the applicant. The applicant explained that minimal leakage has been 

detected when the pool level is increased above the normal level. The applicant further 

explained that, based on subsequent inspections of the area around the pool, all of the leakage 

is contained within the SFP drain system. Based on the minimal amount of leakage and the fact 

that it is contained within the drain system, the staff found this condition acceptable. 
Aging Management Review Results 

 3-141 

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. LRA Section A.2.1.32 provides the UFSAR supplement for the Structures 

Monitoring Program. The staff reviewed this UFSAR supplement section and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.5-2. 

The staff also notes that the applicant committed (Commitment No. 32) to enhance the 

Structures Monitoring Program prior to entering the period of extended operation. Specifically, 

the applicant committed to: 

 (1) Enhance the scope of the program to include additional SCs as described in LRA 

Section A.2.1.32. 

 (2) Observe concrete structures for a reduction in equipment anchor capacity due to local 

concrete degradation. This will be accomplished by visual inspection of concrete 

surfaces around anchors for cracking and spalling. 

 (3) Clarify inspection criteria for loss of material due to corrosion and pitting of additional 

steel components, such as embedments, panels and enclosures, doors, siding, metal 

deck, and anchors. 

 (4) Perform a one-time inspection of the external stainless steel surfaces of the expansion 

bellows at the condensate storage tank dike for loss of material due to corrosion, within 

the 10-year period prior to the period of extended operation. 

 (5) Require inspection of penetration seals, structural seals, and elastomers for degradation 

that will lead to a loss of sealing by visual inspection of the seal for hardening, shrinkage 

and loss of strength. 

 (6) Require monitoring of vibration isolators associated with component supports, other than 

those covered by ASME Code Section XI, Subsection IWF. 

 (7) Add an examination checklist for masonry wall inspection requirements. 

 (8) Enhance parameters monitored for wooden components to include change in material 

properties, loss of material due to insect damage, and moisture damage. 

 (9) Specify an inspection frequency of not greater than 5 years for structures, including 

submerged portions of the service water intake structure. 

 (10) Require individuals responsible for inspections and assessments for structures to have a 

B.S. Engineering degree and/or Professional Engineer license and a minimum of 4 years 

experience working on building structures. 
Aging Management Review Results 

 3-142 

 (11) Perform periodic sampling, testing, and analysis of groundwater chemistry for pH, 

chlorides, and sulfates on a frequency of 5 years. 

 (12) Require supplemental inspections of the in-scope structures within 30 days following 

extreme environmental or natural phenomena (large floods, significant earthquakes, 

hurricanes, and tornadoes). 

 (13) Perform a chemical analysis of ground or surface water in-leakage when there is 

significant in-leakage or there is reason to believe that the in-leakage may be damaging 

concrete elements or reinforcing steel. 

 (14) Enhance implementing procedures to include additional acceptance criteria details 

specified in ACI 349.3R-96. 

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 Structures Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent, based on the resolution of the RAI as 

discussed above. Also, the staff reviewed the enhancements and confirmed that their 

implementation through Commitment No. 32 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). 

3.0.3.2.17 RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants” 

Summary of Technical Information in the Application. LRA Section B.2.1.33 describes the 

existing RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants” Program as consistent, with enhancements, with GALL AMP XI.S7, 

“RG 1.127,”Inspection of Water-Control Structures Associated with Nuclear Power Plants.” The 

applicant stated RG 1.127 is implemented through the Structures Monitoring Program 

(10 CFR 50.65), and is based on the guidance provided in RG 1.127 and ACI 349.3R. The 

water control structures included within the scope of license renewal are the service water 

intake structure and shoreline protection and dike structures. The applicant further stated that 

SCs including submerged portions of the service water intake structure will include an 

inspection frequency of 5 years. 

The applicant stated safety and performance instrumentation such as seismic instrumentation, 

horizontal and vertical movement instrumentation, uplift instrumentation, and other 

instrumentation described in RG 1.127 are not incorporated in the design of HCGS 

water-control structures. Thus, inspection activities related to safety and performance 

instrumentation are not applicable and are not specified in the implementing procedures. 
Aging Management Review Results 

 3-143 

The applicant further stated that conformance to RG 1.127 was part of HCGS’s original design 

basis, and elements of the program have been incorporated in the Structures Monitoring 

Program. 

As noted below, the applicant stated that prior to the period of extended operation, the program 

will be enhanced to provide reasonable assurance that water-control aging effects will be 

adequately managed during the period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether 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 AMP 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 

AMP XI.S7 with the exception of the “scope of the program” program element. For this element, 

the staff determined the need for additional clarification, which resulted in the issuance of an 

RAI. 

The “scope of the program” program element in the Program Basis Document 

SH-PBD-AMP-XI.S7 states there are no HCGS water-control structures that are credited for 

flood protection. It is not clear to the staff that this statement is consistent with LRA Table 2.4-9 

which indicates parts of the service water intake structure as flood barrier, therefore, by letter 

dated May 14, 2010, the staff issued RAI B.2.1.33-01 requesting that the applicant explain the 

apparent inconsistency. 

In its response dated June 14, 2010, the applicant explained that the statement in the basis 

document was potentially misleading and is revised to state, “There are no Hope Creek 

water-control structures that are credited for flood protection to control flood level or prevent 

flooding for the site general area.” The applicant further explained that the service water intake 

structure includes the intended function of flood barrier for the safety-related equipment within 

the building, but not to control site general area flooding. 

The staff reviewed the applicant’s response and finds it acceptable because it explains the 

apparent discrepancy between statements in the basis document and the LRA. The 

water-control structures are not credited for flood protection of the site general area; however, 

they are credited as a flood barrier for the safety-related equipment within the structure. The 

staff’s concern in RAI B.2.1.33-01 is resolved. 

The staff also reviewed the portions of the “scope of the program,” “parameters monitored or 

inspected,” and “detection of aging effects” program elements associated with the 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.2.1.33 states an enhancement to the “scope of the program” 

program element. The LRA explains that shoreline protection and dike structures will be added 

to the scope of the program. The staff found this enhancement acceptable because when the 

enhancement is implemented, the RG 1.127,”Inspection of Water-Control Structures Associated 

with Nuclear Power Plants Program” will be consistent with the guidance in GALL AMP XI.S7 

and will provide assurance that the effects of aging will be adequately managed. 
Aging Management Review Results 

 3-144 

Enhancement 2. LRA Section B.2.1.33 states an enhancement to the “parameters monitored or 

inspected” program element. The LRA explains that monitoring for wooden components will be 

enhanced to include change in material properties and loss of material due to insect damage 

and moisture damage. The staff found this enhancement acceptable because when the 

enhancement is implemented, the RG 1.127,”Inspection of Water-Control Structures Associated 

with Nuclear Power Plants Program” will be consistent with the guidance in GALL AMP XI.S7 

and will provide assurance that the effects of aging will be adequately managed. 

Enhancement 3. LRA Section B.2.1.33 states an enhancement to the “detection of aging 

effects” program element. The LRA explains that inspection requirements for submerged 

concrete structural components will be enhanced to require that inspections be performed by 

dewatering a pump bay or by a diver if the pump bay is not dewatered. The staff found this 

enhancement acceptable because when the enhancement is implemented, the 

RG 1.127,”Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program” will be consistent with the guidance in GALL AMP XI.S7 and will provide assurance 

that the effects of aging will be adequately managed. 

Enhancement 4. LRA Section B.2.1.33 states an enhancement to the “detection of aging 

effects” program element. The LRA explains that procedures will be enhanced to specify an 

inspection frequency of not greater than 5 years for structures, including submerged portions of 

the service water intake structure. The staff found this enhancement acceptable because when 

the enhancement is implemented, the RG 1.127,”Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program” will be consistent with the guidance in GALL 

AMP XI.S7 and will provide assurance that the effects of aging will be adequately managed. 

Enhancement 5. LRA Section B.2.1.33 states an enhancement to the “detection of aging 

effects” program element. The LRA explains that procedures will be enhanced to require 

supplemental inspections of the in-scope structures within 30 days following extreme 

environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and 

tornadoes). The staff found this enhancement acceptable because when the enhancement is 

implemented, the RG 1.127,”Inspection of Water-Control Structures Associated with Nuclear 

Power Plants Program” will be consistent with the guidance in GALL AMP XI.S7 and will provide 

assurance that the effects of aging will be adequately managed. 

Based on its audit and review of the applicant’s response to RAI B.2.1.33-01, the staff finds that 

elements one through six of the applicant’s RG 1.127,”Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” Program, with acceptable enhancements are consistent 

with the corresponding program elements of GALL AMP XI.S7 and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.33 summarizes operating experience related to the 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program.” The LRA explains that in 2004, industry operating experience (OE18658) was 

evaluated for potential generic implication at HCGS. The operating experience subject was 

related to a plant’s intake structure experiencing significant concrete spalling of the floors and 

walls inside the structure due to chloride induced reinforcement corrosion. The interior portion 

of the plant’s intake structure was exposed to significant saltwater leakage from various plant 

components. The LRA further states that the HCGS service water intake structure can be 

exposed to a similar environment, therefore, there is a potential for this condition to occur. The 

disposition of this generic evaluation was that all site safety-related structures are subject to 

condition monitoring in accordance with the structures monitoring program. The LRA also 

discusses inspections performed on submerged concrete walls and other structural components 
Aging Management Review Results 

 3-145 

of the “D” service water intake structure pump bay to support the station equipment preventive 

maintenance (PM) requirements and for the condition monitoring of structures for HCGS. For 

the interior submerged concrete walls and the exterior submerged walls, there was no evidence 

of any deficiency or degradation. There was some minimal erosion at the wall corners that was 

noted as acceptable by the station structural engineer. There was corrosion noted on the 

support plates that provide the structural attachments for the submerged portion of the service 

water pump and screen to the structure. The upper support plates had significant corrosion that 

warranted an engineering evaluation of the condition. The evaluation noted that the design 

basis was maintained and adequate for all design-basis events (DBEs). The LRA explains that 

as a result of the corrective action plan for the degradations noted from this inspection and to 

provide for a focused inspection of the normally submerged interior structural components of the 

service water pump bays, future inspections will be performed under a separate PM condition 

monitoring inspection task to coincide with the traveling water screen/equipment station PM 

task. 

The staff reviewed the operating experience information in the application and during the audit 

to determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant 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 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. 

UFSAR Supplement. LRA Section A.2.1.33 provides the UFSAR supplement for the RG 

1.127,”Inspection of Water-Control Structures Associated with Nuclear Power Plants” Program. 

The staff reviewed this UFSAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.5-2. The staff also notes that the applicant committed (Commitment No. 33) to enhance 

the RG 1.127,”Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program” prior to entering the period of extended operation. Specifically, the applicant 

committed to: (1) adding the shoreline protection and dike structure to the scope of the program, 

(2) including changes in material properties and loss of material of wooden components within 

the parameters monitored, (3) requiring submerged structural components be inspected by 

dewatering a pump bay or by diver, (4) specifying an inspection frequency not greater than 

5 years, and (5) requiring supplemental inspections of in-scope structures within 30 days 

following extreme environmental phenomena. 

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 RG 1.127,”Inspection of 

Water-Control Structures Associated with Nuclear Power Plants” Program, the staff determines 

that those program elements for which the applicant claimed consistency with the GALL Report 

are consistent. Also, the staff reviewed the enhancement and confirmed that its implementation 

through Commitment No. 33 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 
Aging Management Review Results 

 3-146 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2.18 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

Summary of Technical Information in the Application. LRA Section B.2.1.39 describes the new 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program as consistent, with exception, with GALL AMP XI.E6, “Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The 

applicant stated that its program is a new one-time inspection program that manages the 

loosening of bolted connections due to thermal cycling, ohmic heating, electrical transients, 

vibration, chemical contamination, corrosion, and oxidation. The applicant also 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. The applicant further stated that 

the scope of the sampling program will consider application (medium and low voltage), circuit 

loading (high loading), and location (high temperature, high humidity, vibration, etc.), and that 

the technical basis for the sample selection will be documented. The applicant also stated that 

the one-time test used to confirm the absence of an aging effect with respect to electrical cable 

connection stressors will be a specific, proven test for detecting loose connections, such as 

thermography or contact resistance measurement, as appropriate for the application. 

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 whether 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 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 GALL 

AMP XI.E6, with the exception of the “scope of the program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending.” 

The staff also reviewed the portions of the “scope of the program,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “corrective actions” 

program elements 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. LRA Section B.2.1.39 states an exception to the “scope of the program,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“corrective actions” program elements. Prior to the applicant’s submittal of the LRA, the staff 

was working toward the issuance of a revision to GALL AMP XI.E6, “Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualifications Requirements,” via the 

ISG process. The applicant stated that the exception for this AMP is that the Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program 

is consistent with the GALL Report, as modified by the September 6, 2007, proposed revision of 

LR-ISG-2007-02. The ISG recommends that, prior to the period of extended operation, a 

one-time inspection on a representative sample basis is warranted to ensure that either aging of 

metallic cable connections is not occurring and/or that the existing PM program is effective such 

that a periodic inspection program is not required. The one-time inspection verifies that 
Aging Management Review Results 

 3-147 

loosening and/or high resistance of cable connections due to thermal cycling, ohmic heating, 

electrical transients, vibration, chemical contamination, corrosion, or oxidation are not occurring 

and, therefore, periodic inspections are not required. Subsequent to the applicant’s LRA, a 

notice of availability of the final LR-ISG-2007-02 was published in the Federal Register on 

December 23, 2009 (74 FR 68287). Therefore, the staff evaluated the AMP and LRA 

Sections B.2.1.39 and A.2.1.39 based on the staff’s aging management guidance provided by 

the final LR-ISG-2007-02 and GALL AMP XI.E6. 

The staff finds the exception acceptable because the identified program elements are in 

accordance with GALL AMP XI.E6, as modified by the final LR-ISG-2007-02, for compliance 

with the requirements of 10 CFR 54.21(a)(3) to demonstrate that the effects of aging for certain 

electrical cable connections not subject to the requirements of 10 CFR 50.49 will be adequately 

managed during the period of extended operation. 

Based on its audit and review of LRA Section B.2.1.39, the staff finds that elements one through 

six of the applicant’s Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program, with the acceptable exception, are consistent with the 

corresponding program elements of GALL AMP XI.E6, as modified by the final LR-ISG-2007-02 

and, therefore, acceptable. 

Operating Experience. LRA Section B.2.1.39 summarizes operating experience related to the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program. Although a new program, the applicant stated that plant operating 

experience has successfully demonstrated the identification of loose connections through the 

effective use of thermography. The applicant also stated that plant operating experience is in 

alignment with industry experience, in that electrical connections have not experienced a high 

degree of failures and that existing plant installation and maintenance practices are effective. 

The applicant further stated that operating experience provides objective evidence that 

thermography will detect and/or monitor loose electrical connections. The applicant concluded 

that thermography and the corrective action program will resolve issues prior to the loss of 

intended function and, therefore, there is sufficient confidence that the implementation of the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program will effectively confirm the absence of aging degradation of metallic 

cable connections. Referencing the LRA operating experience examples, the applicant 

concluded that the effects of aging and aging mechanisms are being adequately managed. The 

applicant stated that these examples provide objective evidence that the AMP will be effective in 

resolving problems prior to loss of function. 

The staff reviewed the operating experience 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 applicant’s plant operating experience 

database to determine whether the applicant had adequately incorporated and evaluated 

operating experience related to this program. Further, the staff performed a search of operating 

experience for the period 2000 through November 2009. Databases were searched using 

various keyword searches and then reviewed by technical auditor staff. Databases searched 

include GLs, Bulletins, Regulatory Issue Summaries, Licensee Event Reports, Event 

Notifications, Inspection Findings and Inspection Reports. 

During its review, it was not clear based on the applicant’s operating experience discussion that 

the referenced LRA operating experience examples were representative, in that the search 
Aging Management Review Results 

 3-148 

methodology and criteria are not discussed, such as databases searched, connection types, 

time frame, or connection stressors such as application, loading, and environment. Based on 

the above, the staff could not conclude that the applicant’s program will 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. 

By letter dated May 14, 2010, the staff issued RAI B.2.1.39-1 requesting that the applicant 

explain the evaluation methods and search criteria used to select the representative examples 

in LRA Section B.2.1.39 and the associated basis document. The applicant responded by letter 

dated June 14, 2010, and stated that a significant source for operating experience is found in 

historical plant documentation records, including maintenance work records, condition reports 

and corrective action evaluations, external operating experience evaluations, and engineering 

evaluations of regulatory correspondence such as NRC INs and GLs. The applicant also stated 

that operating experience for existing programs is found in system and program assessment 

documentation such as system/program manager notebooks, system health reports, program 

health reports and performance indicators, self assessments, and third party assessments. The 

applicant further stated that no limit was specified for historical record searches although it was 

preferred to use more recent examples (since 2000) with the primary focus to identify operating 

experience where age-related degradation was precluded, mitigated, identified during 

performance testing, or otherwise detected or corrected prior to loss of component intended 

functions. In addition, the applicant stated that operating experience that indicated an AMP or 

aging management activity may not be effective was also considered, including potential 

enhancements to improve the program or activity that demonstrated that feedback from past 

operating experience results in appropriate program enhancements to improve aging 

management effectiveness. The applicant stated that specific operating experience was 

selected for discussion in the LRA regarding the AMP and that these examples were peer 

reviewed by a license renewal project manager and the site’s subject matter expert and 

approved by the technical lead. 

With the additional information provided by the applicant’s RAI response, the staff finds the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program acceptable because the applicant provided a more detailed description 

of the data searched, evaluation methods, and search criteria employed by the applicant in 

selecting the representative operating experience examples. The operating experience 

provided by the applicant and identified by the staff’s independent database search is bounded 

by industry operating experience with no previously unknown aging effects identified by the 

staff. Based on the applicant’s RAI response and the staff’s independent operational 

experience reviews, the staff concludes that the applicant’s program operating experience is 

consistent with SRP-LR Section A.1.2.3.10, such that there is reasonable assurance that the 

operating experience and conclusions provided by the applicant are representative of plant 

operating experience and that the Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program will effectively manage the effects of aging 

and aging mechanisms during the period of extended operation. Therefore, the staff’s concern 

described in RAI B.2.1.39-1 is resolved. 

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

RAI B.2.1.39-1, 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. 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. 
Aging Management Review Results 

 3-149 

UFSAR Supplement. LRA Section A.2.1.39 provides the UFSAR supplement for the Electrical 

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 

Program. 

The staff reviewed this UFSAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.6-2, as modified by LR-ISG-2007-02. The staff also notes that the applicant committed 

(Commitment No. 39) to implement the new Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program prior to entering the period of 

extended operation for managing aging of applicable components. 

The staff determines 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 review of the applicant’s Electrical Cable Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff 

determines those program elements for which the applicant claimed consistency with the GALL 

Report and LR-ISG-2007-02 are consistent. In addition, the staff reviewed the exception and its 

justification and determines that the AMP, with exception, is adequate to manage the aging 

effects for which the LRA credits it. The staff concludes that the applicant has demonstrated 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.19 Metal Fatigue of Reactor Coolant Pressure Boundary 

Summary of Technical Information in the Application. LRA Section B.3.1.1 describes the 

existing Metal Fatigue of Reactor Coolant Pressure Boundary Program as consistent, with 

enhancements, with GALL AMP X.M1, “Metal Fatigue of Reactor Coolant Pressure Boundary.” 

In LRA Section B.3.1.1, the applicant stated the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program monitors and tracks the number of critical thermal and pressure transients to 

ensure that the CUFs for selected RCPB components remain less than 1.0 through the period of 

extended operation. The applicant stated the program determines the number of transients that 

occur and uses the software program FatiguePro® to compute CUFs for select locations. The 

applicant also stated the program requires the generation of fatigue monitoring reports on an 

annual basis. These reports include a list of transient events, cycle summary event details, 

CUFs, a detailed fatigue analysis report, and a cycle projection report. In addition, the applicant 

stated that if the fatigue usage for any location increases beyond a projected amount, based on 

cycle accumulation trends, or if the number of cycles approaches the limit, the corrective action 

program will be used to evaluate the condition and determine the remedial action to be taken. 

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 the conditions 

observed 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 AMP X.M1. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP X.M1. 
Aging Management Review Results 

 3-150 

The staff also reviewed the portions of the “scope of the program,” “preventive actions,” 

“parameters monitored or inspected,” “monitoring and trending,” “acceptance criteria,” and 

“corrective actions” program elements associated with the applicant’s enhancements of the 

program to determine if the program will adequately manage the aging effects for which it is 

credited. 

Enhancement 1. LRA Section B.3.1.1 describes an enhancement to the “parameters monitored 

or inspected” program element. The enhancement includes transients in addition to the 

transients described in the TSs and UFSAR. The enhancement expands the fatigue monitoring 

program to encompass other components requiring monitoring. The applicant will implement 

this enhancement, prior to the period of extended operation, as described in Commitment 

No. 46, LRA Appendix A, Section A.5. 

Because it was not clear to the staff if the commitment was to enhance the basis document (or 

procedure) or to make the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

“parameters monitored or inspected” program element consistent with GALL AMP X.M1, an RAI 

was issued. On June 25, 2010, the staff issued RAI B.3.1.1-1, item 1 requesting that the 

applicant clarify if the commitment was to enhance the basis document (or procedure) or to 

make the Metal Fatigue of Reactor Coolant Pressure Boundary Program “parameters monitored 

or inspected” program element consistent with GALL AMP X.M1. 

In its response dated July 26, 2010, the applicant confirmed that Enhancement 1 is proposed to 

make the “parameters monitored or inspected” program element of the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program consistent with the corresponding program element of 

GALL AMP X.M1. The staff noted that this program element in GALL AMP X.M1 recommends 

monitoring of all plant transients that cause cyclic strains, which are significant contributors to 

fatigue usage factor. The applicant stated that additional transients meeting this GALL Report 

criterion, beyond those in its Metal Fatigue of Reactor Coolant Pressure Boundary Program, 

have been identified and will be added to the enhanced program. The applicant described 

those additional transients which are listed in LRA Table 4.3.1-1 with “N” (No) under the column 

titled “Included in Table 3.9-1 or Table 3.9-1a of UFSAR.” The applicant further stated this 

program enhancement will be implemented by revising the program implementing procedures to 

include monitoring of the additional transients added by Enhancement 1. 

Based on its review, the staff finds the applicant’s response to RAI B.3.1.1-1, item 1 acceptable 

because the applicant is including these additional transients to be monitored by its Metal 

Fatigue of Reactor Coolant Pressure Boundary Program during the period of extended 

operation, consistent with the GALL Report recommendation to monitor all plant transients that 

cause cyclic strains, which are significant contributors to fatigue usage factor and will include 

the monitoring of these transients in its implementing procedures of this program. 

During the review, the staff noted the transients specified in TS Table 5.7.1-1 and tracked 

pursuant to the monitoring requirements in TS 5.7.1, are a subset of the design-basis transients 

listed in UFSAR Sections 3.9.1.1.1 through 3.9.1.1.11 and Tables 3.9-1 and 3.9-1a. It was not 

evident to the staff which process would be used at HCGS to track the design-basis transients 

that were listed in the UFSAR sections or tables but were not within the scope of the stated TS 

requirement. On June 30, 2010, the staff issued RAI B.3.1.1-1, item 2 requesting that the 

applicant clarify the process that will be used at HCGS to track the design-basis transients that 

are listed in the UFSAR but are not within the scope of TS 5.7.1. 
Aging Management Review Results 

 3-151 

In its response dated July 26, 2010, the applicant stated that the process that will be used to 

track the occurrences of those design-basis transients that are listed in the UFSAR, but are not 

within the scope of TS 5.7.1 will be the combination of procedures and a fatigue monitoring 

software program. The applicant further stated that with Enhancement 2 this process will 

become predominantly automated based on plant parameter monitoring using a software 

program to obtain plant operating data, and supplemented by input from manual cycle counting. 

The staff noted that existing plant procedures currently track transients listed in the TSs and 

these procedures will be enhanced to track the occurrences of those design-basis transients 

that are listed in the UFSAR but are not within the scope of TS 5.7.1. The applicant committed 

(Commitment No. 46) to implement Enhancements 1 and 2 prior to the period of extended 

operation. 

Based on its review, the staff finds the applicant’s response to RAI B.3.1.1-1, item 2 acceptable 

because the applicant is including design-basis transients that are listed in the UFSAR but are 

not within the scope of TS 5.7.1 to be monitored by its Metal Fatigue of Reactor Coolant 

Pressure Boundary Program during the period of extended operation, consistent with the GALL 

Report recommendation to monitor all plant transients that cause cyclic strains, which are 

significant contributors to fatigue usage factor and will include the monitoring of these transients 

in its implementing procedures of this program. 

During the review, the staff noted that additional transients were incorporated into the program 

and included in LRA Table 4.3.1-1, “HCGS Reactor Pressure Vessel Design Transients and 

60-Year Cycle Projections.” These transients are the safety relief valve actuation transient, the 

core spray injection event transient, the HPCI event transient, the reactor water cleanup pump 

trip event transient, standby liquid control (SLC) injection event transient, the CRD event 

transient, the LPCI event transient, and the reactor recirculation single loop operation event 

transient. It was not evident to the staff if this list included all the additional transients. It was 

also not evident if the applicant was proposing the AMP track these additional transients or if the 

applicant was proposing to update the design basis in UFSAR Section 3.9.1.1 to include these 

additional transients. 

On June 30, 2010, the staff issued RAI B.3.1.1-1, item 3 requesting that the applicant identify 

the additional transients referred to in Enhancement 1 of the AMP and to clarify which ASME 

Code Class 1 components these additional transients are applied to. The staff also asked the 

applicant to clarify whether an update of the design basis will be performed to include these 

transients, and if so, to identify the sections of the UFSAR affected. The applicant was also 

asked to clarify whether this will be covered within the scope of an LRA commitment. The staff 

asked the applicant to justify omitting these transients from the design basis. 

In its response dated July 26, 2010, the applicant stated that the additional transients and their 

associated design number of cycles are derived from events reported from all UFSAR sources, 

as indicated in LRA Table 4.3.1-1, Note 1, and also from the applicable design-basis 

calculations. The applicant stated that since these additional transients are already included in 

the design basis, no changes to the design basis are being made and, therefore, no changes to 

UFSAR Section 3.9.1.1 are required as a result of the additional transients being added to the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. Furthermore, since no sections 

or tables in UFSAR Section 3.9.1.1 are changed, the applicant stated that no activities to revise 

UFSAR Section 3.9.1.1 are required. The applicant provided a table listing the ASME Code 

Class 1 Components affected by these additional transients and the corresponding LRA Table 

that lists the corresponding component. 
Aging Management Review Results 

 3-152 

Based on its review, the staff finds the applicant’s response to RAI B.3.1.1-1, item 3 acceptable 

because the additional transients were already part of its design basis and there was not a need 

to update the UFSAR to include these additional transients. 

During the review, the staff noted that the applicant proposed enhancing the fatigue monitoring 

program to expand the “program to encompass other components identified to have fatigue as 

an analyzed aging effect, which require monitoring.” The staff noted that a similar enhancement 

is given in Enhancement 4 of the AMP, in the “corrective actions” program element in GALL 

AMP X.M1. The “corrective actions” program element recommendation in GALL AMP X.M1 

states, in part, that for programs that monitor a sample of high fatigue usage locations, 

“corrective actions include a review of additional affected reactor coolant pressure boundary 

locations.” It was not apparent to the staff if the expansion criteria in Enhancement 1 is applied 

to the “scope of the program,” “monitoring and trending,” or “corrective actions” program 

elements in the program or whether it is redundant to the enhancement discussed in 

Enhancement 4 of the AMP. 

On June 30, 2010, the staff issued RAI B.3.1.1-1, item 4 requesting that the applicant clarify 

whether the expansion criterion in Enhancement 1 is being applied as an enhancement of the 

“monitoring and trending” program element or “corrective actions” program element of the AMP, 

or whether it is redundant with the enhancement discussed in Enhancement 4 of the AMP. The 

staff also asked the applicant to justify if the expansion aspect of the enhancement does not 

relate to a corrective action activity, why the expansion referred to in Enhancement 1 was not 

also placed in the “scope of the program” or “monitoring and trending” program elements of the 

AMP. 

In its response dated July 26, 2010, the applicant stated that the expansion criterion in 

Enhancement 1 is for expansion of the number of transients and components being monitored 

by the program, and not for expansion of the RCPB locations to be reviewed as a result of an 

environmental fatigue sample location usage factor approaching its design limit in 

Enhancement 4; therefore, it is not redundant. The applicant also stated that Enhancement 1 

does not provide enhancements to the “scope of the program” or “corrective actions” program 

elements, since these elements do not discuss the transients or components to be monitored by 

the program. The staff reviewed the corresponding program elements of GALL AMP X.M1 and 

finds the applicant’s determination that Enhancement 1 does not affect the “scope of the 

program” and “corrective actions” program elements. However, Enhancement 1 can be applied 

to the “monitoring and trending” program element, since the expansion of components 

increased the number of “high fatigue usage locations” beyond those in the current fatigue 

monitoring program. By letter dated July 26, 2010, the applicant amended its LRA to identify 

that the “monitoring and trending” program element is affected by Enhancement 1. The staff 

reviewed the “monitoring and trending” program element of GALL AMP X.M1 which states the 

program monitors a sample of high fatigue usage locations. The staff noted that the applicant’s 

Enhancement 1 expands the fatigue monitoring program to encompass other components 

identified to have fatigue as an analyzed aging effect, which require monitoring, consistent with 

the recommendations of the GALL Report. 

Based on its review, the staff finds the applicant’s response to RAI B.3.1.1-1, item 4 acceptable 

because the staff confirmed that Enhancement 1 does not affect the “scope of the program” and 

“corrective actions” program elements of GALL AMP X.M1, and the applicant identified that this 

enhancement does impact the “monitoring and trending” program element and amended its 

LRA to reflect this impact. The staff also finds that the applicant’s Enhancement 1 is consistent 
Aging Management Review Results 

 3-153 

with the recommendations of the “monitoring and trending” program element of GALL 

AMP X.M1. 

Based on its review, the staff finds Enhancement 1 acceptable because it is consistent with the 

recommendations of the GALL Report, as described above in the staff’s evaluation of 

RAI B.3.1.1-1. 

Enhancement 2. LRA Section B.3.1.1 states an enhancement to the “scope of the program,” 

“preventive actions,” “parameters monitored or inspected,” “monitoring and trending,” and 

“acceptance criteria” program elements. This enhancement expands on the existing program 

element to use a software program to automatically count transients and calculate cumulative 

usage on select components. By letter dated September 20, 2010, the applicant amended its 

Enhancement 2 to state that, at this time, only cycle–based fatigue monitoring will be used and 

if stress–based fatigue monitoring is used in the future, it will consider the six stress terms in 

accordance with the methodology from ASME Section III, Subsection NB, Subarticle NB3200.The applicant proposed to implement this enhancement, prior to the period of extended 

operation, as identified in Commitment No. 46, LRA Appendix A, Section A.5, as amended by 

letter dated September 20, 2010. 

The staff noted that the applicant is only using cycle–based fatigue monitoring as part of its 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff further noted that this 

technique does not rely on software that uses a simplified input to the Greens’ function of only 

one value of stress, which was expressed in NRC RIS 2008-30. The staff further noted that 

cycle–based fatigue monitoring uses the design-basis fatigue calculations which consider the 

six stress terms in accordance with the methodology from ASME Section III, Subsection NB, 

Subarticle NB- 3200 for the reactor pressure vessel components. 

Based on its review, the staff finds the applicant’s amendment to Enhancement 2 acceptable 

because: (1) the applicant does not rely on the use stress-based fatigue monitoring software 

that uses a simplified input to the Greens’ function, which uses only one value of stress as 

stated in NRC RIS 2008-30, “Fatigue Analysis of Nuclear Power Plant Components” (2) the 

applicant relies only on cycle–based fatigue monitoring that uses the design-basis fatigue 

calculations which consider the six stress terms in accordance with the methodology from 

ASME Section III, Subsection NB, Subarticle NB- 3200 for the reactor pressure vessel 

components, and (3) the applicant addressed the concerns associated with NRC RIS 2008-30. 

During the review, it was not evident to the staff whether the enhancement is being made to 

make the “scope of the program,” “preventive actions,” “parameters monitored or inspected,” 

“monitoring and trending,” and “acceptance criteria” program elements of the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program consistent with the corresponding program 

elements in GALL AMP X.M1. It was also not evident to the staff what would be enhanced in 

the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff could not 

determine if the enhancement would involve a change to the FatiguePro® monitoring software 

or an alternative program, the stated program elements in the basis document or procedure for 

this AMP, the implementing procedure for this AMP, or some combination of these 

software/document bases. 

On June 30, 2010, the staff issued RAI B.3.1.1-2 requesting that the applicant confirm the 

enhancement is being proposed to make the “scope of the program,” “preventive actions,” 

“parameters monitored or inspected,” “monitoring and trending,” and “acceptance criteria” 

program elements of the Metal Fatigue of Reactor Coolant Pressure Boundary Program 
Aging Management Review Results 

 3-154 

consistent with those in GALL AMP X.M1. The staff also asked the applicant to clarify what will 

be enhanced and to address how the enhancement affects the program elements. 

In its response dated July 26, 2010, the applicant stated that Enhancement 2 will make the 

“scope of the program,” “preventive actions,” “parameters monitored or inspected,” “monitoring 

and trending,” and “acceptance criteria” program elements of its program consistent with those 

in GALL AMP X.M1. The applicant stated the current program as described in LRA 

Section B.3.1.1 does not use a fatigue monitoring software program, and Enhancement 2 will 

cause implementation of the use of a fatigue monitoring software program, and not be limited to 

only an anticipated update of the software program. The applicant further stated that the 

implementation of the fatigue monitoring software program involves not only installation of the 

fatigue monitoring software program, but also implementation of new and/or revised procedures. 

The staff reviewed the “scope of the program,” “preventive actions,” “parameters monitored or 

inspected,” “monitoring and trending,” and “acceptance criteria” program elements of GALL 

AMP X.M1, which recommends the preventive measures to mitigate fatigue cracking caused by 

anticipated cyclic strains in the material, maintaining the cumulative usage below the design 

limit of 1.0, and monitoring all plant transients that cause cyclic strains, which are significant 

contributors to the fatigue usage factor. The staff determined that Enhancement 2 and the 

implementation of the fatigue monitoring software program provide the applicant a tool to 

mitigate fatigue cracking caused by anticipated cyclic strains in the material, maintaining the 

cumulative usage below the design limit of 1.0, and monitoring 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.3.1.1-2 acceptable 

because the actions associated with Enhancement 2 are consistent with the recommendations 

of the “scope of the program,” “preventive actions,” “parameters monitored or inspected,” 

“monitoring and trending,” and “acceptance criteria” program elements of GALL AMP X.M1. 

Based on its review, the staff finds Enhancement 2 acceptable because it is consistent with the 

recommendations of the GALL Report, as described above in the staff’s evaluation of 

RAI B.3.1.1-2. 

Enhancement 3. LRA Section B.3.1.1 states an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” “monitoring and trending,” and “acceptance criteria” 

program elements. This enhancement addresses the effects of the reactor coolant environment 

on component fatigue life for a sample of critical components identified in NUREG/CR-6260. 

The applicant will implement this enhancement prior to the period of extended operation, as 

identified in Commitment No. 46, LRA Appendix A, Section A.5. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

AMP X.M1. The staff noted the applicant’s enhancement appropriately expands the existing 

program element to address the effects of the reactor coolant environment on component 

fatigue life. It was not evident to the staff whether this enhancement was being proposed to 

make the “preventive actions,” “parameters monitored or inspected,” and “acceptance criteria” 

program elements for the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

consistent with those in GALL AMP X.M1. The staff sought additional clarification on how this 

enhancement related to the acceptance criteria recommendation for environmental fatigue 

calculations in the “acceptance criteria” program element of GALL AMP X.M1. It was also not 

evident to the staff how this enhancement related to the “preventive actions” and “parameters 

monitored or inspected” program elements in GALL AMP X.M1. 
Aging Management Review Results 

 3-155 

On June 30, 2010, the staff issued RAI B.3.1.1-3 requesting that the applicant confirm the 

stated enhancement is being proposed to make the “preventive actions,” “parameters monitored 

or inspected,” “monitoring and trending,” and “acceptance criteria” program elements of the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program consistent with that in GALL 

AMP X.M1. The applicant was also requested to clarify how this enhancement relates to the 

acceptance criteria recommendation for environmental fatigue calculations in the “acceptance 

criteria” program element of GALL AMP X.M1 and with the aging management 

recommendations in the “preventive actions” and “parameters monitored or inspected” program 

elements in GALL AMP X.M1. 

In its response dated July 26, 2010, the applicant stated that Enhancement 3 is being proposed 

to make the “preventive actions,” “parameters monitored or inspected,” “monitoring and 

trending,” and “acceptance criteria” program elements its program consistent with that in GALL 

AMP X.M1. The applicant stated that Enhancement 3 provides an additional acceptance 

criterion to the existing Metal Fatigue Reactor Coolant Pressure Boundary Program to maintain 

the fatigue usage factor below the design code limit using the fatigue life correction factors 

developed to assess the impact of environmental fatigue. The staff reviewed the corresponding 

program element of GALL AMP X.M1 and noted the recommendation includes maintaining the 

fatigue usage below the design code limit considering environmental fatigue effects. The staff 

finds that the applicant’s Enhancement 3 is consistent with the recommendations to the 

“acceptance criteria” program element of GALL AMP X.M1. The applicant stated that 

Enhancement 3 relates to recommendations in the “preventive actions” program element in 

GALL AMP X.M1 by considering the effects of the reactor coolant environment on the 

component fatigue life. The staff reviewed the corresponding program element of GALL 

AMP X.M1 and noted the recommendation includes consideration of the effect of the reactor 

water environment on fatigue cracking of RCS components due to anticipated cyclic strains. 

The staff finds that the applicant’s Enhancement 3 is consistent with the recommendations to 

the “preventive actions” program element of GALL AMP X.M1. The applicant stated that 

Enhancement 3 relates to recommendations in the “parameters monitored or inspected” and 

“monitoring and trending” program elements in GALL AMP X.M1 by adding the monitoring of a 

sample of critical components for the plant identified in NUREG/CR-6260. The staff reviewed 

the corresponding program element of GALL AMP X.M1 and noted the recommendation 

includes monitoring transients that cause significant fatigue usage, a sample of critical RCPB 

components is to be monitored, and the sample includes locations identified in 

NUREG/CR-6260, as a minimum. The staff finds that the applicant’s Enhancement 3 is 

consistent with the recommendations to the “parameters monitored or inspected” and 

“monitoring and trending” program elements of GALL AMP X.M1. 

Based on its review, the staff finds the applicant’s response to RAI B.3.1.1-3 acceptable 

because the applicant described in detail how Enhancement 3 is consistent with the 

recommendations from the corresponding program elements of GALL AMP X.M1, and the staff 

confirmed that Enhancement 3 is consistent with the GALL Report. 

Based on its review, the staff finds Enhancement 3 acceptable because it is consistent with the 

recommendations of the GALL Report, as described above in the staff’s evaluation of 

RAI B.3.1.1-3. 

Enhancement 4. LRA Section B.3.1.1 states an enhancement to the “corrective actions” 

program element. This enhancement to the existing program element addresses the expanded 

review of RCPB locations if the usage factor for one of the environmental fatigue sample 

locations approaches its design limit. 
Aging Management Review Results 

 3-156 

During the review, it was not evident to the staff whether the stated enhancement was being 

made to make the “corrective actions” program element of the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program consistent with the corresponding program element in GALL 

AMP X.M1. It was also not evident to the staff exactly what is being enhanced relative to the 

information that has been submitted for the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program and specifically, whether the enhancement would involve an enhancement 

of the “basis document or procedure” for this AMP or the implementing procedure for this AMP, 

or both. 

On June 30, 2010, the staff issued RAI B.3.1.1-4 requesting that the applicant confirm the 

stated enhancement is being proposed to make the “corrective actions” program element of the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program consistent with that in GALL 

AMP X.M1. The applicant was also requested to clarify what will be enhanced (e.g., basis 

document, implementing procedure, etc.) relative to Enhancement 4 of the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program. 

In its response to RAI B.3.1.1-4 dated July 26, 2010, the applicant stated that Enhancement 4 is 

being proposed to make the “corrective actions” program element of its program consistent with 

that in GALL AMP X.M1. The applicant further stated that the implementing procedures will be 

revised to include the review of additional RCPB locations, if the usage factor for one of the 

environmental fatigue sample locations approaches its design limit, but will not involve updating 

the basis document. The staff reviewed the “corrective actions” program element of GALL 

AMP X.M1, which states that for programs that monitor a sample of high fatigue usage 

locations, corrective actions include a review of additional affected RCPB. The staff finds the 

applicant’s proposed Enhancement 4 consistent with the recommendations of the 

corresponding program element of GALL AMP X.M1. 

Based on its review, the staff finds the applicant’s response to RAI B.3.1.1-4 acceptable 

because the applicant’s proposed Enhancement 4 includes a sample expansion of additional 

RCPB locations if the usage factor for one of the environmental fatigue sample locations 

approaches its design limit as part of its corrective actions, consistent with the 

recommendations of the GALL Report. 

Based on its review, the staff finds Enhancement 4 acceptable because it is consistent with the 

recommendations of the GALL Report, as described above in the staff’s evaluation of 

RAI B.3.1.1-4 

Based on its audit and review of the applicant’s responses to RAIs B.3.1.1-1 through B.3.1.1-4, 

the staff finds that elements one through seven of the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program, with acceptable enhancements, are consistent with the 

corresponding program elements of GALL AMP X.M1 and, therefore, acceptable. 

Operating Experience. LRA Section B.3.1.1 summarizes operating experience related to the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant stated that the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program is responsive to industry and 

plant-specific emerging issues. To support this statement, the applicant listed examples 

pertaining to ECCS actuation experienced in May 2007, an HPCI event experienced in 

October 2004, and evaluation of the 2006 annual review of plant transients that indicated the 

possibility of the heat-up and cool-down transient exceeding the 40-year lifetime ratio if the 

current trend of transients would continue. 
Aging Management Review Results 

 3-157 

The staff noted that, as a result of an HPCI event that occurred in October 2004, the applicant 

indicated that the cumulative number of HPCI event cycles would exceed the applicant’s 

number of cycles assumed for this transient in the design basis. The staff also noted that the 

applicant considers this HPCI event to fall within the scope of a previously non-monitored ECCS 

injection event, and that the applicant’s corrective action was to evaluate this event and to 

include ECCS HPCI transient events within the scope of the applicant’s cycle counting 

procedure. The staff also noted that, as a result of ECCS HPCI actuation experienced in 

May 2007, a corrective action was invoked and the applicant updated the fatigue usage analysis 

for the core spray nozzle. 

By letter dated June 30, 2010, the staff issued RAI 4.3-03 requesting that the applicant explain 

and justify why the LRA lists two different 60-year projected CUF values for the core spray 

nozzles. The staff also requested that the applicant identify and justify which 60-year 

non-environmental effects CUF value should be used for the core spray nozzles in LRA 

Tables 4.3.1-2 and 4.3.5-1. Furthermore, identify the assumptions that were used to reduce the 

CUF for the core spray nozzle by a factor of 13 in the reanalysis of the component. 

In its response dated July 22, 2010, the applicant stated that the CUF values for the core spray 

nozzle (safe end/thermal sleeve and nozzle body) in LRA Table 4.3.1-2 were inadvertently not 

updated to reflect the final results of the calculation revision completed during preparation of the 

LRA. The applicant further stated that the updated final 60-year CUF values are 0.0202 and 

0.1063 for the core spray nozzle (safe end/thermal sleeve) and the core spray nozzle (nozzle 

body), respectively. The applicant stated the design-basis 60-year CUF values presented in 

LRA Table 4.3.5-1 for the core spray nozzle (safe end/thermal sleeve and nozzle body) are 

based on the final results of the revised calculation, which is the current design analysis record. 

The staff noted that the values presented in LRA Table 4.3.1-2 should be consistent with those 

presented in LRA Table 4.3.5-1 and, therefore, LRA Table 4.3.1-2 is revised. The staff finds the 

applicant’s revision to LRA Table 4.3.1-2 acceptable because it represents the final results of 

the calculation revision which represents the current design analysis record. 

The applicant also stated in its response that prior to the most recent calculations performed for 

60 years of operation for the core spray nozzle (safe end/thermal sleeve) in support of the LRA, 

the previous analyses performed to evaluate the October 2004 HPCI event used the original 

core spray nozzle safe end design. The applicant stated that the original safe end design used 

a threaded-in thermal sleeve, and the analysis applied a stress concentration factor of 5 at this 

location which resulted in the primary plus secondary stress intensity range significantly 

exceeding 3 Sm (three times the design stress intensity) and a resulting Ke (simplified 

elastic-plastic strain correction factor) value of 3.33. The applicant stated that this threaded 

location became the bounding location which was evaluated in subsequent analyses and the 

original analysis design-basis CUF value at the bounding location for 40 years was 0.796. The 

staff noted that this bounding location was evaluated in the October 2004 HPCI event using the 

original analysis, which resulted in a CUF value of 0.815. The staff also noted that this CUF 

value was calculated based on accumulated transients up to the date of the operating 

experience example. 

The applicant clarified that the safe end was replaced prior to initial plant operation, but this 

configuration change was not incorporated into the previous fatigue analyses. The applicant 

stated the new configuration was an integral safe end without threads which was included in the 

finite element model and used to perform the fatigue analysis to support the LRA. The applicant 

also stated that the fatigue analysis performed for the LRA considered the integral safe end as 

fabricated of Alloy 600 instead of stainless steel, with a stainless steel thermal sleeve welded to 
Aging Management Review Results 

 3-158 

the integral safe end, plus the addition of a new weld at the safe end to nozzle location. The 

staff noted that beyond the changes in safe end design and material, the fatigue analysis 

performed for the LRA also refined the transient parameters, as compared to the simplified 

transient parameters used in the original analysis. The staff further noted that these 

refinements included more detail with respect to time steps, nozzle and vessel temperatures 

and flows, and the use of actual lower flow rates associated with HPCI events when compared 

to flow rates shown in the thermal cycle diagram. The applicant stated that the thermal cycle 

diagram assumed all HPCI flow was injected through the core spray nozzle even though the 

system is designed to split the flow between the core spray and feedwater nozzles. The 

applicant also stated that the fatigue summary from the previous fatigue analyses shows that 

the alternating stress values for all transient load set pairs were multiplied by the K, multiplier of 

3.33, whereas only a few load set pairs in the current fatigue analysis are affected by Ke. The 

staff finds the reduction in CUF from the original fatigue analyses, compared to the fatigue 

analyses performed for the LRA, reasonable because the combination of the safe end design 

and material change, refinements with respect to time steps, nozzle and vessel temperatures 

and flows, and the use of actual lower flow rates associated with HPCI events and the 

application of Ke to the affected load set pairs would result in removal of some conservatism 

that was assumed in the original analysis. The staff noted that with regard to the nozzle body 

location, the original design-basis 40-year CUF was 0.071 and it did not experience a similar 

significant reduction in resultant calculated fatigue usage. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-03 acceptable because: 

(1) the applicant clarified the discrepancy between LRA Tables 4.3.1-2 and 4.3.5-1, and (2) the 

applicant’s reduction in CUF for the core spray nozzle (safe end/thermal sleeve) was 

reasonable based on the collective differences between design (geometry and material) and the 

refinement of transient parameters, as described above. 

The staff also noted that the applicant’s annual review in 2006 of past plant transient events 

indicated a possibility that the cumulative number of plant heat-up and cool-down transients 

would exceed the 40-year design-basis limit for the transients if the current trend of transients 

would continue. The staff noted the applicant evaluated this condition and indicated that the 

latest trend for these events is 3.5 heat-up transients per year and 3.5 cool-down transients per 

year, which is more frequent than the average trend of 3 heat-up transients per year and 3 

cool-down transients per year based on a 40-year life limit of 120 transients. The staff noted 

that the applicant concluded that the appropriate corrective action for its 2006 annual transient 

review was to continue monitoring the plant’s heat-up and cool-down transients in accordance 

with the cycle counting requirements of the program. 

To assess the appropriateness of this corrective action, the staff assessed the cumulative 

number of heat-up and cool-down cycles accumulated at the plant to date. The staff noted that, 

as of December 2007, the total number of heat-up cycles and cool-down cycles was 79, and 

that according to the TSs, each of these transients had a limiting design basis allowable of 120. 

The staff noted that in LRA Section 4.3, the applicant is dispositioning the CUF values for the 

ASME Code Class 1 components in accordance with the TLAA acceptance criterion in 

10 CFR 54.21(c)(1)(iii) and will manage the impact of fatigue-induced cracking on the intended 

functions of these components in accordance with the cycle counting and periodic CUF update 

provisions of this AMP. The staff also observed that the applicant still has a significant margin 

on cycle counting for the transients. 

Thus, based on this review, the staff concludes that the applicant has taken an acceptable 

corrective action and the program will be capable of managing the impact of fatigue-induced 
Aging Management Review Results 

 3-159 

cracking on the intended functions of the plant’s ASME Code Class 1 components using this 

program because: (1) the applicant is using the program to disposition the CUF-based TLAAs 

for these components in accordance with the TLAA acceptance criterion in 

10 CFR 54.21(c)(1)(iii); (2) the applicant’s program includes both cycle counting provisions and 

provisions to perform periodic updates of the CUF values for these components, which is 

consistent with the staff’s recommendations in the “parameters monitored or inspected” and 

“detection of aging effects” program elements in GALL AMP X.M1; and (3) there remains 

sufficient margin on cycle counts for the plant’s heat-up and cool-down transients at this time. 

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 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. LRA Section A.3.1.1 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 notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 4.3-2. The staff also notes that the applicant committed (Commitment No. 46), as 

amended by letter dated September 20, 2010, to enhance the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program prior to entering the period of extended operation. Specifically, the 

applicant committed to: (1) include additional transients beyond those defined in the TSs and 

the UFSAR, and expanding the fatigue monitoring program to encompass other components 

identified to have fatigue as an analyzed aging effect, which require monitoring; (2) use a 

software program to automatically count transients and calculate cumulative usage on select 

components, using cycle–based fatigue monitoring and if stress–based fatigue monitoring is 

used in the future, it will consider the six stress terms in accordance with the methodology from 

ASME Section III, Subsection NB, Subarticle NB-3200; (3) address 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 identified in NUREG/CR-6260; and 

(4) require a review of additional reactor coolant pressure boundary locations if the usage factor 

for one of the environmental fatigue sample locations approaches its design limit.. 

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). 
Aging Management Review Results 

 3-160 

Conclusion. On the basis of its audit and review of the applicant’s Metal Fatigue of Reactor 

Coolant Pressure Boundary Program, the staff determines that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. In addition, the 

staff reviewed the enhancements and confirmed that their implementation through Commitment 

No. 46 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). 

3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report 

In LRA Appendix B, the applicant identified the following AMPs that were not consistent with or 

not addressed by the GALL Report: 

● High Voltage Insulators 

● Periodic Inspection 

● Aboveground Non-Steel Tanks 

● Buried Non-Steel Piping Inspection 

● Boral Monitoring Program 

● Small-Bore Class 1 Piping Inspection 

For the AMPs that are not consistent with or not addressed by the GALL Report, the staff 

performed a complete review of the AMPs to determine whether they were adequate to monitor 

or manage aging. The staff’s review of these plant-specific AMPs is documented in the 

following section of this SER. 

3.0.3.3.1 High Voltage Insulators 

Summary of Technical Information in the Application. LRA Section B.2.2.1 describes the new 

High Voltage Insulators Program as plant-specific. The applicant stated that the High Voltage 

Insulators Program is a new condition monitoring program that manages the degradation of 

insulator quality at HCGS due to the presence of salt deposits or surface contamination. The 

scope of the program includes high-voltage insulators in the 500-kV switchyard, portions of the 

13.8-kV buses, and the 500-kV Salem-HCGS crosstie. The applicant also stated that High 

Voltage Insulators Program includes visual inspections to detect unacceptable indications of 

insulator surface contamination. The visual inspections will be performed on a twice per year 

frequency and will be effective in detecting the applicable aging effects, and the frequency of 

monitoring is adequate to prevent significant degradation. The applicant also stated that this 

program will be implemented prior to the period of extended operation so that the intended 

functions of components within the scope of license renewal will be maintained during the 

period of extended operation. 

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. 
Aging Management Review Results 

 3-161 

Scope of the Program. LRA Section B.2.2.1 states that the High Voltage Insulators Program is 

a new program that manages the aging effect of degradation of insulator quality. The scope of 

the program includes insulators in the 500-kV switchyard ring bus, portions of the 13.8-kV 

buses, and the 500-kV Salem-HCGS crosstie. The high-voltage insulators are those credited 

for supplying power to in-scope components for recovery of offsite power following an SBO. 

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 scope of the program should include the 

specific SCs of which the program manages aging. The staff determined that the specific 

commodity groups for which the program manages aging effects are identified (insulators in the 

500-kV switchyard ring bus, portions of the 13.8-kV buses, and the 500-kV Salem-HCGS 

crosstie for recovery of offsite power following an SBO), 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 and, therefore, the staff finds it acceptable. 

Preventive Actions. LRA Section B.2.2.1 states that the High Voltage Insulators Program is not 

a preventive or mitigation program. The High Voltage Insulators Program is a condition 

monitoring program that relies upon visual inspections of insulator surfaces in order to manage 

the degradation of insulator quality due to the presence of salt deposits or surface 

contamination. 

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 condition monitoring programs do not rely on 

preventive actions and thus, preventive actions need not be provided. The staff notes that this 

is a condition monitoring program and that there is no need for preventive actions, consistent 

with SRP-LR Section A.1.2.3.2. 

The staff confirmed that the “preventive actions” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable. 

Parameters Monitored or Inspected. LRA Section B.2.2.1 states that walkdowns are 

periodically conducted to visually inspect material conditions in the switchyards. Inspections of 

high-voltage insulators will be performed visually to determine a threshold for implementing 

corrective actions. These inspections will detect the presence and extent of any aging 

degradation due to the presence of salt deposits. The applicant also stated that porcelain 

insulators typically have a shiny surface; if the surface is dull, then contamination is present. 

Typically, heavy contamination will be apparent by the buildup at the base area of a vertical 

insulator. Similarly, for insulators in the dead-end horizontal configuration, significant drip marks 

are an indication that the location should be monitored. The applicant further stated that the 

most important area that signifies heavy contamination is when contamination is observed on 

the inside ridges on the underside of the porcelain bells. Evidence of salt deposits or surface 

contamination will be monitored and inspected to ensure high-voltage insulator intended 

function during the period of extended operation. 

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 parameter monitored or inspected should 

detect the presence and extent of aging effects. 
Aging Management Review Results 

 3-162 

The staff noted that salt deposits and surface contamination are the potential aging effects for 

high-voltage insulators and a buildup of contamination could enable the conductor voltage to 

track along the surface and can lead to insulator flashover. The staff determined that visual 

inspection is acceptable for detecting and managing the aging effects of salt deposits or surface 

contamination associated with high-voltage insulators and will ensure the component intended 

function during the period of extended operation. 

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable. 

Detection of Aging Effects. LRA Section B.2.2.1 states that system walkdowns in the 

switchyards are conducted periodically, and include a visual inspection of high-voltage insulator 

surface conditions in accordance with system engineering walkdown procedures. These 

walkdowns will continue into the period of extended operation, and will detect any aging 

degradation due to the presence of salt deposits or surface contamination. These inspections 

will be performed visually to determine a threshold for implementing corrective actions. 

The applicant stated that high-voltage insulators within the scope of this program are to be 

visually inspected at least twice per year. This is an adequate period to detect aging effects 

before a loss of component intended function since experience has shown that aging 

degradation is a slow process. The applicant also stated that a twice per year inspection 

interval will provide multiple data points during a 20-year period, which can be used to 

characterize the degradation rate. The buildup of surface contamination is typically a slow, 

gradual process that is even slower for rural areas with generally less suspended particles and 

contaminant concentrations in the air than urban areas. HCGS is located in a rural area, not 

near heavy industry that would provide a source for contaminants. The applicant further stated 

that there has only been one event associated with insulator contamination, which was not 

age-related or time-dependent. Therefore, operating history and plant location support a twice 

per year inspection frequency, which in turn provides reasonable assurance that the aging effect 

of degraded insulator quality will be detected prior to failure and loss of intended function. 

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 SC 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, and timing of 

inspection to ensure timely detection of aging effects. In addition, it states that the method or 

technique and frequency may be linked to plant-specific or industry-wide operating experience. 

The staff noted that the buildup of surface contamination is a slow, gradual process and HCGS 

is located in a rural area, not near heavy industry that would provide a source of contamination. 

There has been one event associated with insulator contamination. The plant-specific operating 

experience supports a twice per year inspection frequency. The staff determined that visual 

inspection is an acceptable technique for inspecting surface contamination of insulators and a 

twice per year inspection frequency is adequate to ensure timely detection of aging effects. 

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable. 

Monitoring and Trending. LRA Section B.2.2.1 states that monitoring activities will be 

prescribed by procedures that contain consistent qualitative criteria for insulator surface 
Aging Management Review Results 

 3-163 

contamination levels (e.g., slight, moderate, and heavy), and results will be documented 

providing a predictable extent of degradation. Visual techniques and a twice per year frequency 

are appropriate for monitoring high-voltage insulators and have been employed with success by 

transmission and distribution organizations. The applicant also stated that qualitative criteria for 

insulator surface contamination levels (e.g., slight, moderate, and heavy), will allow a 

predictable extent and rate of surface contamination degradation. The results will be trended, 

from inspection to inspection, providing a basis for timely corrective actions such as insulator 

cleaning/washing, prior to a loss of insulator intended function. 

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. This program element describes how the data collected 

are evaluated and may also include trending for a forward look. The parameter or indicator 

trended should be described. 

The staff determined that trending for insulator surface contamination levels (slight, moderate, 

and heavy) will be documented and will provide a predictable extent of degradation. The result 

will be trended from inspection to inspection and will provide a basis for timely corrective actions 

prior to a loss of intended functions. 

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable. 

Acceptance Criteria. LRA Section B.2.2.1 states visual inspection of high-voltage insulators will 

be prescribed by procedures that contain consistent qualitative criteria for insulator surface 

contamination levels (e.g., slight, moderate, and heavy), and the results will be documented 

providing a predictable extent of degradation. Inspection findings are to be within the 

acceptance criteria of these procedures, to ensure that high-voltage insulator intended function 

is maintained under all CLB design conditions during the period of extended operation. 

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 SC intended function(s) are maintained under all CLB 

design conditions during the period of extended operation. 

The staff determined that the applicant described acceptance criteria for insulator surface 

contamination level (e.g., slight, moderate, or heavy) in the plant procedures. Inspection 

findings are to be within the acceptance criteria of these procedures to ensure that high-voltage 

insulator intended function is maintained 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 and, therefore, the staff finds it acceptable. 

Operating Experience. LRA Section B.2.2.1 summarizes operating experience related to the 

high-voltage insulators. The applicant stated that industry operating experience illustrates the 

potential for loss of insulator quality due to salt deposits and surface contamination on 

switchyard insulators. The applicant also stated that demonstrating the new High Voltage 

Insulator Program will be effective is achieved through objective evidence that shows the aging 

effect of degradation of insulation quality caused by the presence of salt deposits and surface 

contamination is being adequately managed. The applicant further stated that the following 
Aging Management Review Results 

 3-164 

examples of operating experience provide objective evidence that the new High Voltage 

Insulators Program will be effective in assuring that the intended function will be maintained 

consistent with the CLB for the period of extended operation: 

 (1) In March 1993, Crystal River Unit 3 experienced a loss of the 230-kV switchyard (normal 

offsite power to safety-related buses) when a light rain caused arcing across salt-laden 

230-kV insulators and opened switchyard breakers. In March 1993, the Brunswick 

Steam Electric Plant Unit 2 switchyard experienced a flashover of some high-voltage 

insulators attributed to a winter storm. Since 1982, Pilgrim Nuclear Power Station 

experienced several losses of offsite power when ocean storms deposited salt on the 

345-kV switchyards, causing the insulator to arc to ground. The applicant further stated 

that in response to this industry experience, existing 6-month inspections of HCGS 

13-kV insulators were expanded to include the 500-kV insulators for salt contamination. 

The switchyard was inspected using thermography and corona detection equipment in 

the winter and summer of 2002, and no significant contamination buildup was found. 

The response and actions associated with this industry experience were revisited in 

2003 following the effects of Hurricane Isabel. Switchyard insulator inspections were 

instituted along with contingency planning for an insulator cleaning strategy. The 

applicant further stated that steps for initiating inspection of switchyard insulator surfaces 

were added to severe weather abnormal operating procedures upon forecast of severe 

weather. This example provides objective evidence that industry operating experience 

will be applied toward this new program, and corrective actions will be taken when the 

quality of insulator surfaces is threatened by storms and contamination. 

 (2) One plant-specific event occurred at HCGS on September 18–19, 2003, when Hurricane 

Isabel passed a considerable distance to the south and west of the site. Strong winds 

with gusts in excess of 60 miles per hour (mph) caused switchyard insulators to become 

coated with salt. The rain had stopped prior to the strongest winds, leaving the salt 

spray to dry on switchyard insulators. HCGS operated throughout the storm. The 

combination of salt on the insulator surface and atmospheric moisture subsequently 

caused a flashover. Another insulator flashover occurred shortly thereafter with no effect 

on plant operation. In response to the switchyard faults, HCGS was manually taken 

offline on September 20th. The high-voltage insulators were subsequently 

cleaned/washed prior to returning the units to operation. The applicant further stated 

that this event demonstrates that corrective actions are taken when high-voltage 

insulator degradation is found and, because this is the only high-voltage insulator-related 

event of record, flashover due to salt contamination of insulators at HCGS is considered 

rare. 

 (3) Visual inspection of HCGS switchyard high-voltage insulators is performed twice per 

year for evidence of salt and contamination. These inspections have been in place since 

1996 and have not found or observed degraded insulator quality other than “slight” 

surface contamination, even during periods of excessively dry weather, which would 

warrant cleaning or other corrective measures. This component history demonstrates 

that minor contamination is washed away by rainfall or snow, and cumulative buildup 

has not been experienced and is not expected to occur (with the exception of infrequent 

storms like Hurricane Isabel). Visual inspection results for high-voltage insulators are 

evaluated as part of transmission and distribution outage inspections, as well as 

switchyard system walkdowns. This example provides objective evidence that the aging 

effect of degraded insulation quality is capable of being detected, and that the 

mechanisms of salt deposit and surface contamination on high-voltage insulators will be 
Aging Management Review Results 

 3-165 

managed prior to loss of intended function. The applicant further stated that the HCGS 

operating experience for the High Voltage Insulators Program provides sufficient 

confidence that the implementation of the High Voltage Insulators Program will 

effectively identify degradation prior to failure. 

The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, which states that operating experience with the existing program 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 SC intended 

function(s) will be maintained during the period of extended operation. 

The staff finds that although the High Voltage Insulators Program is a new program with no 

operating experience for implementation, the applicant has captured insulator operating 

experience through reviewing industry operating experience and onsite documentation. The 

applicant reviewed industrial as well as plant-specific operating experience to provide the 

objective evidence that the new High Voltage Insulators Program will be effective in assuring 

that the intended function will be maintained consistent with the CLB for 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 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. 

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.2.2.1 provides the UFSAR supplement for the High 

Voltage Insulators Program. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.6-2. 

The staff notes that the applicant committed (Commitment No. 40) to implement the new High 

Voltage Insulators Program prior to entering 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 technical review of the applicant’s High Voltage Insulators 

Program, the staff concludes that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.3.2 Periodic Inspection 

Summary of Technical Information in the Application. LRA Section B.2.2.2 describes the new 

Periodic Inspection Program as a plant-specific program. The applicant stated that the Periodic 
Aging Management Review Results 

 3-166 

Inspection Program manages stainless steel, aluminum, and copper alloy components for loss 

of material, reduction of heat transfer, and elastomers for hardening and loss of strength. The 

applicant also stated that this program will manage cracking of the stainless steel standby diesel 

generator exhaust expansion joints. The applicant further stated that the program includes 

visual inspections and ultrasonic wall thickness measurements to detect loss of material. 

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. LRA Section B.2.2.2 states that the scope of the Periodic Inspection 

Program monitors aging effects in stainless steel, aluminum, copper alloy piping, piping 

components, piping elements, heat exchanger components, tanks and ducting components, and 

elastomers not included in other AMPs. 

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 scope of the program should include the 

specific SCs of which the program manages the aging. 

The staff concluded that the scope of the Periodic Inspection Program is consistent with the 

corresponding element of SRP-LR Section A.1.2.3.1 because it includes specific SCs for which 

it will manage aging during the period of extended operation. 

The staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.1 and, therefore, the staff finds it acceptable. 

Preventive Actions. LRA Section B.2.2.2 states that the Periodic Inspection Program is a 

condition monitoring program and does not include activities for prevention or mitigation of aging 

effects. 

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 and thus, this information need not be provided. 

The staff concluded that the “preventive actions” program element of the Periodic Inspection 

Program is consistent with the corresponding element of SRP-LR Section A.1.2.3.2 because the 

Periodic Inspection Program is a condition monitoring program and does not need to include 

preventive actions. 

The staff confirmed that the “preventive actions” program element satisfies the criteria defined in 

SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable. 

Parameters Monitored or Inspected. LRA Section B.2.2.2 states that the Periodic Inspection 

Program will detect loss of material in stainless steel, aluminum, and copper alloys, hardening 

and loss of strength in elastomers, cracking of standby diesel exhaust expansion joints, and the 

presence and extent of fouling that could result in reduction of heat transfer of heat transfer 

surfaces. The applicant also stated that the program includes provisions for visual inspections 

and ultrasonic wall thickness measurements to detect loss of material. 
Aging Management Review Results 

 3-167 

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 SC 

intended function(s). For a condition monitoring program, the parameter monitored or inspected 

should detect the presence and extent of aging effects. 

The staff concluded that the “parameters monitored or inspected” element of the Periodic 

Inspection Program is consistent with the corresponding element of SRP-LR Section A.1.2.3.3 

because the applicant identified and linked specific degradations to particular SCs, monitoring 

their condition through visual or volumetric inspections assuring that they can fulfill their 

intended functions. 

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable. 

Detection of Aging Effects. LRA Section B.2.2.2 states the Periodic Inspection Program will use 

visual inspections and ultrasonic wall thickness measurements to detect aging effects of 

components within the scope of this program prior to loss of their intended function. The 

applicant stated that the visual inspections will focus on: (1) loss of material in metals identified 

within the scope of the program; (2) cracking of standby diesel exhaust expansion joints; 

(3) fouling that could result in reduction of heat transfer in heat exchanger coils; (4) hardening 

and loss of strength in elastomers, where visual inspections may be augmented by physical 

manipulations. The applicant also stated that the visual inspections and ultrasonic 

measurements will be performed on a representative sample of components based on system 

operating conditions and plant operating experience and accessibility during their periodic 

disassembly. The applicant further stated that a 10-year inspection frequency is established 

based on plant and industry operating experience, which indicates that a 10-year inspection 

frequency will be adequate to detect loss of material prior to loss of the component’s intended 

function. 

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria for this element articulated in SRP-LR Section A.1.2.3.4, which states: (1) identify aging 

effects linked to SCs and monitor these before loss of their intended function(s); (2) monitor and 

inspect appropriate parameters; (3) designate inspection methods, techniques (i.e., visual, 

volumetric, surface inspection), their frequency, population criteria (i.e., similarity of materials of 

construction, fabrication, procurement, design, installation, operating environment, or aging 

effects), sample size (i.e., its basis and bias), data collection, and timing based on plant-specific 

or industry-wide operating experience; (4) maintain plant’s redundancy, diversity, and 

defense-in-depth consistent with the CLB; (5) describe “when,” “where,” and “how” program 

data is collected. 

The staff concluded that a 10-year inspection frequency is appropriately selected and 

established because it is based on plant-specific and industry operating experience. After 

further reviews and comparisons of the “detection of aging effects” program element in LRA 

Section B.2.2.2 with that of SRP-LR Section A.1.2.3.4, the staff determined that additional 

clarifications are needed to assess its consistency. This resulted in the issuance of RAIs. 

SRP-LR Appendix A, Section A1.2.3.4, states that the program element describes “when,” 

“where,” and “how” program data will be collected (i.e., all aspects of activities to collect data as 

part of the program). Element 4 of the LRA AMP states that the parameters monitored and 

inspected include visual inspection of component surfaces and ultrasonic wall thickness 
Aging Management Review Results 

 3-168 

measurements. However, it was not clear to the staff how these techniques would identify loss 

of material for aluminum components. By letter dated June 3, 2010, the staff issued 

RAI B.2.2.2-1 requesting that the applicant explain how visual inspections could identify aging 

effects in aluminum components. 

In its response dated June 30, 2010, the applicant stated that aluminum components included in 

the Periodic Inspection Program are subject to loss of material due to pitting and crevice 

corrosion and that it will use visual inspection for identifying loss of material on accessible 

component surfaces. The applicant also stated that focused visual inspections of aluminum 

components will identify surface pits or abnormal surface roughness, which will then be entered 

into the corrective action program. The staff finds the applicant’s response acceptable because 

visual inspection for surface pits or roughness is an acceptable technique for identifying loss of 

material due to pitting and crevice corrosion on aluminum components. The staff’s concern 

described in RAI B.2.2.2-1 is resolved. 

When the staff compared the LRA to SRP-LR Appendix A, Section A1.2.3.4 regarding the visual 

inspection and potential physical manipulation of elastomers for hardening and loss of strength, 

it was not clear to the staff: (1) what factors would come into play to determine the need to 

augment the visual inspections of elastomers with physical manipulations, (2) the characteristics 

assessed by the physical manipulations, and (3) how collected information would be quantified 

or otherwise used to assess component longevity. 

By letter dated June 3, 2010, the staff issued RAI B.2.2.2-2 requesting that the applicant clarify 

the process in determining a need for physical manipulation to assist visual inspections of 

elastomer components, clarify the characteristics assessed by physical manipulations, and how 

collected information would be quantified or otherwise be used to assess component longevity. 

In its response dated June 30, 2010, the applicant stated that elastomer components included in 

the Periodic Inspection Program are subject to the aging effect of hardening and loss of 

strength. The applicant stated that physical manipulation to assist in the detection of hardening 

and degradation is determined from the results of the initial visual inspection, which checks the 

material for cracking, flaking, shrinkage, swelling, or physical damage. The applicant stated that 

evidence of aging degradation will lead to that material being placed under the corrective action 

program. The staff finds the applicant’s response acceptable because the applicant has 

clarified that physical manipulation will be used to verify aging of elastomers if signs of 

degradation are present, which is an acceptable technique for determining if an elastomer is 

aging. The staff’s concern described in RAI B.2.2.2-2 is resolved. 

When the staff compared the LRA to SRP-LR Appendix A, Section A1.2.3.4 recommendations 

on sampling, it was unclear to the staff how the applicant defined its “representative sample,” 

population criteria, and population size. On August 18, 2010, the staff held a conference call 

with the applicant (ADAMS Accession No. ML102440706) to clarify the Periodic Inspection 

Program’s sampling methodology, including how the population for each of the 

material-environment-aging effect combinations is being selected, and what type of engineering, 

design, or operating experience considerations would be used to select the sample of 

components for both the scheduled and supplemental inspections. During this discussion, the 

applicant stated that the program will ensure that for each material, environment, and aging 

effect combination, the applicant will conduct representative inspections as directed by formal 

preventive maintenance or recurring tasks within the work management system. The applicant 

also stated that the intent is to use existing preventive maintenance or recurring task activities 

augmented with new recurring task activities to address inspection of material, environments, 
Aging Management Review Results 

 3-169 

and aging effects not adequately addressed by the current activities. The applicant further 

stated that if adverse conditions are identified, they will be entered into a corrective action 

program, discussed in the LRA, and appropriate actions will be directed including identifying and 

evaluating the cause and extent of the condition(s). The staff finds the applicant’s response 

acceptable and that the “detection of aging effects” program element is consistent with the 

corresponding element of SRP-LR Section A.1.2.3.4, because its “representative sample” will 

include inspections for each material, environment, and aging effect combinations and that 

when degradation is found, it will be entered in the corrective action program. 

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable. 

Monitoring and Trending. LRA Section B.2.2.2 states that the Periodic Inspection Program 

performs visual inspections for loss of material, loss of strength, hardening, cracking, and 

reduction of heat transfer for selected materials and components, described under the “scope of 

the program” program element, and ultrasonic wall thickness measurements to detect aging 

effects. The applicant also stated that these periodic inspections performed on population 

samples with frequencies based on industry and plant experience, can be effective in identifying 

the extent of component degradation prior to the loss of their intended function. The applicant 

further stated that identified degradations will be entered into the corrective action program to 

determine their impact on the component’s intended function, including any required repairs or 

subsequent monitoring and trending requirements. 

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Appendix A, Section A.1.2.3.5, which states that monitoring and trending 

activities should predict the extent of degradations to trigger timely corrective or mitigative 

actions. Plant-specific and industry-wide operating experience may be considered in evaluating 

appropriate techniques and frequencies. In addition, the program element should support 

quantification of aging indicators and parameters monitored to compare ongoing collected data 

for trending and future predictions. 

Following the reviews and comparisons between LRA Section B.2.2.2 “monitoring and trending” 

program element with that of the SRP-LR Section A.1.2.3.5, the staff concluded that the 

applicant’s proposed visual inspections and ultrasonic wall thickness measurements together 

with initiation of corrective actions would be able to determine the extent of degradation and 

provide timely corrective or mitigative actions, because the applicant: (1) is using techniques 

that would be able to determine the extent of degradation and (2) has satisfactorily described 

how the data will be collected and evaluated. 

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable. 

Acceptance Criteria. LRA Section B.2.2.2 states that the acceptance criteria are based on the 

following, for the given aging effect: (1) for loss of material, acceptance criteria are based on the 

original equipment design wall thickness minus allowances for corrosion and degradations; 

(2) for reduction of heat transfer, acceptance criteria are based on identification of fouling on the 

external heat transfer surfaces of cooling coils; (3) for standby diesel expansion joint cracking, 

acceptance criteria are based on preventing exhaust gas leakage that could impact engine 

operation; and (4) for hardening and loss of strength of elastomers, acceptance criteria are 

based on visual indications of degradation such as cracking, tears, or perforations in the 
Aging Management Review Results 

 3-170 

material, often augmented with physical manipulations to assure the material’s integrity or the 

need for its replacement. 

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 so that the need for corrective actions is evaluated. Acceptance criteria 

should be specific and quantifiable to ensure that the SC intended function(s) remain (including 

replacement) 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. 

The staff reviewed information presented in LRA Section B.2.2.2 relevant to the “acceptance 

criteria” program element of the Periodic Inspection Program. The staff determined that 

additional clarifications are needed to assess consistency of the “acceptance criteria” program 

element with the corresponding element of SRP-LR Section A.1.2.3.6, which resulted in the 

issuance of an RAI. 

SRP-LR Appendix A, Section A1.2.3.6 states that the acceptance criteria of the program and its 

basis should be described. The “acceptance criteria” program element of the Periodic 

Inspection Program states that acceptance criteria for loss of material are based on the original 

equipment design wall thickness and any corrosion allowance requirements. It is not clear to 

the staff what the acceptance criteria are for determining effects of aging on aluminum 

components. 

By letter dated June 3, 2010, the staff issued RAI B.2.2.2-3 requesting that the applicant clarify 

the acceptance criteria for determining effects of aging on aluminum components. 

In its response dated June 30, 2010, the applicant stated that focused visual inspection will 

identify any surface pitting or abnormal surface roughness and that any evidence of this type of 

degradation beyond minor surface corrosion is entered into the corrective action program for 

further evaluation by engineering staff. The applicant also stated that this engineering 

evaluation will determine acceptability for continued service with acceptance criteria based on 

the component’s design requirements and component intended functions. The applicant further 

stated that components that cannot be determined capable of performing their intended function 

are repaired or replaced. The staff finds the applicant’s response acceptable because the 

applicant has indicated the criteria against which the need for corrective actions will be 

evaluated. The staff’s concern described in RAI B.2.2.2-3 is resolved. 

The staff confirmed that the “acceptance criteria” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable. 

Operating Experience. LRA Section B.2.2.2 summarizes operating experience related to the 

Periodic Inspection Program. The applicant stated that the proposed Periodic Inspection 

Program will be effective in assuring that the intended functions of systems and components 

within the scope of the program will be maintained for the period of extended operation. To 

support this statement, the applicant provided several periodic visual inspection examples of: 

(1) stainless steel, aluminum, and copper alloy ventilation system components exposed to plant 

and outdoor air; (2) stainless steel piping exposed to external salt contamination from the 

Delaware River, following feedback from industry operating experience observations (INPO 

SEN 226, SCC on a portion of safety injection system piping); and (3) elastomer components in 

the technical support center’s ventilation fan. In the first and second examples, the applicant 
Aging Management Review Results 

 3-171 

stated that the results of the inspections were satisfactory and that no corrective actions were 

required. The third example led to a visual identification of a degraded elastomer prompting its 

subsequent repair. The applicant further stated that these examples demonstrate that these 

types of inspections performed by system owners are objective and adequate to evaluate the 

condition of the systems or components. 

The staff reviewed this information against the acceptance criteria in SRP-LR Appendix A, 

Section A.1.2.3.10, which states that operating experience of the AMP, including past corrective 

actions resulting in program enhancements or additional programs, should provide objective 

evidence to support the conclusion that the effects of aging will be adequately managed so that 

the SC intended function(s) will be maintained during the period of extended operation. 

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 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. LRA Section A.2.2.2 provides the UFSAR supplement for the Periodic 

Inspection Program. The staff reviewed this UFSAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.1-2. The staff also notes that the applicant committed (Commitment No. 41) to 

implement the new Periodic Inspection Program prior to entering the period of extended 

operation for managing aging of applicable components. 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 technical review of the applicant’s Periodic Inspection Program, 

the staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.3.3 Aboveground Non-Steel Tanks 

Summary of Technical Information in the Application. LRA Section B.2.2.3 describes the new 

Aboveground Non-Steel Tanks Program as plant-specific. The applicant stated that the 

program is used to manage the aging effect of loss of material on the external surfaces of 

aboveground non-steel tanks of which the condensate storage tank is the only component 

within scope. The applicant also stated that the program will apply visual inspections to the 

external tanks surfaces above their foundation interface, UT inspections of the tank bottom from 

inside the tank, and an inspection of the grout installed at the interface edge between the tank 

bottom and the concrete foundation. The staff notes that the applicant’s inspection procedures 

ensure that the caulk and sealant joint between the tank and foundation interface is visually 

inspected during the inspection of the tank. 
Aging Management Review Results 

 3-172 

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. LRA Section B.2.2.3 states that the Aboveground Non-Steel Tanks 

Program includes outdoor non-steel tanks of which the only one within the scope of license 

renewal is the condensate storage tank. The applicant stated that the program includes 

periodic visual inspections of the accessible tanks external surfaces, UT inspections of the tank 

bottom, and inspection of the grout installed at the interface edge between the tank bottom and 

concrete foundation. The applicant also stated that the tank vent bird screen will be visually 

inspected for loss of material. 

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 SCs for 

which the program manages aging. 

The staff reviewed the LRA and noted that the condensate storage tank and its associated tank 

vent bird screen are the only outdoor aboveground non-steel tanks and components being 

managed by this AMP. The staff also noted all the other non-steel tanks within the scope of 

license renewal are located indoors and are managed under different AMPs (e.g., Water 

Chemistry Program, Periodic Inspection Program, and Closed-Cycle Cooling Water System 

Program). Therefore, given that each of the other non-steel tank AMR line items will be 

evaluated during the review of the LRA, the staff determines the applicant’s scope of the 

program acceptable for 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 and, therefore, the staff finds it acceptable. 

Preventive Actions. LRA Section B.2.2.3 states that the program is a condition monitoring 

program and does not include activities for prevention or mitigation of aging effects. The 

applicant stated that the program includes periodic visual inspections including the grout 

installed at the interface edge between the tank bottom and concrete foundation, UT inspections 

of the tank bottom, and visual inspection of the tank vent bird screen for loss of material. The 

applicant also stated that a 5-year visual inspection frequency was established based on plant 

and industry operating experience, and provides reasonable assurance that significant aging 

effects will be detected and corrective actions taken prior to loss of component intended 

function. 

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 monitoring programs, preventive 

activities do not need to be included in the program. 

The staff reviewed the program and confirmed that for the materials (i.e., stainless steel and 

grout) and environments (i.e., air outdoor and soil) included, it is appropriate that this is a 

condition monitoring program without activities for corrosion mitigation or for corrosion 

prevention. Therefore, the staff determines the applicant’s preventive actions are appropriate 

for the AMP. 
Aging Management Review Results 

 3-173 

The staff confirmed that the “preventive actions” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable. 

Parameters Monitored or Inspected. LRA Section B.2.2.3 states that the program includes 

activities to detect the presence and extent of aging effects including general loss of material, 

pitting, and crevice corrosion. The applicant stated that the methods that monitor for those 

aging effects are visual inspection and UT. The applicant also stated that UT will quantitatively 

measure wall thickness of tank bottoms and focused visual inspections will detect significant 

loss of material due to pitting and crevice corrosion prior to loss of the tank intended function. 

The applicant also stated that the visual inspection will detect grout degradation that could allow 

water to get under the tank bottom. 

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 SC 

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 ultrasonic measurements and visual inspections is consistent 

with standard industrial practices and the parameters monitored in GALL AMP XI.M29, 

“Aboveground Steel Tanks,” and has been proven to be effective in detecting significant losses 

of material due to the corrosion effects covered in the applicant’s program. Therefore, the staff 

determines the parameters to be inspected by the applicant appropriate for the aging effects 

addressed. 

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable. 

Detection of Aging Effects. LRA Section B.2.2.3 states that the Aboveground Non-Steel Tanks 

Program will detect loss of material aging effects on the tank external surfaces before there is a 

loss of the tank intended function. The applicant stated that focused visual inspections will 

detect significant loss of material due to pitting and/or crevice corrosion prior to loss of the 

in-scope tank’s intended functionality. The applicant also stated that the UT method will be 

applied to the inside surfaces to inspect tank bottoms for thickness reduction due to corrosion. 

The applicant further stated that the visual inspection of the grout and sealant materials will be 

conducted to detect signs that water could potentially get under the tank bottom. The applicant 

stated that based on industry and plant-specific operating experience, the visual inspections will 

be conducted with 5-year intervals, and that the UT will be conducted prior to the period of 

extended operation. 

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 SC intended function(s). The criteria also states that parameters to 

be monitored or inspected should be appropriate to ensure that the SC 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 SC 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. 
Aging Management Review Results 

 3-174 

The staff confirmed that the use of the applicant’s methods are appropriate for detecting the 

aging effects covered in the program by comparing them to GALL AMP XI.M29, and that the 

combined use of visual inspections and UT provide sufficient detection methods to monitor 

corrosion effects prior to loss of the tank’s intended function. Therefore, the staff determines 

that the parameters being used to detect the aging effects are appropriate for the aging effects 

addressed. 

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable. 

Monitoring and Trending. LRA Section B.2.2.3 states that the program’s visual and ultrasonic 

examination inspections are based on industry and plant-specific operating experience. The 

applicant stated that wall thickness measurements will be compared to design requirements to 

determine if significant loss of material degradation is occurring. The applicant also stated that 

any significant corrosion detected as part of the inspections of this program will be entered into 

the corrective action program to determine the impact on the tank’s intended function, required 

repair, and further monitoring and trending requirements. 

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 should provide predictability of the extent of degradation and thus effect timely 

corrective or mitigative actions. The criteria also states that plant-specific and/or industry-wide 

operating experience 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. 

The staff considers the applicant’s coverage of this program element to be adequate because 

the applicant’s description of the program includes the application of corrosion monitoring and 

engineering analysis when corrosion is detected on in-scope components, which is consistent 

with the guidance in the SRP-LR. While the applicant’s program description did not specifically 

discuss predicting the rate of degradation, it did state that one aspect of the corrective action 

program is to further monitoring and trending requirements. The staff noted that the applicant’s 

monitoring methods are adequate to ensure that corrosion issues can be addressed prior to loss 

of component functionality because the applicant’s method of inspection and frequency of 

sampling is consistent with industry and plant-specific operating experience and GALL 

AMP XI.M29. Therefore, the staff determines that the parameters being monitored or trended 

are appropriate for the aging effects addressed. 

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable. 

Acceptance Criteria. LRA Section B.2.2.3 states that the acceptance criteria for the inspections 

that result in a quantitative value are the original equipment design wall thickness and corrosion 

allowance. The applicant stated that the acceptance criteria for visual inspections are 

qualitative unless indications of significant pitting, crevice corrosion, or other significant 

degradation are present which will result in an evaluation to quantify the material loss, which is 

then compared to the applicable design requirements. The applicant also stated that 
Aging Management Review Results 

 3-175 

inspections are performed by qualified personnel in accordance with approved station 

procedures. 

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 SC 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 SC 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. 

The staff considers 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, which is consistent with the guidance in the SRP-LR. The staff 

noted that the applicant’s program relies on established acceptance criteria, such as the original 

manufacturer’s specifications, including wall thickness for the specific component type and 

materials to be covered. The staff also noted that qualified personnel are used to perform 

inspections in accordance with approved plant procedures. Therefore, the staff determines 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 and, therefore, the staff finds it acceptable. 

Operating Experience. LRA Section B.2.2.3 summarizes operating experience related to the 

Aboveground Non-Steel Tanks Program. The applicant stated that based on industry operating 

experience, visual inspections were conducted to address the potential for accelerated 

corrosion due to salt contamination from the Delaware River. The applicant also stated that the 

inspections performed in 2005 and 2007 resulted in no indications of age-related degradation. 

The applicant further stated that maintenance history searches did not yield any evidence of 

age-related degradation. The applicant stated that the good physical condition of the in-scope 

tanks supports the sufficiency of the program’s intended frequency of 5 years between 

inspections. 

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 SCs are 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 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 Management Review Results 

 3-176 

aging on SCCs 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. LRA Section A.2.2.3 provides the UFSAR supplement for the 

Aboveground Non-Steel Tanks Program. 

The staff reviewed this UFSAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.4-2. The staff also notes that the applicant committed (Commitment No. 42) to 

implement the new Aboveground Non-Steel Tanks Program prior to entering the period of 

extended operation for managing aging of applicable components. 

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 technical review of the applicant’s Aboveground Non-Steel 

Tanks Program, the staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.3.4 Buried Non-Steel Piping Inspection 

Summary of Technical Information in the Application. LRA Section B.2.2.4 as supplemented by 

letter dated September 1, 2010, and October 29, 2010, describes the existing Buried Non-Steel 

Piping Inspection Program as a plant-specific program. The applicant stated that the Buried 

Non-Steel Piping Inspection Program is a condition monitoring program used to manage buried 

reinforced concrete piping and components in its service water system for cracking, loss of 

bond, increase in porosity and permeability, and loss of material. The Buried Non-Steel Piping 

Inspection Program also manages buried stainless steel piping and components in the 

condensate storage and transfer system and fire protection systems for loss of material. The 

applicant also stated that the program relies on visual inspections of the external surfaces of the 

piping and coatings conducted as part of opportunistic and focused excavations of buried, 

in-scope piping and components. The applicant further stated that areas with high susceptibility 

of exterior surface degradation, consequence of failure, and areas with a history of exterior 

surface degradation problems are prioritized for inspection. 

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. LRA Section B.2.2.4 states that the Buried Non-Steel Piping Inspection 

Program is an existing program that manages the aging effects of cracking, loss of bond, loss of 

material, and increased porosity and permeability. The applicant stated that the program 

manages non-steel buried piping and buried stainless steel piping and components within the 

service water system, condensate storage and transfer system, and fire protection system. 
Aging Management Review Results 

 3-177 

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 SCs for 

which the program manages aging. 

The staff reviewed the applicant’s program basis documents and LRA Sections 2.3 and 3.0. 

The staff determines 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. 

The staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.1 and, therefore, the staff finds it acceptable. 

Preventive Actions. LRA Section B.2.2.4 states that this program is a condition monitoring 

program that relies on opportunistic and focused inspections, and it is not a preventive or 

mitigative program. 

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 monitoring programs, preventive 

activities do not need to be included in the program. 

The staff reviewed the program and confirmed that it is a condition monitoring program without 

activities for corrosion mitigation or for corrosion prevention. 

The staff confirmed that the “preventive actions” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable. 

Parameters Monitored or Inspected. LRA Section B.2.2.4 states that the program includes 

opportunistic or focused inspections to detect the presence of cracking, loss of bond, increases 

in porosity and permeability, and loss of material for non-steel buried piping and components. 

The applicant stated that the inspections identify coating degradation if piping and components 

are coated and base material degradation if piping and components are uncoated. The 

applicant further stated that this program is not a performance monitoring program nor is it a 

preventive or mitigative program. 

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 SC 

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 inspection is consistent with standard industrial practices 

and GALL AMP XI.M34, “Buried Piping and Tanks Inspection,” and has been proven to be 

effective in detecting significant losses of material or coating degradation due to the aging 

effects covered in the applicant’s program. Therefore, the staff determines that the parameters 

to be inspected by the applicant are appropriate for the aging effects addressed. 

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable. 

Detection of Aging Effects. LRA Section B.2.2.4 states that the visual inspections to detect the 

aging effects being managed by this program will be in accordance with accepted industrial 

standards. The applicant stated that engineering evaluations will determine the need for 
Aging Management Review Results 

 3-178 

expanded inspection scope if initial inspection results are unacceptable. The applicant also 

stated that at least one opportunistic or focused inspection will be performed within 10 years 

prior to the period of extended operation and within the first 10 years of the period of extended 

operation. The applicant further stated that plant operating experience (i.e., no failures of buried 

non-steel piping due to external aging effects) supports this frequency of inspection. 

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 SC intended function(s). The criteria also states that parameters to 

be monitored or inspected should be appropriate to ensure that the SC 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 SC 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 are appropriate for detecting the 

aging effects covered in the program by comparing them to GALL AMP XI.M34, “Buried Piping 

and Tanks Inspection,” and that the use of visual inspections provides sufficient detection 

methods to monitor degradation of coatings and corrosion effects prior to loss of the buried 

non-steel piping intended function. Additionally, the program specifies the periodicity of the 

inspections, location of the inspections relative to the material type and risk ranking, and that the 

inspections will be performed by excavated direct inspection of the pipe. Therefore, the staff 

determines that the parameters being used to detect the aging effects are appropriate for the 

aging effects addressed. 

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.4 and, therefore, the staff finds it acceptable. 

Monitoring and Trending. LRA Section B.2.2.4 states that opportunistic and focused inspections 

are appropriate and adequate to detect aging effects prior to piping and component loss of 

intended function. The applicant stated that significant degradation identified by the visual 

inspections will be entered into the corrective action program and an engineering evaluation will 

quantify the results, which will either demonstrate acceptability or specify a repair or 

replacement. The applicant also stated that the engineering evaluations will determine the need 

for follow-up exams to monitor progression of degradation, ensuring that inspections will occur 

prior to loss of function. The applicant further stated that by trending the data, the engineering 

evaluation will determine if the sample size must be expanded to determine the extent of 

degradation or if the frequency of inspections is acceptable. 

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 and/or 

industry-wide operating experience 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 the timing of the next scheduled inspection will occur before 

a loss of SC intended function. 
Aging Management Review Results 

 3-179 

The staff considers the applicant’s coverage of this program element to be adequate because 

the applicant’s description of the program includes the application of engineering analysis and 

trending when corrosion is detected on in-scope components. The staff noted that the 

applicant’s monitoring and trending methods are adequate to ensure that corrosion issues can 

be addressed prior to loss of component functionality, and inspection frequencies will be 

adjusted by engineering evaluation if necessary based on inspection results. 

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable. 

Acceptance Criteria. LRA Section B.2.2.4 states that the acceptance criteria to be applied to 

the results of inspections are the applicable regulatory or industry requirements for the 

component being inspected. The applicant stated that the specific acceptance criteria relating 

to localized pipe wall thinning is contained in engineering documents, and is used in engineering 

evaluations of observed corrosion. The applicant also stated that the visual inspection process 

is qualitative, and in instances where significant corrosion is observed by visual inspection, 

additional evaluation will occur including quantifying material loss and comparing it to the 

applicable design requirements based on industry standards. The applicant further stated that 

inspections are performed by qualified personnel in accordance with approved procedures. 

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 SC 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 SC intended function(s) 

will be maintained under all CLB design conditions. Information from available references may 

be cited. The criteria also state 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 considers 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, it relies on established acceptance design based criteria for the 

specific component and materials to be covered, and it relies on standard industry practices. 

The staff also noted that qualified personnel are used to perform inspections in accordance with 

approved plant procedures. Therefore, the staff determines 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 and, therefore, the staff finds it acceptable. 

The staff notes that even though the Buried Non-Steel Piping Inspection Program is a 

plant-specific program, the applicant has demonstrated consistency with each of the program 

elements in GALL AMP XI.M34 except that the materials are non-steel (i.e., reinforced concrete, 

stainless steel) while the scope of GALL AMP XI.M34 includes only steel components 

(e.g., steel, gray cast iron, ductile cast iron). Based on recent industry operating experience, the 

staff requires further information related to the applicant’s plant-specific operating experience 

and the quality of backfill in the vicinity of buried pipe. The staff issued RAIs B.2.1.24 and 
Aging Management Review Results 

 3-180 

B.2.1.24-02 and their evaluations are documented in the “operating experience” program 

element. 

Operating Experience. LRA Section B.2.2.4 summarizes operating experience related to the 

Buried Non-Steel Piping Inspection Program. The applicant stated that the program has been 

effective as evidenced by the fact that there have been no underground leaks that developed as 

a result of failure of the external surface of buried stainless steel or reinforced concrete piping. 

The applicant also described an instance of operating experience that was related to a condition 

of internal surface degradation which provided an opportunistic external surface coating 

inspection of excavated piping which was observed to be intact and no corrosion was detected 

on the exterior pipe surface. 

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. 

Given that there have been a number of recent industry events involving leakage from buried or 

underground piping, the staff needed further information to evaluate the impact that these recent 

industry events might have on the applicant’s Buried Piping and Tanks Inspection Program. By 

letter dated August 6, 2010, the staff issued RAI B.2.1.24 requesting that the applicant provide 

information regarding how the applicant will incorporate the recent industry OE into its aging 

management reviews and programs. 

In its response dated September 1, 2010, the applicant stated that there have been no leaks of 

buried in-scope piping as a result of external corrosion. The applicant also stated that it has risk 

ranked all buried piping in accordance with NACE and EPRI guidelines and the NEI Industry 

Initiative on Buried Piping, and based on these risk rankings, inspections of the external 

surfaces of the pipe are scheduled and conducted. The applicant stated that it has committed 

to conduct excavated visual inspections of at least 8 linear feet of buried pipe, when practical, in 

each material group, which includes buried reinforced concrete piping and buried stainless steel 

piping, during each 10-year period, beginning 10 years prior to entry into the period of extended 

operation. 

Based on its review, the staff requested clarification on the applicant’s response. By letter dated 

October 12, 2010, the staff issued RAI B.2.1.24-02 requesting that the applicant: (a) define what 

is meant by excavating 8 feet of pipe when practical, state what alternative means will be 

utilized to determine the condition of the buried pipe, or justify why inspecting less than 8 feet is 

sufficient to provide a reasonable assurance of the condition of the pipe and coatings; (b) clarify 

if any in-scope buried pipe contains hazardous material and if applicable, state what percent of 

in-scope buried pipe containing hazardous material will be inspected; and (c) provide details on 

the quality of backfill in the vicinity of in-scope buried pipes. This was considered to be open 

item OI 3.0.3.2.12-1 during the issuance of the SER with open items. 

In its response dated October 29, 2010, the applicant stated that, in reviewing candidate 

inspection sites, it has determined that there is no need to have the phrase “when practical” in 

relation to examining 8 feet of pipe and the RAI response was subsequently revised accordingly 

to retract the words “when practical.” Therefore, the applicant concluded there is no need to 

provide alternative inspection details for less than 8-foot inspections. 
Aging Management Review Results 

 3-181 

Also, the applicant stated that the only buried in-scope piping containing tritium exceeding EPA 

drinking water limits is stainless steel piping that is cathodically protected in the condensate 

storage and transfer system. The applicant subsequently revised its commitment to specifically 

name the stainless steel piping in the condensate storage and transfer system to be inspected 

each 10-year period, starting 10 years prior to the period of extended operation, which will result 

in 3 percent of the piping being inspected each 10-year period. The total length of the line is 

approximately 250 linear feet. An 8-foot segment of one of these lines will be selected to fulfill 

the commitment to excavate and inspect a stainless steel pipe segment in each 10-year period. 

Finally, the applicant stated that buried piping was backfilled during original construction in 

accordance with construction backfill specifications. The applicant stated the construction 

backfill specifications as: 

Bedding material within six inches of the buried coated piping will consist of sand, 

or an approved well graded granular material free from stones greater than 3/8 

inches in diameter, or a lean fillcrete or sandcrete. The backfill requirements for 

the Service Water System pre-stressed concrete pipe were difference than 

requirements for coated metallic pipe since coating damage is not a concern. 

Bedding material for this piping (within 6 inches of the pipe) was required to be 

lean concrete or crushed stones not greater that 1 inch diameter. 

The buried pipe inspection procedures require that the condition of backfill and coatings be 

documented. Review of inspection records note that coatings were found in acceptable 

condition. 

Based on its review, the staff finds the applicant’s response to RAI B.2.1.24 and 

RAI B.2.1.24-02 acceptable because: (a) there have been no leaks of buried in-scope piping; 

(b) the applicant will excavate a minimum of 8 feet of pipe during each inspection; (c) at least 

one excavated visual inspection will be conducted on buried reinforced concrete piping and 

components during each 10-year period, beginning 10 years prior to entry into the period of 

extended operation; (d) 3 percent of the buried stainless steel piping containing tritium 

exceeding EPA drinking water limits will be inspected each 10-year period beginning 10 years 

prior to the period of extended operation; and (e) the applicant has appropriate backfill 

specifications and inspections have demonstrated that coatings are in acceptable condition. 

The staff’s concerns described in RAI B.2.1.24 and RAI B.2.1.24-02 are resolved. Open item 

OI 3.0.3.2.12-1 is closed. 

Based on its audit and review of the application, resolution to RAI B.2.1.24 and RAI B.2.1.24-02, 

and closure of open item OI 3.0.3.2.12-1, 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 

and, therefore, the staff finds it acceptable. 
Aging Management Review Results 

 3-182 

UFSAR Supplement. LRA Section A.2.2.4 provides the UFSAR supplement for the Buried 

Non-Steel Piping Inspection Program. The staff reviewed this UFSAR supplement description 

of the program and notes that it conforms to the recommended description for this type of 

program as described in SRP-LR Table 3.3-2. 

The staff also notes that the applicant committed (Commitment No. 43) to enhance the existing 

Buried Non-Steel Piping Inspection Program for managing aging of applicable components prior 

to the period of extended operation. Specifically, the applicant committed to include: 

1. At least one (1) opportunistic or focused excavation and inspection will be 

performed on buried reinforced concrete piping and components during 

each ten (10) year period, beginning ten (10) years prior to entry into the 

period of extended operation. 

2. At least one (1) opportunistic or focused excavation and inspection will be 

performed on Condensate Storage and Transfer System buried stainless 

steel piping and components, which contain fluid that exceeds EPA 

drinking water limits, during each ten (10 year period, beginning ten 

(10) years prior to entry into the period of extended operation. 

3. Guidance for inspection of concrete aging effects. 

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 technical review of the applicant’s Non-Steel Buried Piping 

Inspection Program, resolution to RAI B.2.1.24 and RAI B.2.1.24-02, and closure of open item 

OI 3.0.3.2.12-1, the staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.3.5 Boral Monitoring Program 

Summary of Technical Information in the Application. LRA Section B.2.2.5 describes the 

existing Boral Monitoring Program as a plant-specific program that monitors the Boral test 

coupon inspections and/or testing results at other BWR sites, and if the testing results indicate a 

problem with the function of the Boral (i.e., ability to absorb neutrons), HCGS will initiate 

inspection and/or testing of its Boral test coupons in the SFP. 

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. 

The staff reviewed information presented in LRA Section B.2.2.5 relevant to the “preventive 

actions,” “detection of aging effects,” and “monitoring and trending” program elements of the 

Boral Monitoring Program. The applicant stated, “The assumption is that the spent fuel pool 

environments, including the pool’s water chemistry and radiation field, and the Boral material 
Aging Management Review Results 

 3-183 

characteristics are consistent enough so that the results at other BWR sites are representative 

of the results if the Hope Creek Boral test coupons were inspected and/or tested. 

LR-ISG-2009-01, “Aging Management of Spent Fuel Pool Neutron-Absorbing Materials other 

than Boraflex,” cited specific examples of industry operating experience that have shown 

extrapolations on plant-specific data that were incorrect in trying to determine the future 

condition of neutron-absorbing material in SFPs. The staff clarified that an applicant should 

consider both plant-specific and industry operating experience in an LRA, and that the 

plant-specific operating experience should include data from an ongoing inspection and 

monitoring program.” The staff determined that additional clarifications was needed, which 

resulted in the issuance of an RAI. 

By letter dated April 14, 2010, the staff issued RAI 2.2.5-1 requesting that the applicant discuss 

its plan to implement changes to the Boral Monitoring Program that will include regular 

inspections of the SFP test coupons at HCGS. 

In its response dated May 11, 2010, the applicant stated that based on recent industry operating 

experience and issues outlined in LR-ISG-2009-01, the Boral Monitoring Program will be 

enhanced to include inspection, testing, and evaluation of one coupon prior to the period of 

extended operation and one coupon within the first 10 years after entering the period of 

extended operation. Testing will include dimensional and neutron attenuation measurements 

with an acceptance criteria of no more than a 10 percent increase in thickness and no more 

than a 5 percent decrease in Boron-10 areal density. 

The staff finds the applicant’s response acceptable because the applicant has committed to 

(Commitment No. 44) an enhancement of the existing program to implement prior to the period 

of extended operation an inspection, testing, and evaluation of one coupon from the SFP prior 

to the period of extended operation, and one coupon within the first 10 years after entering the 

period of extended operation. This verifies that there are no plant-specific conditions in the SFP 

that could degrade the capability of the Boral to absorb neutrons. Additionally, this 

enhancement aligns the Boral Monitoring Program with LR-ISG-2009-01, which states the 

applicant should demonstrate in its specific SFP environment, for its specific material(s), that 

degradation has not occurred in a manner that could adversely impact the material’s intended 

function. The staff’s concern described in RAI 2.2.5-1 is resolved. 

Scope of the Program. LRA Section B.2.2.5 states that the Boral Monitoring Program is an 

existing program that monitors the Boral test coupon inspection and/or testing results at other 

BWR sites. If these results indicate a problem with the Boral neutron-absorbing material 

potentially affecting its intended function (i.e., absorb neutrons), HCGS will initiate inspection 

and/or testing of its Boral test coupons in the SFP. The applicant stated that the scope will be 

enhanced to include inspection, testing, and evaluation of one coupon from the SFP prior to the 

period of extended operation, and one coupon within the first 10 years after entering the period 

of extended operation. Testing will include dimensional and neutron attenuation measurements. 

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 specific program necessary for license 

renewal should be identified, and the scope of the program should include the specific SCs that 

the program manages. 

The staff noted that the scope of the applicant’s Boral Monitoring Program appropriately 

identifies the specific program used and the components monitored by the program. In 
Aging Management Review Results 

 3-184 

response to RAI 2.2.5-1, the applicant expanded the scope of the program to include testing of 

one coupon prior to entering the period of extended operation and one coupon within the first 

10 years of entering the period of extended operation. This enhancement is appropriate 

because it verifies that there are no plant-specific conditions in the SFP that could degrade the 

capability of the Boral to absorb neutrons. Additionally, this enhancement aligns the Boral 

Monitoring Program with LR-ISG-2009-01, which states the applicant should demonstrate in its 

specific spent fuel pool environment, for its specific material(s), that degradation has not 

occurred in a manner that could adversely impact the material’s intended function. Therefore, 

the staff finds that the scope of the applicant’s Boral Monitoring Program satisfies the criteria 

defined in SRP-LR Section A.1.2.3.1 and is acceptable. 

Preventive Actions. LRA Section B.2.2.5 states that the Boral Monitoring Program is comprised 

of the AMPs at other BWR sites and as such, is a condition monitoring program and does not 

rely on 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 and thus, this information need not be provided. 

The staff noted the Boral Monitoring Program is a condition monitoring program and confirmed 

that the applicant’s AMP appropriately identifies the conditions that are monitored by the 

program. Therefore, the staff finds that the applicant’s Boral Monitoring Program satisfies the 

criterion defined in SRP-LR Section A.1.2.3.2 and is acceptable. 

Parameters Monitored or Inspected. LRA Section B.2.2.5 states that the Boral Monitoring 

Program includes Boral surveillance inspections performed by other BWRs, and includes visual 

inspections and/or testing of Boral test specimens or coupons to monitor changes in physical 

properties of the Boral in the SFP. The applicant also stated that examination of the Boral test 

coupon includes visual examination and photography, and may include dimensional 

measurements, weight and density/specific gravity measurement, and neutron attenuation 

measurement. The Boral test coupon is visually examined to detect aging affects such as 

corrosion, pitting, swelling, or other degradation. The Boral test coupon may be photographed 

if, in the judgment of the technician, there is any information of significance that should be 

photographically documented. Dimensional measurements such as length, width, and 

thickness are taken to document if physical changes are occurring in the Boral test coupon. 

The Boral test coupon is weighed and in some instances, the density and specific gravity is 

calculated to determine if there are any changes in the physical properties. A measurement by 

neutron attenuation is performed to determine if there has been any change in the Boron-10 

content. These inspections and/or testing are performed by a qualified contractor or 

measurement laboratory and will ensure against unexpected degradation of the Boral 

neutron-absorbing material. In response to RAI 2.2.5-1, the applicant enhanced the parameters 

monitored or inspected by adding that one coupon from the SFP will be inspected, tested, and 

evaluated prior to the period of extended operation and one coupon will be inspected, tested, 

and evaluated within the first 10 years after entering the period of extended operation. Testing 

will include dimensional and neutron attenuation measurements.

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 for a condition monitoring 

program, the parameter monitored or inspected should detect the presence and extent of aging 

effects. The enhancement provided by the applicant, in response to RAI B.2.2.5-1, provides 
Aging Management Review Results 

 3-185 

reasonable assurance that plant-specific conditions at HCGS will not allow Boral to degrade and 

go unnoticed in the SFP, and thereby compromise the Boral condition monitoring program. 

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable. 

Detection of Aging Effects. LRA Section B.2.2.5 states that the Boral surveillance performed by 

other BWR sites include visual inspections and/or testing of the Boral test specimens or 

coupons to monitor changes in physical properties of Boral. These Boral test coupons are in 

the SFP and subject to irradiated fuel assemblies to ensure that the Boral test coupons of the 

BWR sites are representative of their Boral in their SFP storage racks. Examination of the Boral 

test coupons include visual examination and photography, and may include dimensional 

measurements, weight and density/specific gravity measurement, and neutron attenuation 

measurement. A measurement by neutron attenuation is performed to determine if there has 

been any change in the Boron-10 content. In response to RAI 2.2.5-1, the applicant enhanced 

the parameters monitored or inspected by adding that one coupon from the SFP will be 

inspected, tested, and evaluated prior to the period of extended operation, and one coupon will 

be inspected, tested, and evaluated within the first 10 years after entering the period of 

extended operation. Testing will include dimensional and neutron attenuation measurements. 

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 SC intended function(s). The parameters to be monitored or 

inspected should be appropriate to ensure that the SC 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/one-time inspections to ensure timely detection of aging effects. 

The parameters to be monitored or inspected should be clearly linked to the aging effects being 

managed. The program element describes “when,” “where,” and “how” the data are collected. 

The method or technique and frequency may be linked to plant-specific or industry-wide 

operating experience, and when sampling is used, the basis for the inspection population and 

sample size should be provided. The sample size should be based on such aspects as the 

specific aging effect, location, existing technical information, system and structure design, 

materials of construction, service environment, or previous failure history. The samples should 

be biased toward locations most susceptible to the specific aging effect of concern in the period 

of extended operation. Provisions should also be included on expanding the sample size when 

degradation is detected in the initial sample. 

The applicant’s “detection of aging effects” program element uses many tests that assess the 

physical condition of the Boral test panels in the SFP. The enhancement provided by the 

applicant in response to RAI 2.2.5-1 is appropriate because it directly measures the loss of the 

key function (i.e., absorbing neutrons) that the Boral provides. The enhancement provides 

reasonable assurance that plant-specific conditions at HCGS will not allow Boral to degrade and 

go unnoticed in the SFP. The staff confirmed that the “detection of aging effects” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.4 and, therefore, the staff finds 

it acceptable. 

Monitoring and Trending. LRA Section B.2.2.5 states that the Boral Monitoring Program 

monitors the Boral test coupon inspection or testing results at other BWR sites. If these results 

indicate a problem with the Boral neutron-absorbing material potentially affecting its intended 

function (i.e., absorb neutrons), HCGS will initiate inspection and/or testing of its Boral test 
Aging Management Review Results 

 3-186 

coupons in the SFP. The test results will be used to assess the condition of the Boral 

neutron-absorbing material used in the HCGS SFP storage racks. The test results will provide 

the information and data needed to perform trending for indication of a potential degradation 

that may impact the performance of the Boral neutron-absorbing material. A summary of test 

results received from other BWR Boral surveillance will be entered into the plant document 

retrieval system. If these results indicate a problem with the Boral neutron-absorbing material 

affecting its intended function (i.e., absorb neutrons), HCGS will initiate inspection and/or testing 

of its Boral test coupons. 

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. Plant-specific and/or industry-wide operating experience 

may be considered in evaluating the appropriateness of the technique and frequency. The 

methodology for analyzing the inspection or test results against the acceptance criteria should 

be described. The staff confirmed that the “monitoring and trending” program element satisfies 

the criterion defined in SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable. 

Acceptance Criteria. LRA Section B.2.2.5 states that the Boral Monitoring Program monitors 

the Boral test coupon inspection and/or testing at other BWR sites. HCGS will request test 

reports from the Boral surveillance programs of these other sites every 2 years for evaluation 

and trending. These surveillance programs have acceptance criteria that are focused on the 

type of inspection and/or testing that are performed within the surveillance program. The 

surveillance performed by other sites may include visual inspections and/or testing of the Boral 

test specimens or coupons. The surveillance programs performed by other sites vary from 

qualitative programs that perform visual inspections only, to quantitative programs that also 

perform dimensional measurements and testing of the Boron-10 content. 

The applicant also stated that the acceptance criteria used for the Boral is based on the type of 

test results that are obtained from the other site’s test reports. For sites that perform only a 

qualitative visual examination, the HCGS qualitative acceptance criteria will be based on those 

results. If the conclusion from another site’s test report indicates satisfactory results, no 

additional action is required but to document the receipt of that test report for trending. If the 

test report conclusion indicates performance less than satisfactory, the test report information 

will be entered into the corrective action program for further evaluation. The corrective action 

program will perform an evaluation to determine if the test results are acceptable or if further 

action is required, such as requesting additional previous or historical test results from the same 

site that can be used for correlating trends of the Boral performance. If, as a result of historical 

trending, these test results show a divergence or inconsistency that indicates potential 

degradation of the Boral’s performance, corrective actions will be initiated. This could trigger 

the requirement to retrieve one Boral test coupon from the HCGS SFP and initiate inspection 

and/or testing and evaluation. For those sites that perform quantitative coupon examinations, 

the quantitative acceptance criteria are: (1) the increase in thickness at any point should not 

exceed 10 percent of the initial thickness at that point, and (2) a decrease of no more than 

5 percent in Boron-10 content, as determined by neutron attenuation, is acceptable. If a site’s 

test report indicates satisfactory results, no additional action is required but to document the 

receipt of that test report for trending. If the test report indicates at least one of the two 

acceptance criteria is unsatisfactory, the test report information will be entered into the 

corrective action program for further evaluation. Additionally, this could trigger the requirement 

to retrieve one Boral test coupon from the SFP and initiate inspection, testing, and evaluation. 

The enhancement provided by the applicant in response to RAI 2.2.5-1 stated that the 
Aging Management Review Results 

 3-187 

acceptance criteria, for the dimensional and neutron attenuation measurements that are to be 

performed, include no more than a 10 percent increase in thickness and no more than a 

5 percent decrease in Boron-10 areal density. 

The staff reviewed information presented in LRA Section B.2.2.5 relevant to the “acceptance 

criteria” program element of the Boral Monitoring Program. The applicant stated: 

If the test report conclusion indicates at least one of the two acceptance criteria is 

unsatisfactory, the test report information will be entered into the Hope Creek 

corrective action program for further evaluation. Additionally, this could trigger 

the requirement to retrieve one Boral test coupon from the Hope Creek spent fuel 

pool and initiate inspection, testing, and evaluation in accordance with the Boral 

Monitoring Program. 

The staff determined that additional clarifications are needed, which resulted in the issuance of 

an RAI. 

By letter dated April 14, 2010, the staff issued RAI 2.2.5-2 requesting that the applicant describe 

the test results that would require an SFP test coupon to be retrieved, inspected, tested, and 

evaluated. 

In its response dated May 11, 2010, the applicant stated that the following situations from test 

results from another BWR would be entered into the corrective action program and the 

evaluation would verify the validity of the information, determine its applicability to HCGS, and 

evaluate the potential impact on the spent fuel rack criticality analysis: (1) test results do not 

meet acceptance criteria at the BWR from which the coupon came, (2) test results would not 

meet acceptance criteria at HCGS, (3) test results indicated a reduction in neutron-absorbing 

capability outside of the variation attributed to measurement uncertainty, (4) test results 

generate corrective actions involving Boral material condition at the BWR from which the 

coupon came, (5) test results may be outside of expectations for a single population with 

common characteristics. 

The applicant also stated that testing of HCGS Boral test coupons would be triggered if: (1) test 

results from other BWRs indicate a reduction in the neutron-absorbing capability of Boral that, if 

occurred at HCGS, could challenge the HCGS SFP criticality analysis; or (2) test results from 

other BWRs indicate a statistical variation impacting the intended function of Boral to absorb 

neutrons that is outside of the expectations for a single population with common characteristics. 

The staff finds the applicant’s response acceptable because the applicant has specifically 

described situations in the test results that would require an SFP test coupon to be retrieved, 

inspected, tested, and evaluated. The staff’s concern described in RAI 2.2.5-2 is resolved. 

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 and the acceptance criteria, against which the need for corrective actions 

will be evaluated, should ensure that the SC 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. SRP-LR 

Section A.1.2.3.6 also states that 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 SC intended function(s) will be maintained 

under all CLB design conditions. 
Aging Management Review Results 

 3-188 

The staff confirmed that the “acceptance criteria” program element satisfies the criteria defined 

in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable. 

Operating Experience. LRA Section B.2.2.5 summarizes operating experience related to the 

Boral Monitoring Program. The applicant provided the following examples of operating 

experience as objective evidence that the Boral Monitoring Program will be effective in assuring 

that intended function of the Boral in the SFP will be maintained consistent with the CLB for the 

period of extended operation: 

 (1) Trending recent test results from other BWR sites for the past 5 years demonstrates that 

the Boral neutron-absorbing material is performing satisfactorily and no significant 

degradations have been observed or documented. Industry operating experience was 

obtained from seven BWR sites for Boral test coupons. These seven test reports show 

no aging effect significantly impacting the intended function. Using the operating 

experience from existing Boral surveillance programs at these other BWR sites provides 

a technical basis to demonstrate that HCGS does not need to implement an inspection 

and/or testing surveillance program of its Boral test coupons. Below is a summary of the 

industry operating experience for these seven BWR sites: 

 These BWR plants submit their Boral test coupon(s) to a qualified vendor for inspection 

and testing in accordance with the vendor’s Boral surveillance program. The inspection 

and testing of these test coupon(s) generally involves visual observations and 

photography, dimensional measurements (length, width, and thickness), weight and 

density determinations, and neutron attenuation measurements. Additionally, most of 

the BWR plants included Boron-10 areal density measurements with the surveillance 

program. The vendor prepares a report documenting the inspection and testing results 

and submits the report to the BWR plant. The following summarizes the inspection and 

testing results from the various BWR plants: 

 The visual inspections of the coupon showed that with the exception of some localized 

pitting and some blistering of the aluminum skin of the coupons exposed to the SFP 

water, the condition of the coupons were as expected. It was noted that both the pitting 

and blistering were conditions of appearance and did not affect the function of the 

material. Within the accuracy of the measurements for the length, width, and thickness 

measurements, there were no significant changes from the initial pre-irradiated 

benchmarked measurements. The coupon showed a slight increase in weight and 

density that were within the expected accuracy of the measurements. The neutron 

attenuation test results showed that there was no loss of Boron-10 from the coupon. 

The conclusion from the inspection and tests results was that the Boral 

neutron-absorbing material in the spent fuel storage racks have retained their 

dimensional and neutron-absorption properties and are capable of continuing to perform 

their intended function to absorb neutrons. 

 The summary of the inspection and testing results for the seven BWR plants discussed 

above provides objective evidence that the use and trending of industry operating 

experience demonstrates that the Boral neutron-absorbing material will be capable of 

continuing to perform its intended function of absorbing neutrons. 

 (2) HCGS has had no fuel assembly or blade guide movement impacted by Boral 

deformation (e.g., swelling, blistering). Almost every cell of the SFP racks have been 

accessed except for those cells listed as “DO NOT USE.” Station procedure 

“Supplemental Hope Creek Special Nuclear Material and Core Component Storage 
Aging Management Review Results 

 3-189 

Information,” describes the SFP cells that are considered as “DO NOT USE” cells. Older 

fuel assemblies (i.e., early plant discharges) have been moved to support dry cask 

storage campaigns and thermal management requirements. There have been no 

problems experienced when either removing fuel assemblies from these cells or 

inserting other fuel assemblies into these cells. There are 15 cells on the “DO NOT 

USE” list due to high cell friction. These cells failed drag tests in 1989 (1 cell) and 1992 

(14 cells) soon after installation of the SFP racks and are thus not attributable to Boral 

deformation. The SFP racks were installed in multiple phases at HCGS. The other cells 

on this “DO NOT USE” list have interference problems (i.e., with hangers, equipment 

stored in the SFP, identification strips, the refueling bridge), have damage at the top of 

the cells, contain failed fuel assemblies, or contain other equipment (i.e., dummy 

bundle). There is one cell where the fuel assembly sits high in the cell, but this behavior 

has not been attributed to Boral deformation. Camera inspection did not show Boral 

swelling or blistering. Therefore, based on the actual usage of the SFP racks, HCGS 

has no problems with the Boral performance and there is reasonable assurance that the 

HCGS Boral performance is no different from the industry Boral performance. It is 

acceptable to continue to monitor industry Boral performance rather than perform 

inspections and/or testing of the HCGS Boral test coupons. 

The staff reviewed information presented in LRA Section B.2.2.5 relevant to the “operating 

experience” program element of the Boral Monitoring Program. The staff had concerns about 

the applicant’s conclusion that HCGS has had no fuel assembly or blade guide movement 

impacted by Boral deformation. The applicant also stated that almost every cell of the SFP 

racks have been accessed except for those cells listed as “DO NOT USE.” The staff 

determined that additional clarifications are needed, which resulted in the issuance of an RAI. 

By letter dated April 14, 2010, the staff issued RAI 2.2.5-3 requesting that the applicant provide 

the following regarding spent fuel racks: (1) if and how the racks are vented, (2) what constitutes 

a drag test, and (3) the basis for the conclusion that the 15 cells marked as “DO NOT USE” did 

not suffer from Boral deformation. 

In its response dated May 11, 2010, the applicant provided further explanation that: 

 (1) The HCGS SFP contains 22 high-density racks. These racks use Boral as the neutron 

absorber. The Boral sheets are vented and exposed to SFP water. Each Boral sheet is 

held in place against the cell wall by a stainless steel wrapper. The wrapper is not 

sealed around the Boral sheet. The wrapper is spot welded to the cell wall. All Boral 

test coupons are vented and exposed to the SFP water. The HCGS SFP contains one 

low-density rack. This rack is used to store control rods and defective fuel storage 

containers. It does not use any neutron absorbers. 

 (2) Drag testing is performed for two purposes: (a) to verify that the spent fuel rack cell was 

fabricated with the required dimensions and (b) to detect deformation in the walls of a 

spent fuel rack cell once the spent fuel racks are placed in service. Drag testing can be 

performed under dry or wet conditions. A drag test consists of lowering and then 

withdrawing a test gauge or dummy bundle while monitoring a load cell for elevated 

friction or drag. The acceptance criteria for the drag test is the maximum allowed 

change in the load cell reading from the nominal value. A drag test begins by lowering 

the test gauge or dummy bundle into the spent fuel rack cell while monitoring a load cell. 

A decrease in the load cell reading more than the acceptance criteria is a drag test 
Aging Management Review Results 

 3-190 

failure. If the test gauge of dummy bundle hangs up prior to full insertion, it is a drag test 

failure. The test gauge or dummy bundle is then withdrawn while monitoring the load 

cell reading. An increase in the load cell reading more than the acceptance criteria is a 

drag test failure. A test failure is entered into the corrective action program for 

evaluation. The evaluation could specify repairs, require additional testing, place 

restrictions on usage of the cell, or prevent usage of the cell. 

 (3) The 15 cells marked “DO NOT USE” failed dry drag tests that were performed as part of 

the post-fabrication testing of the associated spent fuel racks prior to their placement in 

the SFP. Following placement of the associated spent fuel racks in the SFP, wet drag 

testing was performed on these cells using a dummy bundle with a smaller crosssectional area than the test gauge used in the dry drag testing. This restriction limited 

the potential channel distortion of the fuel assembly stored in the cell and thus the need 

for additional clearance. Channel distortion is the process by which the fuel channel 

bows and bulges due to operation in the reactor core. Boral deformation is caused by 

the interaction between water and Boral. Since all 15 cells marked “DO NOT USE” 

failed dry drag test prior to exposure to water, the applicant stated that it is not plausible 

that the drag test failures were caused by Boral deformation. 

The staff finds the applicant’s response acceptable because the applicant provided further 

clarification to the conclusion that the 15 cells marked as “DO NOT USE” did not suffer from 

Boral deformation. The staff’s concern described in RAI 2.2.5-3 is resolved. 

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 SC 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 review of the application and the applicant’s responses to 

RAIs 2.2.5-1, 2.2.5-2, and 2.2.5-3, 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. LRA Section A.2.2.5 provides the UFSAR supplement for the Boral 

Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR 

Table 3.3-2. In response to RAIs 2.2.5-1, 2.2.5-2, and 2.2.5-3, the applicant revised the UFSAR 

supplement to include inspection and testing of an SFP test coupon prior to entering the period 

of extended operation and another test coupon within the first 10 years of entering the period of 
Aging Management Review Results 

 3-191 

extended operation. The staff also notes that the applicant committed (Commitment No. 44) to 

enhance the existing Boral Monitoring Program prior to entering the period of extended 

operation for managing aging of applicable components. The staff determines 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 technical review of the applicant’s amended Boral Monitoring 

Program, the staff concludes that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.3.6 Small-Bore Class 1 Piping Inspection 

Summary of Technical Information in the Application. LRA Section B.2.2.6 describes the new

Small-Bore Class 1 Piping Inspection Program as plant-specific. The applicant stated that the 

Small-Bore Class 1 Piping Inspection Program is a new program that will manage the aging 

effect of cracking in small-bore (greater than or equal to nominal pipe size (NPS) 1 and less 

than NPS 4) Class 1 piping through the use of a combination of volumetric examinations and 

visual inspections. The applicant further stated that this new program is comprised of the 

existing ASME Section XI ISI (risk informed-inservice inspection (RI-ISI)) program that performs 

volumetric and visual examinations for selected Class 1 small-bore butt welds and other 

selected small-bore socket welds, and a 100 percent inspection of all accessible Class 1 socket 

welds in the recirculation system using volumetric or other industry-approved techniques. 

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. LRA Section B.2.2.6 states that the scope of the Small-Bore Class 1 

Piping Inspection Program will include a 100 percent inspection of the accessible Class 1 socket 

welds in the recirculation system, as well as ongoing ASME Section XI ISI (RI-ISI) volumetric 

and visual examinations for selected Class 1 small-bore butt welds and other selected 

small-bore socket welds. The applicant further stated that the selected inspections include 

locations that are susceptible to cracking and that the program will include measures to verify 

that unacceptable cracking indications are not occurring in Class 1 small-bore piping. 

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 the specific program necessary for license renewal 

should be identified and the scope of the program should include the specific SCs of which the 

program manages the aging. The staff finds this element of the applicant’s Small-Bore Class 1 

Piping Inspection Program acceptable because the components to be managed by this program 

are clearly identified. 

The staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.1 and, therefore, the staff finds it acceptable. 
Aging Management Review Results 

 3-192 

Preventive Actions. LRA Section B.2.2.6 states the Small-Bore Class 1 Piping Inspection 

Program is a condition monitoring program and does not include activities for preventing or 

mitigating aging degradation, therefore, no guidance is provided on preventive or mitigative 

activities. 

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 and thus, additional information regarding this element 

does not need to be provided. The staff finds the applicant’s determination that no guidance for 

mitigative or preventive activities is required is acceptable because the applicant’s Small-Bore 

Class 1 Piping Inspection Program is a condition monitoring program where small-bore Class 1 

piping welds will be subjected to various inspection methods including volumetric inspection. 

The staff confirmed that the “preventive actions” program element satisfies the criterion defined 

in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable. 

Parameters Monitored or Inspected. LRA Section B.2.2.6 states that volumetric examinations, 

or other approved inspection techniques, will inspect 100 percent of all the accessible Class 1 

socket welds of the recirculation system to identify degrading welds, and other selected 

accessible socket welds and small-bore butt welds will be inspected to detect cracking caused 

by SCC, and thermal and mechanical loading. LRA Section B.2.2.6 further states that the 

aspects of program inspection techniques included in the RI-ISI program are based on the EPRI 

RI-ISI Topical Report, EPRI TR-112657, and ASME Code Case N-578-1; the inspections 

include locations that are the most susceptible to cracking. 

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which states that the parameters to be 

monitored or inspected should be identified and linked to the degradation of the particular SC 

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 finds the applicant’s “parameters monitored or inspected” program element acceptable 

because the program was developed to detect cracking due to SCC and thermal and 

mechanical loading of small-bore Class 1 piping, and volumetric inspection or other approved 

inspection techniques will be implemented to detect cracks in small-bore piping including full 

penetration welds and socket welds. 

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable. 

Detection of Aging Effects. LRA Section B.2.2.6 states that the Small-Bore Class 1 Piping 

Inspection Program detects aging effects before there is a loss of the SC intended functions, 

where the aspects of program inspection techniques are appropriate for detecting degrading 

welds caused by cracking due to SCC and thermal and mechanical loading. LRA 

Section B.2.2.6 further states all accessible Class 1 recirculation system small-bore socket 

welds are inspected for degraded conditions, as well as other selected small-bore socket and 

butt welds, as directed by the RI-ISI program requirements, where selected “high” risk and 

“medium” risk weld locations will be examined to detect cracking. 
Aging Management Review Results 

 3-193 

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: 

 (1) Detection of aging effects should occur before there is a loss of the SC intended 

function(s). The parameters to be monitored or inspected should be appropriate to 

ensure that the SC 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/one-time inspections to ensure timely detection of aging 

effects. Provide information that links the parameters to be monitored or inspected to 

the aging effects being managed. 

 (2) Nuclear power plants are licensed based on redundancy, diversity, and defense-in-depth 

principles. A degraded or failed component reduces the reliability of the system, 

challenges safety systems, and contributes to plant risk. Thus, the effects of aging on a 

structure or component should be managed to ensure its availability to perform its 

intended function(s) as designed when called upon. In this way, all system level 

intended function(s), including redundancy, diversity, and defense-in-depth consistent 

with the plant’s CLB, would be maintained for license renewal. A program based solely 

on detecting SC failure should not be considered as an effective AMP for license 

renewal. 

 (3) 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). 

 (4) The method or technique and frequency may be linked to plant-specific or industry-wide 

operating experience. Provide justification, including codes and standards referenced, 

that the technique and frequency are adequate to detect the aging effects before a loss 

of SC intended function. A program based solely on detecting SC failures is not 

considered an effective AMP. 

 (5) When sampling is used to inspect a group of SCs, provide the basis for the inspection 

population and sample size. The inspection population should be based on such 

aspects of the SCs as a similarity of materials of construction, fabrication, procurement, 

design, installation, operating environment, or aging effects. The sample size should be 

based on such aspects of the SCs as the specific aging effect, location, existing 

technical information, system and structure design, materials of construction, service 

environment, or previous failure history. The samples should be biased toward locations 

most susceptible to the specific aging effect of concern in the period of extended 

operation. Provisions should also be included on expanding the sample size when 

degradation is detected in the initial sample. 

In the “detection of aging effects” program element, the applicant stated that: 

 (1) Volumetric examination techniques will detect cracking before the Class 1 small-bore 

welds leak or fail thus preserving the piping intended function consistent with the CLB of 

the plant. 

 (2) Program data will be collected through the applicant’s ISI program which is augmented 

by the Small-Bore Class 1 Piping Inspection Program. 
Aging Management Review Results 

 3-194 

 (3) Sampling and population size is based on 100 percent of accessible socket welds in the 

recirculation system and selected “high” and “medium” risk socket and butt welds based 

on established risk-informed methods for other locations. 

The staff noted that the applicant plans to inspect 100 percent of the accessible Class 1 socket 

welds in the recirculation system. However, the weld population was not provided. It was not 

clear to the staff what percentage of ASME Code Class 1 socket welds will be inspected prior to 

the period of extended operation. In addition, the staff also noted that the applicant’s program 

only addresses Class 1 small-bore socket welds but did not adequately address volumetric 

examination of full penetration welds. Specifically, the applicant stated in its risk informed 

inservice inspection (RI-ISI) program that Class 1 small-bore full penetration welds were 

included in the population. However, the staff noted that based on its current RI-ISI program 

plan (ISI Program Plan – Third 10-Year Inspection Interval, December 12, 2007, ADAMS 

Accession No. ML0735403840), Class 1 small-bore full penetration welds will not be subject to 

volumetric examinations. In addition, the staff noted that the RI-ISI program is an approved 

relief request that is valid only for the current 10-year ISI interval. This relief request cannot be 

assumed to be approved in future ISI intervals. By letter dated December 9, 2010, the staff 

issued RAI B.2.2.6-01 requesting that the applicant: 

(a) Provide the total population of ASME Code Class 1 socket welds and full 

penetration welds at Hope Creek. 

(b) Explain and justify how the sampling methodology used by the RI-ISI 

program is appropriate and demonstrates adequate aging management 

of small-bore piping that is in scope for License Renewal, since no fullpenetration welds were identified per the RI-ISI program. 

(c) In lieu of the justification above, provide a sampling methodology for small 

bore full-penetration welds and socket welds consistent with the staff’s 

position on adequate sampling, described above. 

(d) Clarify and justify the inspections and sampling methodology for the small 

bore piping in the recirculation system since there is plant-specific 

operating experience of cracking. 

In its response dated December 15, 2010, the applicant provided supplemental information to its 

Small-Bore Class 1 Piping Inspection Program. Regarding Part (a) of RAI B.2.2.6-01, the 

applicant provided its Class 1 weld populations and stated that there are 250 socket welds and 

51 full penetration welds. Based on its review, the staff finds the applicant’s response to 

Part (a) of RAI B.2.2.6-01 acceptable because the subject weld populations were provided. 

Regarding Parts (b) and (c) of RAI B.2.2.6-01, the applicant stated that no small-bore full 

penetration welds were identified for inspection per the current RI-ISI program. The applicant 

stated that it will include small-bore full penetration welds in its Small-Bore Class 1 Piping 

Inspection Program. The applicant also provided inspection sampling of both socket welds and 

full penetration welds. Specifically, 25 full penetration welds (out of a population of 51 welds) 

and 25 socket welds (out of a population of 250 welds) will be inspected using a sampling 

methodology to select the most susceptible and risk-significant welds. The inspections will be 

performed within the 6-year period prior to the period of extended operation. The applicant has 

subsequently revised program elements 1, 3, and 4 to delete inspection of 100 percent of all the 

accessible Class 1 socket welds of the recirculation system and include inspection of 25 Class 1 
Aging Management Review Results 

 3-195 

small-bore socket welds and 25 Class 1 small-bore butt welds based on a sample methodology 

to select the most susceptible and risk-significant welds for inspection. 

The staff noted that the inspection sampling of both socket welds and full penetration welds is 

consistent with the sampling guidance, which is 10 percent of each weld type, in the “detection 

of aging effects” program element of GALL AMP XI.M35 and, therefore, the staff finds it 

acceptable. The staff finds the applicant’s inspection schedule is consistent with the 

recommendations in the “detection of aging effects” program element of GALL AMP XI.M35 for 

timely implementation of the small-bore piping inspections and is, therefore, acceptable. 

Regarding Part (d) of RAI B.2.2.6-01, the applicant stated that it experienced socket weld 

fatigue failures in the past in its recirculation system and has made design changes to address 

the vibration source as well as piping changes to reduce suseptiblity of vibration induced fatigue 

cracking. The applicant further stated that socket weld inspections would focus on the 

recirculation system as it represents some of the most susceptible and risk-significant socket 

welds. The staff finds the applicant’s proposal acceptable because the applicant’s inspection 

methodology will select the most susceptible and risk-significant socket welds. 

Based on its review, the staff finds the applicant’s response to RAI B.2.2.6-01 acceptable 

because the applicant’s program includes: (1) consistency with the recommendations of GALL 

AMP XI.M35, (2) volumetric examinations of both socket welds and full penetration welds, 

(3) sampling of 10 percent or more of the weld populations for each weld type, (4) inspection 

selection of the most susceptible and risk-significant welds, and (5) timely implementation of the 

inspections. The staff’s concern described in RAI B.2.2.6-01 is 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 and, therefore, the staff finds it acceptable. 

Monitoring and Trending. LRA Section B.2.2.6 states that the process for selecting inspection 

locations is based upon risk-significant components and structures. EPRI TR-112657 and 

ASME Code Case N-578-1 provide a robust selection process and inspection schedule and are 

founded on actual service experience with nuclear plant piping failure data. LRA 

Section B.2.2.6 further states that the frequency of the inspections will detect cracking and 

age-related degradation prior to loss of intended function, based on industry and plant-specific 

operating experience; a risk informed inspection schedule directs appropriate inspections to be 

performed on a timely basis and results of the inspections are evaluated in accordance with 

station corrective action procedures, which direct additional inspections as required. 

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; plant-specific and/or industry-wide operating experience 

may be considered in evaluating the appropriateness of the technique and frequency. SRP-LR 

Section A.1.2.3.5 also states that this program element describes “how” the data collected are 

evaluated and may also include trending for a forward look. 

The staff finds the applicant’s “monitoring and trending” program element acceptable because 

inspection frequency is based on industry standard methods and piping failure data and results 

of inspections will be evaluated in a timely manner such that appropriate corrective actions and 

additional inspections will be scheduled through the station corrective action program. 
Aging Management Review Results 

 3-196 

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable. 

Acceptance Criteria. LRA Section B.2.2.6 states that examinations that reveal flaws or relevant 

indications exceeding acceptance criteria may be acceptable by supplemental examinations, 

corrective measures, repair or replacement activities, or analytical evaluations in accordance 

with ASME Code Case N-578-1. LRA Section B.2.2.6 also states that the alternative criteria for 

additional examinations contained in ASME Code Case N-578-1 provide more guidance for 

examination method and categorization for parts to be examined, and the supplemental 

inspections performed on accessible recirculation system piping will be evaluated, reviewed, 

and dispositioned consistent with ASME Code Section XI requirements. 

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, and the acceptance criteria, against which the need for corrective actions 

will be evaluated, should ensure that the SC 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. SRP-LR 

Section A.1.2.3.6 also states that 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 SC intended function(s) will be maintained 

under all CLB design conditions. 

The staff finds the applicant’s “acceptance criteria” program element acceptable because 

specific acceptance criteria are cited which are in accordance with ASME Code Section XI 

requirements such that the piping intended functions will be maintained 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 and, therefore, the staff finds it acceptable. 

Operating Experience. LRA Section B.2.2.6 summarizes operating experience related to the 

Small-Bore Class 1 Piping Inspection Program. The applicant stated that the effects of aging 

are effectively managed through objective evidence that shows that aging effects and 

mechanisms are being adequately managed. The applicant provided numerous examples of 

cracking in ASME Code Class 1 small-bore piping. The staff noted that in each case, the 

applicant provided corrective actions to repair the cracks or replace the degraded piping with a 

modified design. 

The staff reviewed this information against the criteria in SRP-LR Section A.1.2.3.10, which 

states that 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. As a result of numerous cracking incidences, the applicant developed this 

plant-specific AMP in accordance with the recommendations in GALL AMP XI.M35, “One-Time 

Inspection of ASME Code Class 1 Small-Bore Piping,” where the applicant has scheduled 

additional volumetric examinations of ASME Code Class 1 small-bore piping consistent with 

ASME Code Section XI, Subsection IWB. 

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. 
Aging Management Review Results 

 3-197 

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 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. LRA Section A.2.2.6, as amended by letter dated December 15, 2010, 

provides the UFSAR supplement for the Small-Bore Class 1 Piping Inspection Program. The 

staff reviewed this UFSAR supplement description of the program and notes that it conforms to 

the recommended description for this type of program as described in SRP-LR Table 3.1-2. 

The UFSAR supplement specifically states: 

The Small-Bore Class 1 Piping Inspection program is a new program that will 

manage the aging effect of cracking in small-bore (greater than or equal to 

NPS 1 and less than NPS 4) Class 1 piping through the use of a combination of 

volumetric examinations and visual inspections. This new program is comprised 

of the existing ASME Section XI ISI (Risk Informed Inservice Inspection, RI-ISI) 

program that performs volumetric and visual examinations for selected Class 1 

small-bore butt welds and other selected small-bore socket welds, and 

supplemental inspections consisting of 25 Class 1 small-bore socket welds and 

25 Class 1 small-bore butt welds using volumetric or other industry approved 

techniques. The RI-ISI program provides a robust inspection selection process 

and is based upon the susceptibility to degradation and the consequences of a 

piping failure, which is founded on actual service experience with nuclear plant 

piping failure data. The RI-ISI program requires volumetric and VT-2 

examinations on a frequency and number determined by ASME Code Case 

N-578-1 and the Hope Creek ISI Program Plan. These ongoing inspections 

combined with supplemental inspections consisting of 25 Class 1 small-bore 

socket welds and 25 Class 1 small-bore butt welds using volumetric or other 

industry approved techniques and based on a sample methodology to select the 

most susceptible and risk-significant welds for inspection will be effective in 

identifying any age related or underlying deficiencies. Any deficiencies identified 

are evaluated under the corrective action program. 

The Small-Bore Class 1 Piping Inspection program will effectively manage the 

aging effect of cracking in small-bore (greater than or equal to NPS 1 and less 

than NPS 4) Class 1 piping by identifying and evaluating cracking prior to loss of 

intended function. 

This new program will be implemented prior to the period of extended operation, 

with the supplemental inspections performed within the six year period prior to 

the period of extended operation. 

The staff also notes that the applicant committed (Commitment No. 45) to implement the new 

Small-Bore Class 1 Piping Inspection Program prior to entering the period of extended 

operation, with the supplemental inspections performed within the 6-year period prior to the 

period of extended operation for managing aging of applicable components. 

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). 
Aging Management Review Results 

 3-198 

Conclusion. On the basis of its technical review of the applicant’s Small-Bore Class 1 Piping 

Inspection Program, the staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs 

3.0.4.1 Summary of Technical Information in Application 

In Appendix A, “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 actions, confirmation process, and administrative 

controls that are applied to the AMPs for both safety-related and nonsafety-related components. 

The HCGS quality assurance program (QAP) is used, which includes the elements of corrective 

actions, 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. LRA Appendix A, 

Section A.1.5 and Appendix B, Section B.1.3 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 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. Three of these ten attributes are associated with the QA 

activities of corrective action, confirmation process, and administrative controls. 

Table A.1-1, “Elements of an Aging Management Program for License Renewal,” of SRP-LR, 

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 
Aging Management Review Results 

 3-199 

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 

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 LRA Appendix A and Appendix B, and the 

associated implementing procedures. The purpose of this review was to ensure 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 its review, the staff finds that the descriptions of the AMPs and their associated quality 

attributes provided in LRA Appendix A, Section A.1.5 and Appendix B, Section B.1.3 are 

consistent with the staff’s position regarding QA for aging management. 

3.0.5 Conclusion 

On the basis of its review, the staff finds that the descriptions and applicability of the 

plant-specific AMPs and their associated quality attributes provided in LRA Appendix A, 

Section A.1.5 and Appendix B, Section B.1.3 are consistent with the staff’s position regarding 

QA for aging management. The staff concludes that the QA attributes (corrective action, 

confirmation process, and administrative control) of the applicant’s AMPs are consistent with 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-200 

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant 

Systems

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: 

● Nuclear Boiler Instrumentation 

● Reactor Internals 

● Reactor Pressure Vessel 

● Reactor Recirculation System 

3.1.1 Summary of Technical Information in the Application 

LRA Section 3.1 provides AMR results for the RCS, reactor vessel, and reactor vessel internals 

(RVI). 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, and RVI 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 whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the RCS, reactor vessel, and RVI 

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 conducted an onsite audit of AMPs to ensure the applicant’s claim that certain AMPs 

were consistent with the GALL Report. The purpose of this audit was to examine the applicant’s 

AMPs and related documentation and to verify the applicant’s claim of consistency with the 

corresponding GALL Report AMPs. The staff did not repeat its review of the matters described 

in the GALL Report. The staff’s evaluations of the AMPs are documented in SER Section 3.0.3. 

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 Sections 3.1.2.1 and 3.1.2.2. 

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. 

The review evaluated whether all plausible aging effects were identified and whether the aging 
Aging Management Review Results 

 3-201 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff’s evaluation are discussed in SER Section 3.1.2.3. 

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line items and the plant’s operating experience to 

verify the applicant’s claims. 

Table 3.1-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.1 and addressed in the GALL Report. 

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

Coolant System Components in the 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 TLAA Fatigue is a TLAA 

(See SER 

Section 3.1.2.2.1) 

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-alloy 

reactor vessel 

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 are to be 

addressed for 

Class 1 

components 

Yes TLAA Fatigue is a TLAA 

(See SER 

Section 3.1.2.2.1) 

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-alloy 

reactor coolant 

pressure boundary 

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 are to be 

addressed for 

Class 1 

components 

Yes TLAA Fatigue is a TLAA 

(See SER 

Section 3.1.2.2.1) 

Steel pump and valve 

closure bolting 

(3.1.1-4) 

Cumulative fatigue 

damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

check Code limits 

for allowable 

cycles (less than 

7,000 cycles) of 

thermal stress 

range 

Yes TLAA Fatigue is a TLAA 

(See SER 

Section 3.1.2.2.1) 
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 

Stainless steel and 

nickel-alloy RVI 

components 

(3.1.1-5) 

Cumulative fatigue 

damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

Yes TLAA Fatigue is a TLAA 

(See SER 

Section 3.1.2.2.1) 

Nickel-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 Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.1) 

Steel and stainless 

steel reactor coolant 

pressure boundary 

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 Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.1) 

Steel; stainless steel; 

and nickel-alloy 

reactor coolant 

pressure boundary 

piping, piping 

components, piping 

elements; flanges; 

nozzles and safe 

ends; pressurizer 

vessel shell heads 

and welds; heater 

sheaths and sleeves; 

penetrations; and 

thermal sleeves 

(3.1.1-8) 

Cumulative fatigue 

damage 

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.1) 
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 

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-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 are to be 

addressed for 

Class 1 

components 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.1) 

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-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 are to be 

addressed for 

Class 1 

components 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.1) 

Steel top head 

enclosure (without 

cladding) top head 

nozzles (vent, top 

head spray or RCIC, 

and spare) exposed 

to reactor coolant 

(3.1.1-11) 

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 3.1.2.2.2) 

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 Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.2) 

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 Water 

Chemistry and 

One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.1.2.2.2) 
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 

Stainless steel, 

nickel-alloy, and steel 

with nickel-alloy or 

stainless steel 

cladding reactor 

vessel flanges, 

nozzles, 

penetrations, safe 

ends, vessel shells, 

heads, and welds 

(3.1.1-14) 

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 3.1.2.2.2) 

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and 

nickel-alloy reactor 

coolant pressure 

boundary 

components exposed 

to reactor coolant 

(3.1.1-15) 

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 3.1.2.2.2) 

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 

Inservice 

Inspection (IWB, 

IWC, and IWD), 

and Water 

Chemistry and, for 

Westinghouse 

Model 44 and 

51 S/G, if general 

and pitting 

corrosion of the 

shell is known to 

exist, additional 

inspection 

procedures are to 

be developed. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.2) 

Steel (with or without 

stainless steel 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds 

(3.1.1-17) 

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement 

TLAA, evaluated in 

accordance with 

10 CFR 50, 

Appendix G, 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 Loss of fracture 

toughness is a 

TLAA (See SER 

Section 3.1.2.2.3) 
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 

Steel (with or without 

stainless steel 

cladding) reactor 

vessel 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 Reactor Vessel 

Surveillance 

Consistent with 

GALL Report 

(See SER 

Section 3.1.2.2.3) 

Stainless steel and 

nickel-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 ASME Section 

XI Inservice 

Inspection, 

Subsections 

IWB, IWC, and 

IWD; and Water 

Chemistry 

Consistent with 

GALL Report 

(See SER 

Section 3.1.2.2.4) 

Stainless steel 

isolation condenser 

components exposed 

to reactor coolant 

(3.1.1-20) 

Cracking due to 

SCC and IGSCC 

Inservice 

Inspection (IWB, 

IWC, and IWD), 

Water Chemistry, 

and plant-specific 

verification 

program 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.1.2.2.4) 

Reactor vessel shell 

fabricated of 

SA508-Cl 2 forgings 

clad with stainless 

steel using a 

high-heat-input 

welding process 

(3.1.1-21) 

Crack growth due 

to cyclic loading 

TLAA Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.5) 

Stainless steel and 

nickel-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: 

(1) participate in 

industry RVI aging 

programs, 

(2) implement 

applicable results, 

and (3) submit for 

NRC approval, 

> 24 months 

before the period 

of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.6) 
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 

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 Not applicable Not applicable to 

BWRs (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 Not applicable Not applicable to 

BWRs (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 

HCGS (See SER 

Section 3.1.2.2.8) 

Steel and stainless 

steel isolation 

condenser 

components exposed 

to reactor coolant 

(3.1.1-26) 

Cracking due to 

cyclic loading 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and plant-specific 

verification 

program 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.1.2.2.8) 

Stainless steel and 

nickel-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 

NRC approval, 

> 24 months 

before the period 

of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation. 

Yes Not applicable Not applicable to 

BWRs (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 Not applicable to 

BWRs (See SER 

Section 3.1.2.2.10)
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 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 BWR Vessel 

Internals 

Consistent with 

GALL Report 

(See SER 

Section 3.1.2.2.11)

Stainless steel RVI 

components 

(e.g., upper internals 

assembly, rod cluster 

control assembly 

(RCCA) guide tube 

assemblies, 

baffle/former 

assembly, lower 

internal assembly, 

shroud assemblies, 

plenum cover and 

plenum cylinder, 

upper grid assembly, 

control rod guide tube 

(CRGT) 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 

irradiation-assisted 

stress-corrosion 

cracking (IASCC) 

Water Chemistry 

and UFSAR 

supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs, 

(2) implement 

applicable results, 

and (3) submit for 

NRC approval, 

> 24 months 

before the period 

of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.12)

Nickel alloy and steel 

with nickel-alloy 

cladding piping, 

piping component, 

piping elements, 

penetrations, 

nozzles, safe ends, 

and welds (other than 

reactor vessel head); 

pressurizer heater 

sheaths, sleeves, 

diaphragm plate, 

manways and 

flanges; core support 

pads/core guide lugs 

(3.1.1-31) 

Cracking due to 

primary water 

stress-corrosion 

cracking (PWSCC) 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry and 

UFSAR 

supplement 

commitment to 

implement 

applicable plant 

commitments to: 

(1) NRC Orders, 

Bulletins, and GLs 

associated with 

nickel alloys and 

(2) staff-accepted 

industry 

guidelines. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.13)

Steel steam 

generator feedwater 

inlet ring and 

supports 

(3.1.1-32) 

Wall thinning due to 

flow-accelerated 

corrosion 

A plant-specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.14)
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 

Stainless steel and 

nickel-alloy RVI 

components 

(3.1.1-33) 

Changes in 

dimensions due to 

void swelling 

UFSAR 

supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs, 

(2) implement 

applicable results, 

and (3) submit for 

NRC approval, 

> 24 months 

before the period 

of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.15)

Stainless steel and 

nickel-alloy reactor 

CRD head 

penetration pressure 

housings 

(3.1.1-34) 

Cracking due to 

SCC and PWSCC 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry and for 

nickel alloy, 

comply with 

applicable NRC 

Orders and 

provide a 

commitment in the 

UFSAR 

supplement to 

implement 

applicable: 

(1) Bulletins and 

GLs and 

(2) staff-accepted 

industry 

guidelines. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.16)
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 with stainless 

steel or nickel-alloy 

cladding primary side 

components; steam 

generator upper and 

lower heads, 

tubesheets, and 

tube-to-tube sheet 

welds 

(3.1.1-35) 

Cracking due to 

SCC and PWSCC 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry and for 

nickel alloy, 

comply with 

applicable NRC 

Orders and 

provide a 

commitment in the 

UFSAR 

supplement to 

implement 

applicable: 

(1) Bulletins and 

GLs and 

(2) staff-accepted 

industry 

guidelines. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.16)

Nickel-alloy, stainless 

steel pressurizer 

spray head 

(3.1.1-36) 

Cracking due to 

SCC and PWSCC 

Water Chemistry 

and One-Time 

Inspection and for 

nickel-alloy welded 

spray heads, 

comply with 

applicable NRC 

Orders and 

provide a 

commitment in the 

UFSAR 

supplement to 

implement 

applicable: 

(1) Bulletins and 

GLs and 

(2) staff-accepted 

industry 

guidelines. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.16)
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 

Stainless steel and 

nickel-alloy RVI 

components 

(e.g., upper internals 

assembly, RCCA 

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: 

(1) participate in 

industry RVI aging 

programs, 

(2) implement 

applicable results, 

and (3) submit for 

NRC approval, 

> 24 months 

before the period 

of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.1.2.2.16)

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 Control Rod 

Drive Return Line 

Nozzle 

No BWR Control 

Rod Drive 

Return Line 

Nozzle 

Consistent with 

GALL Report 

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 BWR Feedwater 

Nozzle 

Consistent with 

GALL Report 

Stainless steel and 

nickel-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 BWR 

Penetrations 

and Water 

Chemistry 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-211 

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 

nickel-alloy piping, 

piping components, 

and piping elements 

≥ 4”NPS; nozzle safe 

ends and associated 

welds 

(3.1.1-41) 

Cracking due to 

SCC and IGSCC 

BWR Stress 

Corrosion 

Cracking and 

Water Chemistry 

No BWR Stress 

Corrosion 

Cracking and 

Water 

Chemistry 

ASME Section 

XI Inservice 

Inspection, 

Subsections 

IWB, IWC, and 

IWD 

Consistent with 

GALL Report 

(See SER 

Sections 3.1.2.1.4 

and 3.1.2.1.6) 

Stainless steel and 

nickel-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 BWR Vessel ID 

Attachment 

Welds and 

Water 

Chemistry 

Consistent with 

GALL Report 

Stainless steel fuel 

supports and CRD 

assemblies CRD 

housing exposed to 

reactor coolant 

(3.1.1-43) 

Cracking due to 

SCC and IGSCC 

BWR Vessel 

Internals and 

Water Chemistry 

No BWR Vessel 

Internals and 

Water 

Chemistry 

Consistent with 

GALL Report 

Stainless steel and 

nickel-alloy core 

shroud, core plate, 

core plate bolts, 

support structure, top 

guide, core spray 

lines, spargers, jet 

pump assemblies, 

CRD housing, 

nuclear 

instrumentation guide 

tubes 

(3.1.1-44) 

Cracking due to 

SCC, IGSCC, and 

IASCC 

BWR Vessel 

Internals and 

Water Chemistry 

No BWR Vessel 

Internals and 

Water 

Chemistry 

Consistent with 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant 

(3.1.1-45) 

Wall thinning due to 

flow-accelerated 

corrosion 

Flow-Accelerated 

Corrosion 

No Flow-Accelerate

d Corrosion 

Consistent with 

GALL Report 

Nickel-alloy core 

shroud and core plate 

access hole cover 

(mechanical covers) 

(3.1.1-46) 

Cracking due to 

SCC, IGSCC, and 

IASCC 

Inservice 

Inspection (IWB, 

IWC, and IWD), 

and Water 

Chemistry 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.1.2.1.1) 
Aging Management Review Results 

 3-212 

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 

nickel-alloy RVIs 

exposed to reactor 

coolant 

(3.1.1-47) 

Loss of material 

due to pitting and 

crevice corrosion 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry 

No BWR Vessel 

Internals and 

Water 

Chemistry 

Consistent with 

GALL Report 

(See SER 

Section 3.1.2.1.3) 

Steel and stainless 

steel Class 1 piping, 

fittings, and branch 

connections < NPS”4 

exposed to reactor 

coolant 

(3.1.1-48) 

Cracking due to 

SCC, IGSCC (for 

stainless steel 

only), and thermal 

and mechanical 

loading 

Inservice 

Inspection (IWB, 

IWC, and IWD), 

Water Chemistry, 

and One-Time 

Inspection of 

ASME Code 

Class 1 

Small-Bore Piping 

No ASME Section 

XI Inservice 

Inspection, 

Subsection IWB, 

IWC, and IWD; 

Water 

Chemistry; and 

Small-Bore 

Class 1 Piping 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.1.2.1.7) 

Nickel-alloy core 

shroud and core plate 

access hole cover 

(welded covers) 

(3.1.1-49) 

Cracking due to 

SCC, IGSCC, and 

IASCC 

Inservice 

Inspection (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 BWR Vessel 

Internals and 

Water 

Chemistry 

Consistent with 

GALL Report 

(See SER 

Section 3.1.2.1.2) 

High-strength 

low-alloy 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 Reactor Head 

Closure Studs 

Consistent with 

GALL Report 

CASS jet pump 

assembly castings; 

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 Thermal Aging 

and Neutron 

Irradiation 

Embrittlement of 

CASS 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-213 

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 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 

self-loosening 

Bolting Integrity No Bolting Integrity 

Inspection of 

Overhead 

Heavy Load and 

Light Load 

(Related to 

Refueling) 

Handling 

Systems 

Structures 

Monitoring 

Consistent with 

GALL Report 

(See SER 

Sections 3.1.2.1.5 

and 3.5.2.1.2) 

Steel piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water 

(3.1.1-53) 

Loss of material 

due to general, 

pitting, and crevice 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.1.2.1.1) 

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water 

(3.1.1-54) 

Loss of material 

due to pitting, 

crevice, and 

galvanic corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.1.2.1.1) 

CASS Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant > 250 °C 

(> 482 °F) 

(3.1.1-55) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

Inservice 

Inspection (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 Section 

XI Inservice 

Inspection, 

Subsections 

IWB, IWC, and 

IWD 

Consistent with 

GALL Report 

Copper alloy 

> 15% zinc (Zn) 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water 

(3.1.1-56) 

Loss of material 

due to selective 

leaching 

Selective Leaching 

of Materials 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.1.2.1.1) 
Aging Management Review Results 

 3-214 

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 

CASS Class 1 piping, 

piping components, 

and piping elements 

and CRD pressure 

housings exposed to 

reactor coolant 

> 250 °C (> 482 °F) 

(3.1.1-57) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

Thermal Aging 

Embrittlement of 

CASS 

No Not applicable Not applicable to 

HCGS (See SER 

Sections 3.1.2.1.1 

and 3.1.2.2.2) 

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 Not applicable Not applicable to 

BWRs 

Steel steam 

generator steam 

nozzle and safe end, 

feedwater nozzle and 

safe end, auxiliary 

feedwater (AFW) 

nozzles and safe 

ends exposed to 

secondary 

feedwater/steam 

(3.1.1-59) 

Wall thinning due to 

flow-accelerated 

corrosion 

Flow-Accelerated 

Corrosion 

No Not applicable Not applicable to 

BWRs 

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 

BWRs 

Stainless steel, steel 

pressurizer integral 

support exposed to 

air with metal 

temperature up to 

288 °C (550 °F) 

(3.1.1-61) 

Cracking due to 

cyclic loading 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

No Not applicable Not applicable to 

BWRs (See SER 

Section 3.3.2.1.10)

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 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

No Not applicable Not applicable to 

BWRs 
Aging Management Review Results 

 3-215 

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, stainless steel 

and nickel-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, lower grid 

assembly) 

(3.1.1-63) 

Loss of material 

due to wear 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

No Not applicable Not applicable to 

BWRs 

Stainless steel and 

steel with stainless 

steel or nickel-alloy 

cladding pressurizer 

components 

(3.1.1-64) 

Cracking due to 

SCC and PWSCC 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry 

No Not applicable Not applicable to 

BWRs 

Nickel-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 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry and 

Nickel-Alloy 

Penetration 

Nozzles Welded to 

the Upper Reactor 

Vessel Closure 

Heads of 

Pressurized Water 

Reactors 

No Not applicable Not applicable to 

BWRs 

Steel steam 

generator secondary 

manways and 

handholds 

(cover only) exposed 

to air with leaking 

secondary side water 

and/or steam 

(3.1.1-66) 

Loss of material 

due to erosion 

Inservice 

Inspection (IWB, 

IWC, and IWD) for 

Class 2 

components 

No Not applicable Not applicable to 

BWRs 

Steel with stainless 

steel or nickel-alloy 

cladding; or stainless 

steel pressurizer 

components exposed 

to reactor coolant 

(3.1.1-67) 

Cracking due to 

cyclic loading 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry 

No Not applicable Not applicable to 

BWRs 
Aging Management Review Results 

 3-216 

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 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry 

No Not applicable Not applicable to 

BWRs 

Stainless steel, 

nickel-alloy safety 

injection nozzles, 

safe ends, and 

associated welds and 

buttering exposed to 

reactor coolant 

(3.1.1-69) 

Cracking due to 

SCC and PWSCC 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

and Water 

Chemistry 

No Not applicable Not applicable to 

BWRs 

Stainless steel; steel 

with stainless steel 

cladding Class 1 

piping, fittings, and 

branch connections 

< NPS (nominal pipe 

size) 4” exposed to 

reactor coolant 

(3.1.1-70) 

Cracking due to 

SCC, and thermal 

and mechanical 

loading 

Inservice 

Inspection (IWB, 

IWC, and IWD), 

Water Chemistry, 

and One-Time 

Inspection of 

ASME Code 

Class 1 Small-bore 

Piping 

No Not applicable Not applicable to 

BWRs 

High-strength 

low-alloy 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 Not applicable Not applicable to 

BWRs 

Nickel-alloy steam 

generator tubes and 

sleeves exposed to 

secondary 

feedwater/steam 

(3.1.1-72) 

Cracking due to 

outside-diameter 

stress-corrosion 

cracking (ODSCC) 

and intergranular 

attack, and loss of 

material due to 

fretting and wear 

Steam Generator 

Tube Integrity and 

Water Chemistry 

No Not applicable Not applicable to 

BWRs 
Aging Management Review Results 

 3-217 

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 

Nickel-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 Not applicable Not applicable to 

BWRs 

Chrome plated steel, 

stainless steel, 

nickel-alloy steam 

generator 

anti-vibration 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 Not applicable Not applicable to 

BWRs 

Nickel-alloy 

once-through steam 

generator (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 

BWRs 

Steel steam 

generator tube 

support plate, 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 Not applicable Not applicable to 

BWRs 

Nickel-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 to 

BWRs 

Steel steam 

generator tube 

support lattice bars 

exposed to 

secondary 

feedwater/steam 

(3.1.1-78) 

Wall thinning due to 

flow-accelerated 

corrosion 

Steam Generator 

Tube Integrity and 

Water Chemistry 

No Not applicable Not applicable to 

BWRs 
Aging Management Review Results 

 3-218 

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 

Nickel-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; 

Water Chemistry 

and, 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 NRC 

Bulletin 88-02. 

No Not applicable Not applicable to 

BWRs 

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 to 

BWRs 

Nickel alloy or 

nickel-alloy clad 

steam generator 

divider plate exposed 

to reactor coolant 

(3.1.1-81) 

Cracking due to 

PWSCC 

Water Chemistry No Not applicable Not applicable to 

BWRs 

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 

BWRs 

Stainless steel, steel 

with nickel-alloy or 

stainless steel 

cladding, and 

nickel-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 Not applicable Not applicable to 

BWRs 
Aging Management Review Results 

 3-219 

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 

Nickel-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 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

No Not applicable Not applicable to 

BWRs 

Nickel-alloy piping, 

piping components, 

and piping elements 

exposed to air – 

indoor uncontrolled 

(external) 

(3.1.1-85) 

None None No None Consistent with 

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 

GALL Report 

Steel piping, piping 

components, and 

piping elements in 

concrete 

(3.1.1-87) 

None None No Not applicable Not applicable to 

HCGS (See SER 

Section 3.1.2.1.1) 

The staff’s review of the RCS component groups followed several approaches. One approach, 

documented in SER Section 3.1.2.1, discusses the staff’s review of AMR results for components 

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 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 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. 
Aging Management Review Results 

 3-220 

3.1.2.1 AMR 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 reactor vessel, RVIs, and RCS components: 

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

● Bolting Integrity Program 

● BWR Control Rod Drive Return Line Nozzle 

● BWR Feedwater Nozzle 

● BWR Penetrations 

● BWR Stress Corrosion Cracking 

● BWR Vessel ID Attachment Welds 

● BWR Vessel Internals 

● External Surfaces Monitoring 

● One-Time Inspection Program 

● Periodic Inspection 

● Reactor Head Closure Studs 

● Reactor Vessel Surveillance 

● Small-Bore Class 1 Piping Inspection 

● Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel 

(CASS) 

● TLAA 

● Water Chemistry Program 

LRA Tables 3.1.2-1 through 3.1.2-4 summarize the results of AMRs for the RCS, reactor vessel, 

and RVI components and indicate AMRs claimed to be consistent with the GALL Report. 

For component groups evaluated in the GALL Report for which the applicant had claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR line item describing how the information in the 

tables aligns with the information in the GALL Report. The staff reviewed those AMRs with 

Notes A through E, which indicate how the AMR was consistent with the GALL Report. 
Aging Management Review Results 

 3-221 

Note A indicates that the AMR line 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 line 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 line 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 line items to verify consistency 

with the GALL Report and 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 line 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 

line items to verify consistency with the GALL Report. The staff also determined whether the 

AMR line 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 line 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 line items 

to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of 

the different component was applicable to the component under review and whether the 

exceptions to the GALL Report AMPs had been 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 line item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff reviewed these line 

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 audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, it did verify that the material presented in 

the LRA was applicable and that the applicant had identified the appropriate GALL Report 

AMRs. The staff’s evaluation is discussed below. 

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the 

system, components, materials, and environments; (b) stated that the applicable aging effects 

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the 

RCS, reactor vessel, and RVI components that are subject to an AMR. 

On the basis of its audit and review, the staff determines that, for AMRs not requiring further 

evaluation, as identified in LRA Table 3.1.1, the applicant’s references to the GALL Report are 

acceptable and no further staff review is required. 
Aging Management Review Results 

 3-222 

3.1.2.1.1 AMR Results Identified as Not Applicable 

LRA Table 3.1.1, item 3.1.1-46 addresses nickel-alloy core shroud and core plate access hole 

cover (mechanical covers) exposed to reactor coolant subject cracking due to SCC, IGSCC, 

and IASCC for this component group. The applicant stated that this line item is not applicable 

because it has access hole covers that are of a welded design and not a mechanical (bolted) 

design. The applicant further stated that the access hole covers of a welded design are 

addressed under item 3.1.1-49. The staff confirmed that the applicant is managing the core 

shroud and core plate (access hole cover-welded covers) for cracking due to SCC, IGSCC, and 

IASCC with its BWR Vessel Internals Program and Water Chemistry Program. The staff noted 

that the applicant is managing the same aging effects that are addressed in item 3.1.1-46. 

Based on its review, the staff finds the applicant’s statement that item 3.1.1-46 is not applicable 

acceptable because the applicant: (1) addressed aging of these components in item 3.1.1-49 

and (2) is managing these components for the same aging effects addressed in item 3.1.1-49. 

LRA Table 3.1.1, item 3.1.1-53 addresses steel piping, piping components, and piping elements 

exposed to closed-cycle cooling water subject to loss of material due to general, pitting and 

crevice corrosion for this component group. The applicant stated that this line item is not 

applicable because it has no steel piping, piping components, or piping elements exposed to 

closed-cycle cooling water in nuclear boiler instrumentation, reactor internals, RPV, and the 

reactor recirculation system. The staff reviewed the applicant’s UFSAR and confirmed that no 

in-scope steel piping, piping components, and piping elements exposed to closed-cycle cooling 

water are present in these systems and, therefore, the staff finds the applicant’s determination 

acceptable. 

LRA Table 3.1.1, item 3.1.1-54 addresses copper alloy piping, piping components, and piping 

elements exposed to closed-cycle cooling water subject to loss of material due to pitting, 

crevice, and galvanic corrosion for this component group. The applicant stated that this line 

item is not applicable because it has no copper alloy piping, piping components, or piping 

elements exposed to closed-cycle cooling water in nuclear boiler instrumentation, reactor 

internals, RPV, and the reactor recirculation system. The staff reviewed the applicant’s UFSAR 

and confirmed that no in-scope copper alloy piping, piping components, and piping elements 

exposed to closed-cycle cooling water are present in these systems and, therefore, the staff 

finds the applicant’s determination acceptable. 

LRA Table 3.1.1, item 3.1.1-56 addresses copper alloy greater than 15 percent Zn piping, piping 

components, and piping elements exposed to closed-cycle cooling water subject to loss of 

material due to selective leaching for this component group. The applicant stated that this line 

item is not applicable because it has no copper alloy greater than 15 percent Zn piping, piping 

components, or piping elements exposed to closed-cycle cooling water in nuclear boiler 

instrumentation, reactor internals, RPV, and the reactor recirculation system. The staff 

reviewed the applicant’s UFSAR and confirmed that no in-scope copper alloy greater than 

15 percent Zn piping, piping components, and piping elements exposed to closed-cycle cooling 

water are present in these systems and, therefore, the staff finds the applicant’s determination 

acceptable. 

LRA Tables 3.1.1, item 3.1.1-57 addresses CASS Class 1 piping, piping components, and 

piping elements and CRD pressure housings exposed to reactor coolant greater than 250 °C 

(482 °F) subject to loss of fracture toughness due to thermal aging embrittlement for this 

component group. The applicant stated that this line item is not applicable because with the 

exception of the Class 1 pump casings and valve bodies, and reactor internals components, 
Aging Management Review Results 

 3-223 

there are no other CASS piping, piping components, or piping elements in nuclear boiler 

instrumentation, reactor internals, RPV, and the reactor recirculation system exposed to reactor 

coolant greater than 250 °C (482 °F) that require aging management for loss of fracture 

toughness due to thermal aging embrittlement. The applicant further stated that loss of fracture 

toughness due to thermal aging embrittlement in CASS Class 1 pump casings and valve bodies 

is addressed by item 3.1.1-55, and the loss of fracture toughness due to thermal aging and 

neutron irradiation embrittlement of CASS for the reactor internals components is addressed by 

item 3.1.1-51. The staff reviewed the applicant’s UFSAR and confirmed that no in-scope CASS 

Class 1 piping, piping components, and piping elements and CRD pressure housings exposed 

to reactor coolant greater than 250 °C (482 °F) are present in these systems and, therefore, the 

staff finds the applicant’s determination acceptable. 

The staff confirmed that for CASS Class 1 pump casings and valve bodies, the applicant is 

managing loss of fracture toughness due to thermal aging embrittlement, addressed under 

item 3.1.1-55, with its ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program, consistent with the recommendations of the GALL Report. The staff also confirmed 

that for CASS RVIs, the applicant is managing loss of fracture toughness due to thermal aging 

and neutron irradiation embrittlement, addressed under item 3.1.1-51, with its Thermal Aging 

and Neutron Irradiation Embrittlement of CASS Program, consistent with the recommendations 

of the GALL Report. Based on its review, the staff finds the applicant’s proposed program to 

manage CASS Class 1 pump casings, valve bodies, and RVIs acceptable because it is 

consistent with the recommendations of the GALL Report. 

The applicant further stated that the CASS Class 1 flow restrictor nozzles in the main steam 

system are not susceptible to thermal embrittlement because the nozzles were cast by a 

centrifugal casting method using low molybdenum stainless material (SA 351 CF8). The staff 

noted that the “scope of the program” program element of GALL AMP XI.M12 states the 

susceptibility to thermal aging embrittlement of CASS components is determined in terms of 

casting method, molybdenum content, and ferrite content. It further states that all centrifugal 

cast low-molybdenum steels are not susceptible to thermal aging embrittlement. The staff 

confirmed that the applicant addressed cracking due to SCC and loss of material due to pitting 

and crevice corrosion in items 3.1.1-41 and 3.1.1-15, respectively. Based on its review, the staff 

finds it acceptable that loss of fracture toughness due to thermal embrittlement is not managed 

for these Class 1 flow elements fabricated from CASS because they were cast by a centrifugal 

casting method using low molybdenum stainless material, which are not susceptible consistent 

with the recommendations in GALL AMP XI.M12. Based on its review, the staff finds the 

applicant’s statement that item 3.1.1-57 is not applicable acceptable. 

LRA Table 3.1.1, item 3.1.1-87 addresses steel piping, piping components, and piping elements 

in concrete. The GALL Report recommends that there is no aging effect requiring management 

(AERM). The applicant stated that this line item is not applicable because it has no steel piping, 

piping components, and piping elements exposed to concrete in nuclear boiler instrumentation, 

reactor internals, RPV, and the reactor recirculation system. The staff reviewed the applicant’s 

UFSAR and confirmed that no in-scope steel piping, piping components, and piping elements in 

concrete are present in the systems and, therefore, the staff finds the applicant’s determination 

acceptable. 
Aging Management Review Results 

 3-224 

3.1.2.1.2 Cracking Due to Stress-Corrosion Cracking, Intergranular Stress-Corrosion Cracking, 

and Irradiation-Assisted Stress-Corrosion Cracking 

LRA Table 3.1.1, item 3.1.1-49 addresses nickel-alloy, welded access hole covers exposed to 

reactor coolant which are being managed for cracking due to SCC, IGSCC, and IASCC. The 

LRA credits the BWR Vessel Internals and the Water Chemistry Programs to manage the aging 

effect. The GALL Report recommends GALL AMP XI.M1, “ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD,” and GALL AMP XI.M2, “Water Chemistry,” to 

ensure that these aging effects are adequately managed. The associated AMR line item cites 

generic note E, indicating that the LRA AMR is consistent with the GALL Report item for 

material, environment, and aging effect, but a different AMP is credited. 

For those line items associated with generic note E, GALL AMP XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” recommends using periodic visual 

examination and leakage testing with augmented inspections of creviced areas along with GALL 

AMP XI.M2, “Water Chemistry,” which recommends monitoring and controlling known 

detrimental contaminants in accordance with the recommendations of BWRVIP-130 to manage 

the effects of aging. In its review of components associated with item 3.1.1-49 for which the 

applicant cited generic note E, the staff noted that the BWR Vessel Internals Program proposes 

to manage the aging of nickel-alloy, welded access hole covers through the use of EVT-1 to 

inspect the creviced regions of the welded access hole covers. The staff noted that the EVT-1 

inspection is a capable method for detecting fine-scale cracking that is characteristic of IGSCC 

and IASCC. 

The staff’s evaluation of the applicant’s BWR Vessel Internals Program and Water Chemistry 

Program are documented in SER Sections 3.0.3.1.7 and 3.0.3.2.1, respectively. The staff noted 

that the Water Chemistry Program includes controls of chemistry parameters which create an 

environment to reduce susceptibility to IGSCC. 

In its review of the component associated with item 3.1.1-49, the staff finds the applicant’s 

proposal to manage aging using the BWR Vessel Internals Program acceptable because: (1) it 

follows the guidelines in BWRVIP-180 for EVT-1 inspections for welded access hole covers, 

which is a proven technique that is capable of detecting the fine-scale cracking associated with 

IGSCC and IASCC and includes provisions for specific flaw evaluation guidelines to assess any 

indications of cracking that are detected; and (2) the applicant’s use of the Water Chemistry 

Program creates an environment to reduce susceptibility to IGSCC and is consistent with the 

recommendations of the GALL Report. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.1.3 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.1.1, item 3.1.1-47 addresses nickel-alloy and stainless steel RVI components 

exposed to reactor coolant which are being managed for loss of material due to pitting and 

crevice corrosion. The LRA credits the BWR Vessel Internals Program and the Water 

Chemistry Program to manage the aging effect. The GALL Report recommends GALL 

AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD,” and 

GALL AMP XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately 
Aging Management Review Results 

 3-225 

managed. The associated AMR line items cite generic note E, indicating that the LRA AMR is 

consistent with the GALL Report item for material, environment, and aging effect, but a different 

AMP is credited. 

For those line items associated with generic note E, GALL AMP XI.M1 recommends using 

periodic visual, surface, and/or volumetric examination and leakage testing along with GALL 

AMP XI.M2, which recommends monitoring and controlling known detrimental contaminants in 

accordance with the recommendations of BWRVIP-130 to manage the aging of this line item. In 

its review of components associated with item 3.1.1-47 for which the applicant cited generic 

note E, the staff noted that the BWR Vessel Internals Program is substituted for the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program because it proposes 

to manage the aging of nickel-alloy and stainless steel RVI components through ISIs according 

to component-specific BWRVIP documents that include industry-approved inspection 

procedures and flaw evaluations. The staff noted that the BWRVIP recommended inspections 

are often more stringent than those inspections specified by ASME Code Section XI, such as 

the BWRVIP use of EVT-1 or UT, in place of VT-1 or VT-3 from ISI for select components and 

locations. The staff noted that the applicant’s use of its Water Chemistry Program is consistent 

with the recommendations of the GALL Report. 

The staff’s evaluation of the applicant’s BWR Vessel Internals Program and Water Chemistry 

Program are documented in SER Sections 3.0.3.1.7 and 3.0.3.2.1, respectively. The staff noted 

that the Water Chemistry Program includes controls of chemistry parameters which create an 

environment that is not conducive for loss of material to occur. 

In its review of components associated with item 3.1.1-47, the staff finds the applicant’s 

proposal to manage aging using the BWR Vessel Internals Program and Water Chemistry 

Program acceptable because: (1) the BWR Vessel Internals Program follows the guidelines 

recommended by the BWRVIP, which are often more stringent than those inspections specified 

by ASME Code Section XI, and include specific flaw evaluation and repair recommendations to 

facilitate post-inspection review; and (2) the applicant’s use of the Water Chemistry Program 

creates an environment that is not conducive for loss of material to occur, and is consistent with 

the recommendations of the GALL Report. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.1.4 Cracking Due to Stress-Corrosion Cracking 

LRA Table 3.1.2-3, item 3.1.1-41 addresses nickel-alloy and stainless steel piping components 

exposed to reactor coolant which are being managed for cracking due to stress-corrosion 

cracking. The LRA credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program and Water Chemistry Program to manage the aging effect. The GALL 

Report recommends GALL AMP XI.M7, “BWR Stress Corrosion Cracking,” and GALL 

AMP XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately managed. 

The associated AMR line items cite generic note E, indicating that the LRA AMR is consistent 

with the GALL Report item for material, environment, and aging effect, but a different AMP is 

credited. 
Aging Management Review Results 

 3-226 

For those line items associated with generic note E, GALL AMP XI.M7 recommends using 

periodic visual and/or volumetric examination and leakage testing along with GALL AMP XI.M2, 

which recommends monitoring and controlling known detrimental contaminants in accordance 

with the recommendations of BWRVIP-130 to manage the aging of this line item. In its review 

of components associated with item 3.1.1-41 for which the applicant cited generic note E, the 

staff noted that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program is substituted for the BWR Stress Corrosion Cracking Program because it proposes to 

manage the aging of nickel-alloy and stainless steel RVI components through ISIs according to 

the ASME Code Section XI and component-specific BWRVIP documents that include 

industry-approved inspection procedures and flaw evaluations. The staff noted that the 

BWRVIP recommended inspections are often more stringent than those inspections specified 

by ASME Code Section XI, such as the use of EVT-1 or UT, in place of VT-1 or VT-3 for select 

components and locations. The staff also noted that the Water Chemistry Program is consistent 

with the recommendations of the GALL Report. 

The staff’s evaluation of the applicant’s ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD Program and Water Chemistry Program are documented in SER 

Sections 3.0.3.1.1 and 3.0.3.2.1, respectively. The staff noted that the components associated 

with item 3.1.1-41 for which the applicant cited generic note E, include steel with stainless steel 

cladding, stainless steel, and nickel alloy for nozzles (CRD return, core spray, jet pump 

instrumentation, recirculation inlet and outlet), penetrations (stub tubes, incore housings), and 

the reactor vessel bottom head, shell, and shell flange. In its review of components associated 

with item 3.1.1-41, the staff finds the applicant’s proposal to manage aging using the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and Water 

Chemistry Program acceptable because the ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD Program includes component-specific BWRVIP documents that include 

industry-approved inspection procedures and flaw evaluations, which require more stringent 

inspections than those specified by ASME Code Section XI, such as the use of EVT-1 or UT, in 

place of VT-1 or VT-3 for select components and locations, and the applicant’s use of the Water 

Chemistry Program is consistent with the recommendations of the GALL Report. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.1.5 Cracking Due to Stress-Corrosion Cracking, Loss of Material Due to Wear, Loss of 

Preload Due to Thermal Effects, Gasket Creep, and Self-loosening 

LRA Table 3.1.1, item 3.1.1-52 addresses steel and stainless steel bolting exposed to high 

pressure and high temperature systems which are being managed for SCC, loss of material due 

to wear, and loss of preload due to thermal effects, gasket creep, and self-loosening. The LRA 

credits the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program and the Structures Monitoring Program to manage these aging effects. The 

GALL Report recommends GALL AMP XI.M18, “Bolting Integrity,” to ensure that the aging 

effects are adequately managed. In LRA Table 3.3.2-8 (Cranes & Hoists), Table 3.3.2-13 (Fuel 

Handling and Storage System), and Table 3.5.2-7 (Primary Containment), the applicant aligned 

AMR results for carbon, low alloy, and stainless steel bolting exposed to air with item 3.1.1-52. 

The AMR result lines cite generic note E, indicating that the AMR result is consistent with the 

GALL Report for material, environment, and aging effect, but a different AMP is credited. The 

AMR result lines also cite plant-specific notes stating that for these combinations of component 
Aging Management Review Results 

 3-227 

type, material, and environment, the aging mechanisms of thermal effects and gasket creep are 

not applicable, but reductions of preload caused by self-loosening due to vibration or joint 

flexing is assumed potentially to occur. 

The staff reviewed the applicant’s Inspection of Overhead Heavy Load and Light Load (Related 

to Refueling) Handling Systems Program and the Structures Monitoring Program, and its 

evaluations are documented in SER Sections 3.0.3.2.6, and 3.0.3.2.16, respectively. 

The staff noted that the applicant’s Structures Monitoring Program uses procedures that have 

incorporated the guidance in EPRI TR-104319 and includes periodic visual inspections for loose 

nuts, missing bolts, or other signs of loss of preload. The staff finds the applicant’s proposed 

program acceptable to manage aging for these components because it uses visual inspections 

to detect loss of preload and has incorporated the guidance recommended in GALL 

AMP XI.M18. The staff noted that bolting in the cranes and hoists system, fuel handling and 

storage system, and primary containment system are not subjected to high temperatures and 

finds the applicant’s statement that thermal effects and gasket creep are not applicable aging 

mechanisms for bolting in these systems to be acceptable because exposure to high 

temperatures is required for these aging mechanisms to occur. 

During its review of AMR result lines associated with components for which the GALL Report 

recommends the Bolting Integrity Program, the staff noted that several other programs were 

identified to manage aging for bolting in the LRA. The staff issued RAI B.2.1.12-01 requesting 

that the applicant explain why programs other than the Bolting Integrity Program were credited 

to manage aging for structural bolting. 

In its response, which is evaluated in SER Section 3.0.3.2.4, the applicant added a number of 

AMR result lines, including lines associated with LRA Table 3.1.1, item 3.1.1-52. The AMR 

result lines credit the Bolting Integrity Program to manage loss of preload, in addition to the 

previously credited program, and cite generic note B, indicating that the results are consistent 

with the GALL Report for component, material, environment, and aging effect, but the AMP 

takes some exception(s) to the GALL Report. 

The staff finds the applicant’s proposed combination of programs acceptable to manage aging 

for these components because: (1) all of the programs include visual inspections of bolting 

which are capable of detecting loss of preload, (2) the use of the Bolting Integrity Program is 

consistent with the recommendations in the GALL Report, (3) the inspections performed by the 

Bolting Integrity Program supplements inspections performed by the Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems, and (4) the Structures 

Monitoring Program provides a more comprehensive approach to monitoring aging for these 

components. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-228 

3.1.2.1.6 Cracking Due to Stress-Corrosion Cracking and Intergranular Stress-Corrosion 

Cracking 

LRA Table 3.1.1, item 3.1.1-41 addresses stainless steel and nickel-alloy piping, piping 

components, and piping elements greater than or equal to 4 inches NPS, nozzle safe ends, and 

associated welds which are being managed for cracking due to SCC and IGSCC. The LRA 

credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and Water 

Chemistry Programs to manage cracking for stainless steel penetrations and carbon or low alloy 

steel with stainless steel cladding nozzles; reactor vessel bottom head; upper, upper 

intermediate, intermediate, lower intermediate, and lower shell sections; and shell flange. The 

GALL Report recommends GALL AMP XI.M7, “BWR Stress Corrosion Cracking,” and GALL 

AMP XI.M2, “Water Chemistry,” to ensure these aging effects are adequately managed. The 

associated AMR line items cite generic note E, which indicate that the line item is consistent 

with the GALL Report for the material, environment, and aging effect, but a different AMP is 

credited. 

GALL AMP XI.M7 recommends preventive measures to mitigate the effects of IGSCC, including 

water chemistry control, reduction of tensile stresses, and proper selection of materials, as well 

as ISIs and flaw evaluations to monitor for IGSCC and its effects. GALL AMP XI.M2 

recommends monitoring and controlling the concentration of contaminates in the water to 

minimize the occurrence of SCC. 

The staff reviewed the applicant’s ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD and Water Chemistry Programs and its evaluations are documented in SER 

Sections 3.0.3.1.1 and 3.0.3.2.1, respectively. The staff noted that the applicant’s Water 

Chemistry Program includes monitoring and controlling the concentration of contaminates in the 

water to minimize cracking. The staff also noted that the applicant’s ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program includes periodic visual, surface, and 

volumetric examinations and leakage testing of ASME Class 1, 2, and 3 components. The staff 

further noted that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program has incorporated the guidance from BWRVIP-75, “Technical Basis for Revisions to 

Generic Letter 88-01 Inspection Schedules,” which includes recommendations regarding proper 

selection of materials and reduction of stresses and is consistent with the recommendations in 

GALL AMP XI.M7. The staff finds the applicant’s proposed programs acceptable to manage 

aging for these components because the Water Chemistry Program will monitor and control 

contaminants in the water, and the ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program will perform periodic inspections and leakage testing in accordance with 

accepted industry guidance. 

However, for a CASS ASME Class 1 flow element, LRA Table 3.4.2-4 credits the Water 

Chemistry Program to manage the aging effect. The GALL Report recommends GALL 

AMP XI.M7, “BWR Stress Corrosion Cracking,” and GALL AMP XI.M2, “Water Chemistry,” to 

ensure these aging effects are adequately managed. The associated AMR line items cite 

generic note E, indicating that the LRA AMR is consistent with the GALL Report item for 

material, environment, and aging effects, but a different AMP is credited. The AMR line items 

also cite in a plant-specific note that this CASS nozzle (a Class 1 flow element) is not 

susceptible to thermal embrittlement because it was cast by a centrifugal casting method using 

low molybdenum stainless steel material (SA 351 CF8). 

The staff noted that SA 351 CF8 grade material is not susceptible to thermal embrittlement, but 

is susceptible to cracking and stress corrosion cracking. To manage cracking due to SCC, the 
Aging Management Review Results 

 3-229 

GALL Report recommends use of both GALL AMP XI.M7 “BWR Stress Corrosion Cracking” and 

GALL AMP XI.M2, “Water Chemistry.” The applicant only credited one AMP (Water Chemistry). 

By letter dated August 3, 2010, the staff issued RAI 3.4.2.4-01 requesting that the applicant 

justify why it did not credit the BWR Stress Corrosion Cracking program for managing the aging 

effect of cracking due to SCC and IGSCC of this nozzle. 

In its response dated August 26, 2010, the applicant stated that the steam flow element consists 

of an outer carbon steel pipe section, which performs the Class 1 reactor coolant pressure 

boundary function, and an internal nozzle insert that provides the throttle intended function. The 

applicant stated that the nozzle insert is made of two sections: an upstream nozzle section 

made of CASS welded to a downstream section made of carbon steel. The applicant further 

stated that the CASS portion of the nozzle insert does not meet the applicability criteria of GALL 

AMP XI.M7. The applicant also stated that water chemistry program would be an effective 

means to maintain the contaminants below the levels that would promote cracking because the 

flow element is located in a high steam flow area. The applicant further stated that the carbon 

content of the CASS portion of the flow element ranges between 0.04 and 0.06 wt. percent and 

ferrite content varies between 14 and 32 wt. percent. The staff notices that, under the GALL 

AMP XI.M7 recommendation, a component is resistant to sensitization (i.e., susceptibility to 

cracking/SCC) if the stainless steel material has a maximum carbon of 0.035 wt. percent and a 

minimum ferrite of 7.5 percent in weld metal and CASS. Since the CASS carbon content 

exceeds the GALL Report recommended maximum value of 0.035 percent, the staff reviewed 

the technical basis document BWRVIP-75-A2 referenced in GALL AMP XI.M7. BWRVIP-75-A 

states, in part, that “castings with a carbon content higher than 0.035 percent are generally not 

considered resistant to sensitization. However, experience has shown that welds joining these 

castings to resistant piping have performed well and can therefore be included in Category A3

. 

If extensive weld repairs were performed, the welds should be included in the Category D 

population4

.” As documented in the applicant’s e-mail correspondence (ADAMS Accession 

No. ML102560006), dated September, 9, 2010, the applicant confirmed that the main steam 

flow element CASS material had not been repaired during the plant operation to date. Thus this 

main steam flow element CASS material can be regarded as resistant to cracking, in 

accordance with the BWRVIP-75-A. Therefore, the staff finds the applicant’s use of Water 

Chemistry and One-Time Inspection programs to mitigate the aging of the Class 1 flow element 

(nozzle) acceptable because the applicant has selected a material that is resistant to cracking 

due to SCC, and use of the Water Chemistry and One-Time Inspection Programs is consistent 

with the GALL Report recommended programs. 

The staff concludes, based on the e-mail correspondence (ADAMS Accession 

No. ML102560006), that the applicant has demonstrated that the effects of aging for these 

 

2

 EPRI Technical Report 1012621, “BWRVIP-75-A: BWR Vessel and Internals Project Technical 

Basis for Revisions to Generic Letter 88-01 Inspection Schedules” Final Report, October 2005 

3

 Category A weldments are those with no known cracks that have low probability of 

experiencing IGSCC because they are made entirely of IGSCC resistant materials or have been 

solution heat treated after welding (Section 2.1.1 of BWRVIP-75-A). 

4 Category D weldments are those not made with resistant materials (Section 2.4.1 of BWRVIP75-A). 
Aging Management Review Results 

 3-230 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.1.7 Cracking Due to Stress-Corrosion Cracking, Intergranular Stress-Corrosion Cracking 

(for Stainless Steel Only), and Thermal and Mechanical Loading 

LRA Table 3.1.1, item 3.1.1-48 addresses carbon steel Class 1 piping, fittings, and branch line 

connections less than 4 inches NPS exposed to steam or treated water (reactor coolant) which 

are being managed for cracking due to thermal or mechanical loading. This LRA item also 

addresses: (1) stainless steel Class 1 piping, fittings, and branch line connections less than 

4 inches NPS exposed to steam or treated water greater than 140 °F which are being managed 

for cracking due to SCC and thermal or mechanical loading; and (2) stainless steel Class 1 

condensing chambers, flow devices, restricting orifices, thermowells, and valve bodies which 

are being managed for cracking due to SCC. The LRA credits the ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program; the Water Chemistry Program; and the 

Small-Bore Class 1 Piping Inspection Program, which is a plant-specific program, to manage 

the aging effect in the carbon steel or stainless steel Class 1 piping, fittings, and branch line 

connections. However, for the stainless steel Class 1 condensing chambers, flow devices, 

restricting orifices, thermowells, and valve bodies, the LRA credits only the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program and the Water Chemistry 

Program to manage the aging effect. The GALL Report recommends GALL AMP XI.M1, 

“ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD”; GALL AMP XI.M2, 

“Water Chemistry”; and GALL AMP XI.M35, “One-Time Inspection of ASME Code Class 1 

Small-Bore Piping,” to ensure that these aging effects are adequately managed. For the 

Class 1 piping, fittings, and branch line connections, AMR line items crediting the Small-Bore 

Class 1 Piping Inspection Program cite generic note E. Also, for the Class 1 condensing 

chambers, flow devices, restricting orifices, thermowells, and valve bodies, AMR lines crediting 

the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and the 

Water Chemistry Program cite generic note E. 

For those AMR line items associated with generic note E, GALL AMP XI.M35 recommends 

using one-time volumetric inspections for cracking, together with the Water Chemistry Program 

and ongoing ASME Code Section XI ISIs, to manage the aging effect of cracking. 

In its review of components associated with item 3.1.1-48 for which the applicant cited generic 

note E and credited the Small-Bore Class 1 Piping Inspection Program, the staff noted that the 

credited program proposes to manage the aging of carbon steel or stainless steel Class 1 

piping, fittings, and branch line connections less than 4 inches NPS through the use of ongoing 

visual inspections and volumetric examinations for selected Class 1 small-bore butt welds and 

other selected small-bore socket welds. 

The staff’s evaluation of the applicant’s Small-Bore Class 1 Piping Inspection Program is 

documented in SER Section 3.0.3.3.6. The staff notes that the applicant’s Small-Bore Class 1 

Piping Inspection Program provides ongoing inspections of selected piping welds using a 

combination of visual inspections and volumetric examinations that are equivalent to those 

recommended in GALL AMP XI.M35. The staff also notes that the selection criteria for 

components to be inspected in the Small-Bore Class 1 Piping Inspection Program include 

consideration of susceptibility to degradation similar to the selection criteria recommended in 

GALL AMP XI.M35. The staff further notes that the primary difference between the applicant’s 

Small-Bore Class 1 Piping Inspection Program and GALL AMP XI.M35 is that the applicant’s 
Aging Management Review Results 

 3-231 

program provides ongoing inspections and the GALL Report AMP specifies a one-time 

inspection. The staff finds the applicant’s use of its Small-Bore Class 1 Piping Inspection 

Program in lieu of GALL AMP XI.M35 acceptable because the applicant’s program uses 

appropriate examination techniques and component selection criteria, and provides for 

examination that occurs more frequently than the one-time examination specified in GALL 

AMP XI.M35. 

In its review of components associated with item 3.1.1-48 where the applicant cited generic 

note E and credited the Water Chemistry Program and the ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program, the staff noted that the credited 

programs propose to manage the aging of Class 1 condensing chambers, flow devices, 

restricting orifices, thermowells, and valve bodies using control of water chemistry and ASME 

Code Section XI-required inspections for these components. 

The staff’s evaluation of the applicant’s ASME Section XI Inservice Inspection, Subsection IWB, 

IWC, and IWD Program and Water Chemistry Program are documented in SER 

Sections 3.0.3.1.1 and 3.0.3.2.1, respectively. The staff notes that the applicant’s Water 

Chemistry Program provides mitigation for cracking due to SCC in stainless steel components, 

and the applicant’s ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD 

Program provides for VT-2 visual examination (system leakage test) of these components in 

accordance with ASME Code Section XI Examination Category B-P, applicable for all Class 1 

pressure boundary components. The staff also notes that the applicant does not credit a 

volumetric examination of these components comparable to what is recommended in GALL 

AMP XI.M35. The staff further notes that the material, environment, and aging effect for these 

components is the same as for the stainless steel Class 1 piping, fittings, and branch line 

connections less than 4 inches NPS where the applicant does perform a volumetric examination 

of selected piping welds. The staff notes that Class 1 condensing chambers, flow devices, 

restricting orifices, thermowells, and valve bodies are less susceptible to cracking due to SCC 

than stainless steel piping welds in the same environment; and welds associated with Class 1 

condensing chambers, flow devices, restricting orifices, thermowells, and valve bodies have 

susceptibility similar to stainless steel piping welds. The staff further notes that the VT-2 

examination of Class 1 condensing chambers, flow devices, restricting orifices, thermowells, 

and valve bodies provides ongoing confirmation that unacceptable leakage of these 

components does not occur. Because the applicant is performing volumetric examination of 

similar components that would provide an indication of whether cracking in the stainless steel 

Class 1 condensing chambers, flow devices, restricting orifices, thermowells, and valve bodies 

is an issue and the VT-2 examination provides ongoing confirmation that component pressure 

boundary integrity is intact, the staff finds it acceptable for the applicant to use the Water 

Chemistry Program and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and 

IWD Program for aging management of stainless steel Class 1 condensing chambers, flow 

devices, restricting orifices, thermowells, and valve bodies. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function(s) will be maintained 

consistent with the CLB during the period of extended operations, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-232 

3.1.2.2 AMR 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 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 

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 addresses the applicant’s AMR basis for managing cumulative fatigue 

damage in ASME Code Class 1 components and ASME Code Class 2 components that were 

analyzed to ASME Code Section III, Class 1 CUF calculation criteria. In this LRA section, the 

applicant stated that the analysis of cumulative fatigue damage in the core spray, feedwater, 

HPCI, main steam, nuclear boiler instrumentation, RCIC, reactor internals, RPV, reactor 

recirculation, reactor water cleanup, and RHR systems RCPB piping, valves, and other 

components are TLAAs as defined in 10 CFR 54.3. The applicant stated that these TLAAs are 

evaluated in accordance with 10 CFR 54.21(c)(1). 
Aging Management Review Results 

 3-233 

The applicant identified that the following AMRs in LRA Table 3.1.1 are applicable to this further 

evaluation item and that the analysis of metal fatigue for components addressed in these AMRs 

is a TLAA: 

● Item 3.1.1-1: The applicant stated that the HCGS steel pressure vessel support skirt and 

attachment weld components were required to be analyzed in accordance with 

applicable ASME Code Section III CUF calculation criteria. In LRA Table 3.1.2-3, the 

applicant identified that the reactor vessel external attachments are analyzed for CUF 

analyses. 

● Item 3.1.1-2: The applicant stated that the HCGS steel, stainless steel, steel with 

nickel-alloy or stainless steel cladding, nickel-alloy reactor vessel components, flanges, 

nozzles, penetrations, safe ends, thermal sleeves, vessel shells, heads, and welds were 

required to be analyzed in accordance with applicable ASME Code Section III CUF 

calculation criteria. In LRA Table 3.1.2-3, the applicant identified various nozzles, nozzle 

safe ends, nozzle thermal sleeves, penetrations, and the reactor vessel required to be 

analyzed for CUF analyses. 

● Item 3.1.1-3: The applicant stated that the HCGS steel, stainless steel, steel with 

nickel-alloy or stainless steel cladding, nickel-alloy RCPB piping, piping components, 

and piping elements exposed to reactor coolant were required to be analyzed in 

accordance with applicable ASME Code Section III CUF calculation criteria. In LRA 

Tables 3.1.2-1, 3.1.2-4, 3.2.2-2, 3.2.2-4, 3.2.2-6, 3.2.2-7, 3.3.2-24, and 3.4.2-4, the 

applicant identified piping, fittings, branch connections, and valve bodies that were 

required to be analyzed for CUF analyses. 

● Item 3.1.1-4: The applicant stated that the HCGS steel pump and valve closure bolting 

were required to be analyzed in accordance with applicable ASME Code Section III CUF 

calculation criteria. In LRA Tables 3.1.2-1, 3.1.2-3, 3.1.2-4, 3.2.2-2, 3.2.2-4, 3.2.2-6, 

3.2.2-7, 3.3.2-24, 3.4.2-2, and 3.4.2-4, the applicant identified bolting that was required 

to be analyzed for CUF analyses. 

● Item 3.1.1-5: The applicant stated that some of the HCGS RVI components designed to 

ASME Code Section III, Subsection NG requirements were required to be analyzed in 

accordance with applicable ASME Code Section III CUF calculation criteria. In LRA 

Table 3.1.2-2, the applicant identified that the following RVI components were required 

to be analyzed in accordance with an applicable CUF analysis: (1) RVI core shroud and 

core plate structures and (2) RVI top guide structure. The applicant stated that 

Section 4.3 describes the evaluation of these TLAAs. 

The staff reviewed LRA Section 3.1.2.2.1 against the general criteria in SRP-LR Section 3.1.2.1 

for performing AMR reviews, as subject to the additional further evaluation criteria in SRP-LR 

Section 3.1.2.2.1, which states that fatigue is a TLAA as defined in 10 CFR 54.3, and that these 

TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements in 

10 CFR 54.21(c)(1) and in accordance with the staff’s recommended acceptance criteria and 

review procedures for reviewing these type of TLAAs in SRP-LR Section 4.3, “Metal Fatigue 

Analysis.” The staff also reviewed LRA Section 3.1.2.2.1 and the AMRs discussed in this 

section against the staff’s AMR items for evaluating BWR design cumulative fatigue damage in 

the GALL Report. 
Aging Management Review Results 

 3-234 

With regard to the applicant’s metal fatigue AMR item 3.1.1-1, the staff noted that AMR item 1 in 

Table 1 of the GALL Report, Volume 1 and AMR items IV.A1-6 and IV.A2-20 in the GALL 

Report, Volume 2 identify that cumulative fatigue damage is an applicable aging effect for steel 

pressure vessel support skirt and attachment welds. The staff also noted that these GALL 

Report AMRs recommend that the TLAA on metal fatigue be used to manage the impact of 

cumulative fatigue damage in these components. The staff noted that, in conformance with this 

recommendation, the applicant included an applicable line item in LRA Table 3.1.2-3 for the 

reactor vessel external attachments that received ASME Code Section III CUF analysis 

calculations. The staff noted that the applicant credited the TLAA analysis in LRA Section 4.3.1 

with the management of cumulative fatigue damage in these components. The staff found that 

the applicant’s AMR assessment was in conformance with the recommendations in both the 

SRP-LR and in AMR item 1 of the GALL Report, Volume 1, Table 1 and AMR items IV.A1-6 and 

IV.A2-20 in the GALL Report, Volume 2. Based on this review, the staff finds the applicant’s 

AMR analysis on cumulative fatigue damage of support skirt and attachment welds components 

to be acceptable because it is in conformance with the recommendations in SRP-LR 

Section 3.1.2.2.1 and the GALL Report AMR items that are invoked by this SRP-LR section. 

The staff evaluates the TLAA analysis for the support skirt and attachment welds component in 

SER Section 4.3.1. 

With regard to the applicant’s metal fatigue AMR item 3.1.1-2, the staff noted that AMR item 2 in 

Table 1 of the GALL Report, Volume 1 and AMR item IV.A1-7 in the GALL Report, Volume 2 

identify that cumulative fatigue damage is an applicable aging effect for steel, stainless steel, 

steel with nickel-alloy or stainless steel cladding, nickel-alloy reactor vessel components, 

flanges, nozzles, penetrations, safe ends, thermal sleeves, vessel shells, heads, and welds. 

The staff also noted that these GALL Report AMRs recommend that the TLAA on metal fatigue 

be used to manage the impact of cumulative fatigue damage in these components. The staff 

noted that, in conformance with this recommendation, the applicant included applicable line 

items in LRA Table 3.1.2-3 for various nozzles, nozzle safe ends, nozzle thermal sleeves, 

penetrations, and the reactor vessel that received ASME Code Section III CUF analysis 

calculations. The staff noted that the applicant credited the TLAA analysis in LRA Section 4.3.1 

with the management of cumulative fatigue damage in these components. The staff found that 

the applicant’s AMR assessment was in conformance with the recommendations in both the 

SRP-LR and in AMR item 2 of GALL Report, Volume 1, Table 1 and AMR item IV.A1-7 in the 

GALL Report, Volume 2. Based on this review, the staff finds the applicant’s AMR analysis on 

cumulative fatigue damage of reactor vessel components, flanges, nozzles, penetrations, safe 

ends, thermal sleeves, vessel shells, heads, and welds to be acceptable because it is in 

conformance with the recommendations in SRP-LR Section 3.1.2.2.1 and the GALL Report 

AMR items that are invoked by this SRP-LR section. The staff evaluates the TLAA analysis for 

the reactor vessel components, flanges, nozzles, penetrations, safe ends, thermal sleeves, 

vessel shells, heads, and welds components in SER Section 4.3.1. 

With regard to the applicant’s metal fatigue AMR item 3.1.1-3, the staff noted that AMR item 3 in 

Table 1 of the GALL Report, Volume 1 and AMR item IV.C1-15 in the GALL Report, Volume 2 

identify that cumulative fatigue damage is an applicable aging effect for steel, stainless steel, 

steel with nickel-alloy or stainless steel cladding, nickel-alloy RCPB piping, piping components, 

and piping elements exposed to reactor coolant. The staff also noted that these GALL Report 

AMRs recommend that the TLAA on metal fatigue be used to manage the impact of cumulative 

fatigue damage in these components. The staff noted that, in conformance with this 

recommendation, the applicant included applicable line items in LRA Tables 3.1.2-1, 3.1.2-4, 

3.2.2-2, 3.2.2-4, 3.2.2-6, 3.2.2-7, 3.3.2-24, and 3.4.2-4 for piping, fittings, branch connections 

and valve bodies that received ASME Code Section III CUF analysis calculations. The staff 
Aging Management Review Results 

 3-235 

noted that the applicant credited the TLAA analysis in LRA Sections 4.3.3 and 4.3.4 with the 

management of cumulative fatigue damage in these components. The staff found that the 

applicant’s AMR assessment was in conformance with the recommendations in both the 

SRP-LR and in AMR item 3 of the GALL Report, Volume 1, Table 1 and AMR item IV.C1-15 in 

the GALL Report, Volume 2. Based on this review, the staff finds the applicant’s AMR analysis 

on cumulative fatigue damage of piping, piping components, and piping elements components 

to be acceptable because it is in conformance with the recommendations in SRP-LR 

Section 3.1.2.2.1 and the GALL Report AMR items that are invoked by this SRP-LR section. 

The staff evaluates the TLAA analysis for the piping, piping components, and piping elements 

components in SER Sections 4.3.3 and 4.3.4. 

With regard to the applicant’s metal fatigue AMR item 3.1.1-4, the staff noted that AMR item 4 in 

Table 1 of the GALL Report, Volume 1 and AMR item IV.C1-11 in the GALL Report, Volume 2 

identify that cumulative fatigue damage is an applicable aging effect for steel pump and valve 

closure bolting. The staff also noted that these GALL Report AMRs recommend that the TLAA 

on metal fatigue be used to manage the impact of cumulative fatigue damage in these 

components. The staff noted that, in conformance with this recommendation, the applicant 

included applicable line items in LRA Tables 3.1.2-1, 3.1.2-3, 3.1.2-4, 3.2.2-2, 3.2.2-4, 3.2.2-6, 

3.2.2-7, 3.3.2-24, 3.4.2-2, and 3.4.2-4 for bolting that received ASME Code Section III CUF 

analysis calculations. The staff noted that the applicant credited the TLAA analysis in LRA 

Section 4.3.1 with the management of cumulative fatigue damage in these components. The 

staff found that the applicant’s AMR assessment was in conformance with the recommendations 

in both the SRP-LR and in AMR item 4 of the GALL Report, Volume 1, Table 1 and AMR 

item IV.C1-11 in the GALL Report, Volume 2. Based on this review, the staff finds the 

applicant’s AMR analysis on cumulative fatigue damage of pump and valve closure bolting 

components to be acceptable because it is in conformance with the recommendations in 

SRP-LR Section 3.1.2.2.1 and the GALL Report AMR items that are invoked by this SRP-LR 

section. The staff evaluates the TLAA analysis for the pump and valve closure bolting 

components in SER Section 4.3.1. 

With regard to the applicant’s metal fatigue AMR item 3.1.1-5, the staff noted that AMR item 5 in 

Table 1 of the GALL Report, Volume 1 and AMR item IV.B1-14 in the GALL Report, Volume 2 

identify that cumulative fatigue damage is an applicable aging effect for RVI components. The 

staff also noted that these GALL Report AMRs recommend that the TLAA on metal fatigue be 

used to manage the impact of cumulative fatigue damage in these components. The staff noted 

that, in conformance with this recommendation, the applicant included applicable line items in 

LRA Tables 3.1.2-2 for RVI components that received ASME Code Section III CUF analysis 

calculations. The staff noted that the applicant credited the TLAA analysis in LRA Section 4.3.2 

with the management of cumulative fatigue damage in these components. The staff found that 

the applicant’s AMR assessment was in conformance with the recommendations in both the 

SRP-LR and in AMR item 5 of the GALL Report, Volume 1, Table 1 and AMR item IV.B1-14 in 

the GALL Report, Volume 2. Based on this review, the staff finds the applicant’s AMR analysis 

on cumulative fatigue damage of pump and valve closure bolting components to be acceptable 

because it is in conformance with the recommendations in SRP-LR Section 3.1.2.2.1 and the 

GALL Report AMR items that are invoked by this SRP-LR section. The staff evaluates the 

TLAA analysis for the RVI components in SER Section 4.3.2. 

With regard to the applicant’s metal fatigue AMR items 3.1.1-6, 3.1.1-7, 3.1.1-8, 3.1.1-9, and 

3.1.1-10, the applicant stated that this aging effect is not applicable to HCGS, which is a BWR. 
Aging Management Review Results 

 3-236 

SRP-LR Section 3.1.2.2.1 states that fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are 

required to be evaluated in accordance with 10 CFR 54.21(c)(1). SRP-LR Table 3.1-1 identifies 

items 6, 7, 8, 9, and 10 applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.1 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWRs. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.5 do not apply to HCGS because the guidance is applicable to PWRs. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.1 criteria. For those items that apply to LRA Section 3.1.2.2.1, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.1.2.2.2 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. 

 (1) LRA Section 3.1.2.2.2 is associated with LRA Table 3.1.1, item 3.1.1-11 and addresses 

carbon and low alloy steel for the reactor vessel nozzles, nozzle safe ends and welds, 

RCPB components, RVI attachments, and reactor vessel top head and flange exposed 

to reactor coolant which are being managed for loss of material due to general, pitting, 

and crevice corrosion by the Water Chemistry Control and the One-Time Inspection 

programs. The applicant addressed the further evaluation requirement by stating that it 

will implement the One-Time Inspection Program to verify the effectiveness of the Water 

Chemistry Program. The applicant further stated that LRA Table 3.1.1, item 3.1.1-12 is 

only applicable to PWR designs and is, therefore, not applicable to HCGS. 

 The staff reviewed LRA Section 3.1.2.2.2, item 1 against the criteria in SRP-LR 

Section 3.1.2.2.2, item 1, which states that loss of material due to general, pitting, and 

crevice corrosion could occur for steel top head enclosure (without cladding) top head 

nozzles (vent, top head spray, or RCIC and spare) exposed to reactor coolant. The 

SRP-LR also states that control of water chemistry does not preclude loss of material 

due to general, pitting, and crevice corrosion at locations of stagnant flow conditions. 

Therefore, the effectiveness of the chemistry control program should be verified to 

ensure that corrosion does not occur. A one-time inspection of select components at 

susceptible locations is an acceptable method to determine whether an aging effect is 

not occurring, or an aging effect is progressing very slowly such that the component’s 

intended function will be maintained during the period of extended operation. 

 The applicant stated that item 3.1.1.-12 is not applicable because it is applicable to 

PWRs only. The staff finds the applicant’s determination acceptable for item 3.1.1-12. 

 The staff’s evaluation of the applicant’s Water Chemistry Program and One-Time 

Inspection Program is documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, 

respectively. The staff determined that the Water Chemistry Program includes activities 

to mitigate aging effects on component surfaces by controlling water chemistry for 

impurities such as dissolved oxygen, chlorides, fluorides, and sulfates that can 

potentially accelerate corrosion and cracking. The staff further determined that this 
Aging Management Review Results 

 3-237 

program relies on monitoring and control of water chemistry in order to keep the peak 

levels of various impurities below the specified limits. The staff noted that by keeping 

the impurities within the guidance of BWRVIP-130, the applicant can mitigate the 

damage from the active aging mechanism (loss of material due to general, crevice, and 

pitting corrosion). The staff determined that the applicant’s One-Time Inspection 

Program will also verify the effectiveness of its Water Chemistry Program. 

 In its review of components associated with item 3.1.1-11, the staff finds the applicant’s 

proposal to manage aging using the Water Chemistry Program and the One-Time 

Inspection Program acceptable because the Water Chemistry Program monitors and 

controls the chemical environment (impurities) of the RCPB components that are 

exposed to reactor coolant and will be supplemented by the One-Time Inspection 

Program to confirm the effectiveness of the Water Chemistry Program, consistent with 

the recommendations in the GALL Report. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.2, item 1 criteria. For those line items that apply to LRA 

Section 3.1.2.2.2, item 1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (2) LRA Section 3.1.2.2.2.2 is associated with Table 3.1.1, item 3.1.1-13 and addresses 

carbon steel piping and fittings exposed to treated water and steam in the core spray, 

feedwater, HPCI, main steam, nuclear boiler instrumentation, RCIC, reactor 

recirculation, reactor water cleanup, and RHR systems, which are being managed for 

loss of material due to general (steel only), pitting, and crevice corrosion by the Water 

Chemistry and One-Time Inspection Programs. The applicant stated that it does not 

have isolation condensers. The applicant addressed the further evaluation requirements 

by stating that the One-Time Inspection Program will be used to verify the effectiveness 

of the Water Chemistry Program. 

 The staff reviewed LRA Section 3.1.2.2.2, item 2 against the criteria in SRP-LR 

Section 3.1.2.2.2, item 2, which states that: (1) loss of material due to general, pitting, 

and crevice corrosion could occur for stainless steel BWR isolation condenser 

components exposed to reactor coolant; (2) the existing AMP relies on monitoring and 

control of water chemistry to manage the effects of loss of material due to general, 

pitting, and crevice corrosion; and (3) control of water chemistry does not preclude loss 

of material due to general, pitting, and crevice corrosion at locations of stagnant flow 

conditions. The effectiveness of the Water Chemistry Program, therefore, should be 

verified using a one-time inspection to ensure that corrosion does not occur. The GALL 

Report recommends a one-time inspection of select components at susceptible locations 

as an acceptable method to verify the effectiveness of the Water Chemistry Program 

and ensure that an aging effect is not occurring, or is progressing very slowly so that the 

component’s intended function will be maintained during the period of extended 

operation. 

 The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. The 

staff finds the applicant’s combination of programs acceptable to manage loss of 

material because these programs: (1) provide for periodic sampling of treated water to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 
Aging Management Review Results 

 3-238 

pitting, and crevice corrosion; and (2) will perform one-time inspections to verify the 

effectiveness of the Water Chemistry Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.2, item 2 criteria. For those line items that apply to LRA 

Section 3.1.2.2.2, item 2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (3) LRA Section 3.1.2.2.2 is referenced by LRA Table 3.1.1, items 3.1.1-14 and 3.1.1-15 

and addresses stainless steel, nickel-alloy, and steel with nickel-alloy or stainless steel 

cladding reactor vessel flanges, nozzles, penetrations, pressure housings, safe ends, 

and vessel shell, heads, and welds exposed to reactor coolant which are being managed 

for loss of material due to pitting and crevice corrosion by the Water Chemistry and the 

One-Time Inspection Programs. The applicant addressed the further evaluation criteria 

of the SRP-LR by stating that it will implement a One-Time Inspection Program to 

manage the loss of material due to general, pitting, and crevice corrosion of stainless 

steel, CASS, nickel-alloy, and steel with stainless steel cladding for reactor vessel 

flange, nozzles, penetrations, safe ends, thermal sleeves, vessel shells, heads, welds, 

and RCPB components including piping, piping elements, and piping components 

exposed to treated water and steam at susceptible locations. 

 The staff reviewed LRA Section 3.1.2.2.2, item 3 against the criteria in SRP-LR 

Section 3.1.2.2.2, item 3, which states that: (1) loss of material due to pitting and crevice 

corrosion could occur for stainless steel, nickel-alloy, and steel with stainless steel or 

nickel-alloy cladding flanges, nozzles, penetrations, pressure housings, safe ends, and 

vessel shells, heads, and welds exposed to reactor coolant; (2) the existing AMP relies 

on monitoring and control of water chemistry to mitigate corrosion; and (3) control of 

water chemistry does not preclude corrosion at locations of stagnant flow conditions. 

The effectiveness of the water chemistry program, therefore, should be verified using a 

one-time inspection to ensure that corrosion does not occur. The GALL Report 

recommends a one-time inspection of select components at susceptible locations as an 

acceptable method to verify the effectiveness of the Water Chemistry Program and 

ensure that an aging effect is not occurring, or is progressing very slowly so that the 

component’s intended function will be maintained during the period of extended 

operation. 

 The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.1, found that the applicant’s 

Water Chemistry Program follows the guidelines in BWRVIP-130 and will provide 

mitigation for the aging effect of loss of material due to pitting and crevice corrosion. 

The staff reviewed the applicant’s One-Time Inspection Program, which is documented 

in SER Section 3.0.3.1.11, and found that the applicant’s AMP is consistent with the 

GALL Report’s recommendations for GALL AMP XI.M32, “One-Time Inspection.” The 

applicant’s One-Time Inspection Program includes provisions for inspecting select 

components in areas of low or stagnant flow and is capable of detecting loss of material 

due to pitting and crevice corrosion, if it should occur in the selected components. The 

applicant’s One-Time Inspection Program is acceptable for verification because: (1) the 

aging effects progress very slowly so that the performance of the RCPB components is 

not compromised, and (2) it is listed as an acceptable method in the SRP-LR. 
Aging Management Review Results 

 3-239 

 In its review of components associated with AMR item 3.1.1-15, the staff noted that 

CASS is not listed as one of the materials. Additionally, for CASS flow elements, 

SRP-LR Table 3.1-1, item 57 recommends aging management for loss of fracture 

toughness due to thermal aging embrittlement. However, LRA Table 3.4.2-4 includes 

two 3.1.1-15 line items under Table 1 items (flow elements, Class 1) with CASS as the 

material, and credits the Water Chemistry and the One-Time Inspection Programs. In its 

letter dated June 14, 2010, the staff issued RAI 3.1.1-15-1 requesting that the applicant 

explain why: (1) AMR item 3.1.1-57 is not applicable when the GALL Report only 

exempts pump and valve bodies and (2) the flow elements associated with AMR item 

3.1.1-15 do not credit GALL AMP XI.M12, “Thermal Aging Embrittlement of Cast 

Austenitic Stainless Steel (CASS),” to manage loss of fracture toughness/thermal aging 

embrittlement. 

 In a letter dated July 12, 2010, the applicant responded to RAI 3.1.1-15-1 by providing 

the following response: 

(a) Hope Creek LRA Table 3.1.1 Summary of Aging Management 

Evaluations for the Reactor Vessel, Internals, and Reactor Coolant 

System, on Pages 3.1-36 and 3.1-37, provides the following discussion 

for why line item 3.1.1-57 is not applicable to Hope Creek. 

 The Class 1 CASS flow restrictor nozzles in the Main Steam System are 

not susceptible to thermal embrittlement because the nozzles were cast 

by a centrifugal casting method using low molybdenum stainless material 

(SA351 CF8). In accordance with the guidance provided in the 

NUREG-1801, Volume 2, Section XI.M12, the centrifugally cast, low 

molybdenum CASS portion of the flow restrictors is not susceptible to 

thermal aging embrittlement. 

(b) Based on the above, loss of fracture toughness/thermal aging 

embrittlement is not an applicable aging effect/mechanism for the CASS 

nozzle sections of the Main Steam flow elements associated with AMR 

line item 3.1.1-15. In addition, GALL AMP XI.M12, Thermal Aging 

Embrittlement of Cast Austenitic Stainless Steel (CASS) states: 

 Scope of Program: The program includes screening criteria to 

determine which CASS components are potentially susceptible to 

thermal aging embrittlement and require augmented inspection. 

The screening criteria are applicable to all primary pressure 

boundary and reactor vessel internal components constructed 

from SA-351 Grades CF3,CF3A, CF8, CF8A, CF3M, CF3MA, 

CF8M, with service conditions above 250 C (482°F). 

 The CASS nozzle sections of the Main Steam flow elements are not 

primary pressure boundary or reactor vessel internal components. 

Therefore, GALL AMP XI.M12, "Thermal Aging Embrittlement of Cast 

Austenitic Stainless Steel (CASS) program is not used for Hope Creek.” 

 The staff reviewed the applicant’s response to RAI 3.1.1-15-1 and confirmed that the 

CASS flow elements associated with AMR item 3.1.1-15 should not be susceptible to 

thermal aging embrittlement. Therefore, the staff’s concern described in RAI 3.1.1-15-1 

is resolved. 
Aging Management Review Results 

 3-240 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.2.3 criteria. For those line items that apply to LRA 

Section 3.1.2.2.2.3, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (4) LRA Section 3.1.2.2.2.4 refers to Table 3.1.1, item 3.1.1-16 and addresses loss of 

material due to general, pitting, and crevice corrosion. The applicant stated that this 

aging effect is not applicable to HCGS, which is a BWR. 

 SRP-LR Section 3.1.2.2.2.4 states that loss of material due to general, pitting, and 

crevice corrosion could occur in the steel PWR steam generator upper and lower shell 

and transition cone exposed to secondary feedwater and steam. SRP-LR Table 3.1-1 

identifies item 6 applicable to PWRs. 

 The staff verified that SRP-LR Section 3.1.2.2.2.4 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWR nickel-alloy tubes and sleeves in a reactor coolant and secondary feedwater and 

steam environment. 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA 

Section 3.1.2.2.2, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR 

Section 3.1.2.2.3: 

 (1) LRA Section 3.1.2.2.3 refers to Table 3.1.1, item 3.1.1-17 and states that neutron 

irradiation embrittlement 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 4.2 documents 

the staff’s review of the applicant’s evaluation of this TLAA. 

 (2) LRA Section 3.1.2.2.3 refers to LRA Table 3.1.2-3, item 3.1.1-18 and addresses RPV 

carbon or low alloy steel with stainless steel cladding exposed to reactor coolant and 

neutron flux (internal) which are being managed for loss of fracture toughness due to 

neutron irradiation embrittlement by the Reactor Vessel Surveillance Program. The 

applicant addressed the further evaluation requirement by stating that the Reactor 

Vessel Surveillance Program relies on the BWRVIP ISP and satisfies the requirements 

of 10 CFR Part 50, Appendix H. The Reactor Vessel Surveillance Program includes 

periodic testing of metallurgical surveillance samples to monitor the progress of neutron 

embrittlement of the RPV as a function of neutron fluence, in accordance with RG 1.99, 

“Radiation Embrittlement of Reactor Vessel Materials,” Revision 2. BWRVIP-116 

identifies and schedules additional capsules to be withdrawn and tested during the 

period of extended operation. HCGS will continue using the ISP during the period of 

extended operation by implementing the requirements of BWRVIP-116. The 

BWRVIP-116 (NRC Safety Evaluation dated February 24, 2006) report incorporates the 
Aging Management Review Results 

 3-241 

technical criteria specified in BWRVIP-86-A (approved by the staff in an SER dated 

February 1, 2002) and extends the ISP to cover the BWR fleet through the period of 

extended operation. The Reactor Vessel Surveillance Program will adequately identify, 

evaluate, and manage the effects of loss of fracture toughness due to neutron irradiation 

embrittlement of the steel with stainless steel cladding of the reactor vessel to ensure 

there is no loss of intended function during the period of extended operation. 

 The staff reviewed LRA Section 3.1.2.2.3, item 2 against the criteria in SRP-LR 

Section 3.1.2.2.3, item 2, which states that loss of fracture toughness due to neutron 

irradiation embrittlement could occur in BWR reactor vessel beltline shell, nozzle, and 

welds exposed to reactor coolant and neutron flux. The SRP-LR also states that the 

applicant must implement a reactor surveillance program that follows the requirements 

of 10 CFR Part 50, Appendix H by incorporating plant-specific factors such as the 

composition of limiting materials, availability of surveillance capsules, and projected 

fluence levels. In addition, the plant-specific program must provide for untested 

capsules to be maintained in a manner such that they could be re-inserted into the 

vessel in the future if the need arises. The staff also notes that the applicant has 

committed (Commitment No. 21) to establishing restrictions that will ensure that the plant 

is operated within the conditions to which the surveillance capsules were exposed. 

 The staff’s evaluation of the applicant’s Reactor Vessel Surveillance program is 

documented in SER Section 3.0.3.2.11. The staff noted the applicant’s program 

consists of periodic testing of metallurgical surveillance samples to monitor the progress 

of neutron embrittlement of the RPV as a function of neutron fluence that is capable of 

identifying, evaluating, and managing the effects of loss of fracture toughness due to 

neutron irradiation embrittlement of the steel with stainless steel cladding of the reactor 

vessel. 

 In its review of components associated with item 3.1.1-18, the staff finds the applicant’s 

proposal to manage aging using the Reactor Vessel Surveillance Program acceptable 

because the applicant has committed to implementation of the BWRVIP-116 ISP. The 

staff noted that this industry program does provide for testing of the most sensitive 

beltline material from HCGS at a fluence that is representative of 56 EFPY at HCGS. 

The staff also noted that all of the HCGS capsules are already tested or slated for testing 

as part of the ISP; there are no extra capsules that could be removed without testing. 

 Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.3, item 2 criteria. For those line items that apply to LRA 

Section 3.1.2.2.3, item 2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-242 

3.1.2.2.4 Cracking Due to SCC and IGSCC 

The staff reviewed LRA Section 3.1.2.2.4 against the criteria in SRP-LR Section 3.1.2.2.4. 

 (1) LRA Section 3.1.2.2.4.1 refers to Table 3.1.1, item 3.1.1-19 and addresses the stainless 

steel vessel flange leak detection line exposed to treated water which is being managed 

for cracking due to SCC or IGSCC by the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program and the Water Chemistry Program. The 

applicant addressed the further evaluation requirements by stating that the Water 

Chemistry Program monitors and controls water chemistry in accordance with EPRI 

BWR Water Chemistry Guidelines and that control of water chemistry within the 

guidelines prevents or mitigates cracking due to SCC or IGSCC. The applicant further 

stated that its current ISI program, through a currently approved relief request, uses a 

VT-2 visual examination on the vessel flange leak detection line, prior to reactor cavity 

drain down during each refueling outage. 

 The staff reviewed LRA Section 3.1.2.2.4.1 against the criteria in SRP-LR 

Section 3.1.2.2.4.1, which states that cracking due to SCC or IGSCC could occur in the 

stainless steel and nickel-alloy BWR top head enclosure vessel flange leak detection 

lines. The GALL Report recommends that a plant-specific AMP be evaluated because 

existing programs may not be capable of mitigating or detecting crack initiation and 

growth due to SCC and IGSCC in the vessel flange leak detection line. 

 In its review of components subordinate to LRA item 3.1.1-19, the staff noted that the 

applicant’s current relief request related to VT-2 visual examination of the flange leak 

detection line is approved only for the current 10-year ISI interval and does not extend 

into the period of extended operation. The staff further noted that during the VT-2 

examination, the line is pressurized only by the static head of water above the flange. 

By letter dated June 9, 2010, the staff issued RAI 3.1.2.2.4.1 requesting that the 

applicant explain: (1) how a VT-2 examination will detect cracking due to SCC or IGSCC 

in the vessel flange leak detection line prior to failure of the line’s intended function, and 

(2) how aging of the vessel flange leak detection line will be managed without referring 

to implementation of a relief request which has neither been requested nor approved for 

the period of extended operation. 

 By letter dated July 6, 2010, the applicant provided a response to RAI 3.1.2.2.4.1. In its 

review of the applicant’s response, the staff noted that the applicant proposed to 

manage the aging effect of cracking due to SCC with a combination of the Water 

Chemistry Program and the ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program. The staff also noted that there was no proposed augmentation 

of the ASME Code Section XI requirement applicable for the vessel flange leak detection 

line and that the applicant did not provide sufficient information for the staff to conclude 

that the applicable VT-2 leakage testing of the component is capable of detecting crack 

initiation prior to failure of the component’s intended function. On August 5, 2010, the 

staff and the applicant held a telephone conference to discuss issues with the applicant’s 

response to RAI 3.1.2.2.4.1. As a result of this conference, the applicant provided a 

revised response in a letter dated August 26, 2010. 

 In its revised response to RAI 3.1.2.2.4.1, the applicant stated that it will manage 

cracking due to SCC or IGSCC in the stainless steel vessel flange leak detection line 

using the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program and the Water Chemistry Program, plus a one-time volumetric examination of 
Aging Management Review Results 

 3-243 

the line for cracking in accordance with its One-Time Inspection Program. The applicant 

revised appropriate LRA tables and discussions to reflect this change. This resulted in 

changes to LRA Table 3.1.1, item 3.1.1-19; Table 3.4.2-4; and Subsection 3.1.2.2.4. 

 Based on its review of the applicant’s response to RAI 3.1.2.2.4.1, as amended by letter 

dated August 26, 2010, the staff finds that: (1) the monitoring and control for water 

chemistry mitigates the likelihood of cracking, (2) the volumetric examination performed 

prior to the period of extended operation provides assurance that there is no cracking in 

the vessel flange leak detection line, and (3) the VT-2 examination provides ongoing 

periodic confirmation that physical integrity of the line is maintained during the period of 

extended operation. Therefore, the staff’s concern described in RAI 3.1.2.2.4.1 is 

resolved. 

 The staff’s evaluation of the applicant’s ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program; Water Chemistry Program; and One-Time 

Inspection Program are documented in SER Sections 3.0.3.1.1, 3.0.3.2.1, and 

3.0.3.1.11, respectively. In its review of components associated with item 3.1.1-19, the 

staff finds the applicant’s proposal to manage aging using the combination of these three 

programs acceptable because: (1) the Water Chemistry Program provides monitoring 

and control for water chemistry to mitigate the likelihood of cracking due to SCC or 

IGSCC; (2) the volumetric examination, performed in accordance with the One-Time 

Inspection Program, provides assurance that there is no cracking in the vessel flange 

leak detection line prior to entering the period of extended operation; and (3) the VT-2 

examination in accordance with the ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD Program provides ongoing periodic confirmation that physical 

integrity of the line is maintained during the period of extended operation. 

 On this basis, the staff finds that the revised response to RAI 3.1.2.2.4.1, as documented 

in the applicant’s letter dated August 26, 2010, resolves all issues addressed in the RAI. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.4, item 1 criteria. For those line items that apply to LRA 

Section 3.1.2.2.4, item 1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (2) LRA Section 3.1.2.2.4.2 refers to Table 3.1.1, item 3.1.1-20 and addresses the stainless 

steel isolation condenser components exposed to reactor coolant. The applicant stated 

this aging effect is not applicable because HCGS does not have isolation condensers. 

 SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in 

stainless steel BWR isolation condenser components exposed to reactor coolant. 

 The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.1.2.2.4, item 

2 is not applicable to HCGS because HCGS does not have an isolation condenser and 

the staff guidance in this SRP-LR section is only applicable to BWRs with isolation 

condenser components. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.4, item 2 do not apply to HCGS because the guidance is applicable to BWRs 

with isolation condenser components. 
Aging Management Review Results 

 3-244 

3.1.2.2.5 Crack Growth Due to Cyclic Loading 

LRA Section 3.1.2.2.5 refers to Table 3.1.1, item 3.1.1-21 and addresses crack growth due to 

cyclic loading. The applicant stated that this aging effect is not applicable to HCGS, which is a 

BWR. 

SRP-LR Section 3.1.2.2.5 states that crack growth due to cyclic loading could occur in reactor 

vessel shell forgings clad with stainless steel using a high-heat-input welding process. SRP-LR 

Table 3.1-1 identifies item 21 as applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.5 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR-designed reactor 

vessel shells fabricated of SA508-CI forgings clad with stainless steel using a high-heat-input 

welding process. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.5 do not apply to HCGS because the guidance is applicable to PWRs. 

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void 

Swelling 

LRA Section 3.1.2.2.6 refers to Table 3.1.1, item 3.1.1-22 and addresses loss of fracture 

toughness due to neutron irradiation embrittlement and void swelling. The applicant stated that 

this aging effect is not applicable to HCGS, which is a BWR. 

SRP-LR Section 3.1.2.2.6 states that loss of fracture toughness due to neutron irradiation 

embrittlement and void swelling could occur in stainless steel and nickel-alloy RVI components 

exposed to reactor coolant and neutron flux. SRP-LR Table 3.1-1 identifies item 22 applicable 

to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.5 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR stainless steel 

and nickel-alloy RVI components exposed to reactor coolant and neutron flux. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.6 do not apply to HCGS because the guidance is applicable to PWRs. 

3.1.2.2.7 Cracking Due to Stress-Corrosion Cracking 

 (1) LRA Section 3.1.2.2.7.1 refers to Table 3.1.1, item 3.1.1-23 and addresses cracking due 

to SCC. The applicant stated that this aging effect is not applicable to HCGS, which is a 

BWR. 

 SRP-LR Section 3.1.2.2.7.1 states that cracking due to SCC could occur in the PWR 

stainless steel reactor vessel flange leak detection lines and bottom-mounted instrument 

guide tubes exposed to reactor coolant. SRP-LR Table 3.1-1 identifies item 23 

applicable to PWRs. 

 The staff verified that SRP-LR Section 3.1.2.2.7.1 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWR stainless steel reactor vessel closure head flange leak detection line and 

bottom-mounted instrument guide tubes. 
Aging Management Review Results 

 3-245 

 (2) LRA Section 3.1.2.2.7.2 refers to Table 3.1.1, item 3.1.1-24 and addresses cracking due 

to SCC. The applicant stated that this aging effect is not applicable to HCGS, which is a 

BWR. 

 SRP-LR Section 3.1.2.2.7.2 states that cracking due to SCC could occur in Class 1 

PWR CASS RCS piping, piping components, and piping elements exposed to reactor 

coolant. SRP-LR Table 3.1-1 identifies item 24 applicable to PWRs. 

 The staff verified that SRP-LR Section 3.1.2.2.7.2 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWR Class 1 CASS piping, piping components, and piping elements exposed to reactor 

coolant. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.7,”Items 1 and 2 do not apply to HCGS because the guidance is applicable to 

PWRs. 

3.1.2.2.8 Cracking Due to Cyclic Loading 

 (1) LRA Section 3.1.2.2.8.1 refers to Table 3.1.1, item 3.1.1-25 and addresses cracking due 

to cyclic loading. The applicant stated that this aging effect is not applicable because 

stainless steel jet pump sensing lines internal to the reactor vessel are not required to 

support intended functions and are not included within the scope of license renewal. A 

safety assessment for these components has been performed and reported in 

BWRVIP-06. The evaluation concluded that these components do not perform a 

safety-related function. This report also concluded that failure of these components will 

not result in consequential failure of any safety-related equipment. The lines outside of 

the vessel are not subjected to flow-induced vibration, but are part of the RCPB and are 

subject to an AMR. Cracking due to SCC, and thermal and mechanical loading of the 

stainless steel lines external to the reactor vessel are addressed by Table 3.1.1, 

item 3.1.1-48. 

 SRP-LR Section 3.1.2.2.8.1 states that cracking due to cyclic loading could occur in the 

stainless steel BWR jet pump sensing lines. 

 The staff reviewed the BWRVIP-06 and the applicant’s UFSAR and finds that SRP-LR 

Section 3.1.2.2.8, item 1 is not applicable to HCGS because jet pump sensing lines do 

not perform a safety-related function and failure of these components will not result in 

consequential failure of any safety-related equipment. Also, lines outside of the vessel 

are subject to an AMR and the aging effects of cracking due to SCC, and thermal and 

mechanical loading of the stainless steel lines external to the reactor vessel are being 

addressed by Table 3.1.1, item 3.1.1-48. 

 (2) LRA Section 3.1.2.2.8.2 refers to Table 3.1.1, item 3.1.1-26 and addresses cracking due 

to cyclic loading. The applicant stated this aging effect is not applicable because HCGS 

does not have isolation condensers. 

 SRP-LR Section 3.1.2.2.8.2 states that cracking due to cycling loading could occur in 

steel and stainless steel BWR isolation condenser components exposed to reactor 

coolant. 
Aging Management Review Results 

 3-246 

 The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.1.2.2.8.2, 

item 2 is not applicable to HCGS because HCGS does not have an isolation condenser, 

and the staff guidance in this SRP-LR section is only applicable to BWRs with isolation 

condenser components. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.8, items 1 and 2 do not apply to HCGS because stainless steel jet pump sensing 

lines internal to the reactor vessel are not included within the scope of license renewal but are 

being addressed by Table 3.1.1, item 3.1.1-48 and HCGS does not have isolation condensers. 

3.1.2.2.9 Loss of Preload Due to Stress Relaxation 

LRA Section 3.1.2.2.9 refers to Table 3.1.1, item 3.1.1-27 and addresses loss of preload due to 

stress relaxation. The applicant stated that this aging effect is not applicable to HCGS, which is 

a BWR. 

SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation could occur in 

stainless steel and nickel-alloy PWR RVI screws, bolts, tie rods, and hold down springs exposed 

to reactor coolant. SRP-LR Table 3.1-1 identifies item 27 applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.9 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR stainless steel 

and nickel-alloy RVI screws, bolts, tie rods, and hold down springs. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.9 do not apply to HCGS because the guidance is applicable to PWRs. 

3.1.2.2.10 Loss of Material Due to Erosion 

LRA Section 3.1.2.2.10 refers to Table 3.1.1, item 3.1.1-28 and addresses loss of material due 

to erosion. The applicant stated that this aging effect is not applicable to HCGS, which is a 

BWR. 

SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion could occur in steel steam 

generator feedwater impingement plates and supports exposed to secondary feedwater. 

SRP-LR Table 3.1-1 identifies item 28 applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.10 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR steel steam 

generator feedwater impingment plates and supports exposed to secondary feedwater. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.10 do not apply to HCGS because the guidance is applicable to PWRs. 

3.1.2.2.11 Cracking Due to Flow-Induced Vibration 

LRA Section 3.1.2.2.11 refers to LRA Table 3.1.1, item 3.1.1-29 and addresses reactor internals 

stainless steel and CASS steam dryer components exposed to reactor coolant which are being 

managed for cracking due to flow-induced vibration by the BWR Vessel Internals Program. The 

applicant addressed the further evaluation requirements by stating that the BWR Vessel 
Aging Management Review Results 

 3-247 

Internals Program inspects, evaluates, and repairs flaws, in accordance with the guidelines 

provided in BWRVIP-139, “BWR Vessel and Internals Project Steam Dryer Inspection and Flaw 

Evaluation.” The applicant further stated that following the guidelines in BWRVIP-139 will 

adequately identify, evaluate, and manage the effects of cracking due to flow-induced vibration 

of the CASS and stainless steel steam dryer components. 

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11, 

which states that cracking due to flow-induced vibration could occur for BWR stainless steel 

steam dryers exposed to reactor coolant. The SRP-LR also recommends further evaluation of a 

plant-specific AMP to ensure that this aging effect is adequately managed. The staff reviewed 

the applicant’s experience with cracking in steam dryers and notes that fatigue cracking in the 

steam dryer components has been found at other plants after EPU, but not at HCGS. 

The staff’s evaluation of the applicant’s BWR Vessel Internals Program is documented in SER 

Section 3.0.3.1.7. The staff noted that the BWR Vessel Internals Program includes inspection 

of the steam dryer that is in accordance with BWRVIP-139 guidance. The staff issued its safety 

evaluation (SE) on BWRVIP-139 in a letter to the EPRI, dated July 30, 2008. In its SE, the staff 

stated that the guidelines below should be followed for re-inspection: 

● Each BWR applicant will determine the appropriate re-inspection approach according to 

GE SIL-644 or BWRVIP-139 in consideration of the steam dryer performance at its plant. 

● License conditions associated with steam dryer monitoring programs in power uprate 

license amendments take precedence over the steam dryer re-inspection provisions in 

GE SIL-644 or BWRVIP-139. 

● The applicant will justify any adjustments to its steam dryer re-inspection program where 

commitments exist to implement the re-inspection provisions in GE SIL-644 to support a 

power uprate license amendment or other activities. 

● The applicant is expected to inform the staff of significant changes to its steam dryer 

re-inspection program where the staff relied on the program in a regulatory decision. 

In its review of components associated with item 3.1.1-29, the staff finds the applicant’s 

proposal to manage aging using the BWR Vessel Internals Program acceptable because the 

applicant is implementing the guidelines of BWRVIP-139 as accepted by the staff in the SE, and 

the applicant’s BWR Vessel Internals Program incorporates the guidelines of BWRVIP-139. 

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.11 criteria. For those line items that apply to LRA Section 3.1.2.2.11, 

the staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-248 

3.1.2.2.12 Cracking Due to Stress-Corrosion Cracking and Irradiation-Assisted 

Stress-Corrosion Cracking 

LRA Section 3.1.2.2.12 refers to Table 3.1.1, item 3.1.1-30 and addresses cracking due to SCC 

and IASCC. The applicant stated that this aging effect is not applicable to HCGS, which is a 

BWR. 

SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and IASCC could occur in PWR 

stainless steel reactor internals exposed to reactor coolant. SRP-LR Table 3.1-1 identifies 

item 30 applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.12 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR stainless steel 

RVI components. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.12 do not apply to HCGS because the guidance is applicable to a PWR. 

3.1.2.2.13 Cracking Due to Primary Water Stress-Corrosion Cracking 

LRA Section 3.1.2.2.13 refers to Table 3.1.1, item 3.1.1-31 and addresses cracking due to 

PWSCC. The applicant stated that this aging effect is not applicable to HCGS, which is a BWR. 

SRP-LR Section 3.1.2.2.13 states that cracking due to PWSCC could occur in 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. SRP-LR Table 3.1-1 identifies item 31 applicable to 

PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.13 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR nickel alloy and 

steel with nickel-alloy cladding piping, piping components, piping elements, penetration, 

nozzles, safe ends, and weld; pressurizer heater sheaths, sleeves, diaphragm plate, manways 

and flanges; and core support pads and core guide lugs. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.13 do not apply to HCGS because the guidance is applicable to PWRs. 

3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion 

LRA Section 3.1.2.2.14 refers to Table 3.1.1, item 3.1.1-32 and addresses wall thinning due to 

flow-accelerated corrosion. The applicant stated that this aging effect is not applicable to 

HCGS, which is a BWR. 

SRP-LR Section 3.1.2.2.14 states that wall thinning due to flow-accelerated corrosion could 

occur in steel feedwater inlet rings and supports. SRP-LR Table 3.1-1 identifies item 32 

applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.14 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR steel steam 

generator feedwater inlet rings and supports. 
Aging Management Review Results 

 3-249 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.14 do not apply to HCGS because the guidance is applicable to PWRs. 

3.1.2.2.15 Changes in Dimensions Due to Void Swelling 

LRA Section 3.1.2.2.15 refers to Table 3.1.1, item 3.1.1-33 and addresses changes in 

dimensions due to void swelling. The applicant stated that this aging effect is not applicable to 

HCGS, which is a BWR. 

SRP-LR Section 3.1.2.2.15 states that changes in dimensions due to void swelling could occur 

in stainless steel and nickel-alloy PWR reactor internal components exposed to reactor coolant. 

SRP-LR Table 3.1-1 identifies item 33 applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.15 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR stainless steel 

and nickel-alloy RVI components. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.15 do not apply to HCGS because the guidance is applicable to PWRs. 

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 refers to Table 3.1.1, items 3.1.1-34 and 3.1.1-35 and 

addresses cracking due to SCC and PWSCC. The applicant stated that this aging effect 

is not applicable to HCGS, which is a BWR. 

 SRP-LR Section 3.1.2.2.16.1 states that cracking due to SCC could occur on the primary 

coolant side of PWR steel steam generator upper and lower heads, tubesheets, and 

tube-to-tube sheet welds made or clad with stainless steel. Cracking due to PWSCC 

could occur on the primary coolant side of PWR steel steam generator upper and lower 

heads, tubesheets, and tube-to-tube sheet welds made or clad with nickel alloy. 

SRP-LR Table 3.1-1 identifies items 34 and 35 applicable to PWRs. 

 The staff verified that SRP-LR Section 3.1.2.2.16.1 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWRs. 

 (2) LRA Section 3.1.2.2.16.2 refers to Table 3.1.1, item 3.1.1-36 and addresses cracking 

due to SCC and PWSCC. The applicant stated that this aging effect is not applicable to 

HCGS, which is a BWR. 

 SRP-LR Section 3.1.2.2.16.2 states that cracking due to SCC could occur on stainless 

steel pressurizer spray heads. Cracking due to PWSCC could occur on nickel-alloy 

pressurizer spray heads. SRP-LR Table 3.1-1 identifies item 36 applicable to PWRs. 

 The staff verified that SRP-LR Section 3.1.2.2.16.2 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWR nickel-alloy, stainless steel pressurizer spray heads. 
Aging Management Review Results 

 3-250 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.16, items 1 and 2 do not apply to HCGS because the guidance is applicable to 

PWRs. 

3.1.2.2.17 Cracking Due to Stress-Corrosion Cracking, Primary Water Stress-Corrosion 

Cracking, and Irradiation-Assisted Stress-Corrosion Cracking 

LRA Section 3.1.2.2.17 refers to Table 3.1.1, item 3.1.1-37 and addresses cracking due to SCC, 

PWSCC, and IASCC. The applicant stated that this aging effect is not applicable to HCGS, 

which is a BWR. 

SRP-LR Section 3.1.2.2.17 states that cracking due to SCC, PWSCC, and IASCC could occur 

in PWR stainless steel and nickel-alloy RVI components. SRP-LR Table 3.1-1 identifies item 37 

applicable to PWRs. 

The staff verified that SRP-LR Section 3.1.2.2.17 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR stainless steel 

and nickel-alloy RVI components. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.1.2.2.17 do not apply to HCGS because the guidance is applicable to PWRs. 

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 through J, that the 

combination of component type, material, environment, and AERM does not correspond to a 

line 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 line 

item component is not evaluated in the GALL Report. Note G indicates that the environment for 

the AMR line item component and material is not evaluated in the GALL Report. Note H 

indicates that the aging effect for the AMR line 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 line item component, material, and environment 

combination is not applicable. Note J indicates that neither the component nor the material and 

environment combination for the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant had 

demonstrated that the aging effects will be adequately managed so that the intended function(s) 

will be maintained consistent with the CLB during the period of extended operation. The staff’s 

evaluation is discussed in the following sections. 
Aging Management Review Results 

 3-251 

3.1.2.3.1 Reactor Vessel, Internals, and Reactor Coolant System – Nuclear Boiler 

Instrumentation – Summary of Aging Management Evaluation – LRA Table 3.1.2-1 

The staff reviewed LRA Table 3.1.2-1 which summarizes the results of AMR evaluations for the 

nuclear boiler instrumentation component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.1.2.1. 

3.1.2.3.2 Reactor Vessel, Internals, and Reactor Coolant System – Reactor Internals – 

Summary of Aging Management Evaluation – LRA Table 3.1.2-2 

In LRA Table 3.1.2-2, the applicant stated that the nickel-alloy core shroud and core plate 

components exposed to reactor coolant and neutron flux are being managed for cracking due to 

SCC, IGSCC, and IASCC by the BWR Vessel Internals Program and Water Chemistry 

Program. The AMR line items cite generic note F, indicating that the material for the AMR line 

item component is not evaluated in the GALL Report. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environmental combination 

because nickel-alloy components exposed to reactor coolant and neutron flux are subject to 

cracking due to SCC, IGSCC, or IASCC, similar to the stainless steel components. The staff 

noted that the GALL Report recommends that stainless steel core shroud (GALL AMR 

item IV.B1-1) and core plate (GALL AMR item IV.B1-6) components exposed to reactor coolant 

be managed for cracking due to SCC, IGSCC, and/or IASCC. The staff further noted that the 

applicant is managing loss of material due to pitting and crevice corrosion for these components 

and are associated with LRA Table 3.1.1, item 3.1.1-47. 

The staff noted that nickel-alloy components are corrosion resistant materials much like 

stainless steel and are also susceptible to many of the same aging effects and mechanisms 

such as cracking due to SCC, IGSCC, and/or IASCC. The staff’s evaluation of the applicant’s 

BWR Vessel Internals Program and Water Chemistry Program are documented in SER 

Sections 3.0.3.1.7 and 3.0.3.2.1, respectively. The staff noted that the Water Chemistry 

Program includes controls of chemistry parameters which create an environment that is not 

conducive for loss of material to occur. The staff finds the applicant’s proposal to manage aging 

using the BWR Vessel Internals Program and Water Chemistry Program acceptable because: 

(1) the internals program follows the guidelines recommended by the BWRVIP, which includes 

stringent inspections, such as the use of EVT-1 or UT, and specific flaw evaluation and repair 

recommendations to facilitate post-inspection review; and (2) the applicant’s use of the Water 

Chemistry Program creates an environment that is not conducive for cracking to occur. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-252 

In LRA Table 3.1.2-.2, the applicant stated that the stainless steel with stellite cladding core 

shroud and core plate (LPCI coupling), and jet pump assemblies components exposed to 

reactor coolant and neutron flux are being managed for cracking due to SCC, IGSCC, and 

IASCC, and loss of material due to pitting and crevice corrosion by the BWR Vessel Internals 

Program and Water Chemistry Program. The AMR line items cite generic note F, indicating that 

the material for the AMR line item component is not evaluated in the GALL Report. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because stainless steel with stellite cladding components exposed to reactor coolant and 

neutron flux are subject to cracking due to SCC, IGSCC, and/or IASCC, and loss of material 

due to pitting and crevice corrosion similar to the stainless steel components. The staff noted 

that the GALL Report recommends that stainless steel core shroud and core plate (LPCI 

coupling) (GALL AMR item IV.B1-3) and jet pump assemblies (GALL AMR item IV.B1-13) 

components exposed to reactor coolant be managed for cracking due to SCC, IGSCC, and/or 

IASCC. The staff also noted that the GALL Report recommends that stainless steel RVI 

components (GALL AMR item IV.B1-15) exposed to reactor coolant be managed for loss of 

material due to pitting and crevice corrosion. 

The staff noted that stainless steel with stellite components are corrosion resistant materials 

much like stainless steel and are also susceptible to many of the same aging effects and 

mechanisms such as cracking due to SCC, IGSCC, and/or IASCC, and loss of material due to 

pitting and crevice corrosion. The staff’s evaluation of the applicant’s BWR Vessel Internals 

Program and Water Chemistry Program are documented in SER Sections 3.0.3.1.7 and 

3.0.3.2.1, respectively. The staff noted that the Water Chemistry Program includes controls of 

chemistry parameters which create an environment that is not conducive for loss of material to 

occur. The staff finds the applicant’s proposal to manage aging using the BWR Vessel Internals 

Program and Water Chemistry Program acceptable because: (1) the internals program follows 

the guidelines recommended by the BWRVIP, which includes stringent inspections, such as the 

use of EVT-1 or UT, and specific flaw evaluation and repair recommendations to facilitate 

post-inspection review; and (2) the applicant’s use of the Water Chemistry Program creates an 

environment that is not conducive for cracking to occur. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.1.2-2, the applicant stated that nickel-alloy jet pump assemblies exposed to 

reactor coolant and neutron flux are being managed for loss of preload and stress relaxation by 

a TLAA. The AMR line item cites generic note H, which indicates that the aging effect is not 

addressed in the GALL Report for this component, material, and environment combination. 

TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1), and the staff’s evaluation of the 

TLAA for this item is documented in SER Section 4.7.3. 

In LRA Table 3.1.2-2, the applicant stated that stainless steel core shroud and core plate 

components exposed to reactor coolant and neutron flux are being managed for loss of preload 

and stress relaxation by a TLAA. The AMR line item cites generic note H, which indicates that 

the aging effect is not addressed in the GALL Report for this component, material, and 
Aging Management Review Results 

 3-253 

environment combination. TLAAs are evaluated in accordance with 10 CFR 54.21(c)(1), and 

the staff’s evaluation of the TLAA for this item is documented in SER Section 4.2.7. 

3.1.2.3.3 Reactor Vessel, Internals, and Reactor Coolant System – Reactor Pressure Vessel – 

Summary of Aging Management Evaluation – LRA Table 3.1.2-3 

In LRA Table 3.1.2-3, the applicant stated that high-strength low alloy steel ASME Class 1 

bolting (i.e., top head studs and nuts) with yield strength of 150 ksi or greater exposed to indoor 

air is being managed for loss of material due to general, pitting, and crevice corrosion by the 

Reactor Head Closure Studs Program. The AMR line items cite generic note H, indicating that 

the aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Reactor Head Closure Studs Program is documented in SER 

Section 3.0.3.1.2. The staff noted that the Reactor Head Closure Studs Program manages loss 

of material for the reactor head closure studs, nuts, and washers using visual and volumetric 

inspections in accordance with ASME Code Section XI, Subsection IWA. The staff finds that 

the applicant’s proposed program to manage loss of material for low alloy steel bolting with yield 

strength of 150 ksi or greater exposed to indoor air acceptable because the applicant will use 

inspection techniques that are in accordance with ASME Code Section XI, Subsection IWA, 

which are acceptable for detection of loss of material. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.1.2.3.4 Reactor Vessel, Internals, and Reactor Coolant System – Reactor Recirculation 

System – Summary of Aging Management Evaluation – LRA Table 3.1.2-4 

The staff reviewed LRA Table 3.1.2-4 which summarizes the results of AMR evaluations for the 

reactor recirculation system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.1.2.1. 

3.1.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the RCS, reactor vessel, and RVI 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). 
Aging Management Review Results 

 3-254 

3.2 Aging Management of Engineered Safety Features

This section of the SER documents the staff’s review of the applicant’s AMR results for the ESF 

components and component groups of: 

● containment hydrogen recombiner system 

● core spray system 

● filtration, recirculation, and ventilation system 

● high pressure coolant injection system 

● hydrogen and oxygen analyzer system 

● reactor core isolation cooling system 

● residual heat removal system 

● vacuum relief valve system 

3.2.1 Summary of Technical Information in the Application 

LRA Section 3.2 provides AMR results for the ESF components and component groups. LRA 

Table 3.2.1, “Summary of Aging Management Evaluations for the Engineered Safety Features,” 

provides a summary comparison of its AMRs to those evaluated in the GALL Report for 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 

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. 

3.2.2 Staff Evaluation 

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for ESF 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 conducted an onsite audit of AMPs to confirm the applicant’s claim that certain AMPs 

were consistent with the GALL Report. The purpose of this audit was to examine the applicant’s 

AMPs and related documentation and to verify the applicant’s claim of consistency with the 

corresponding GALL Report AMPs. The staff did not repeat its review of the matters described 

in the GALL Report. The staff’s evaluations of the AMPs are documented in SER Section 3.0.3. 

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 Sections 3.2.2.1 and 3.2.2.2. 
Aging Management Review Results 

 3-255 

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. 

The review evaluated whether all plausible aging effects were identified and whether the aging 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff’s evaluation are discussed in SER Section 3.2.2.3. 

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line 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 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 and stainless 

steel piping, piping 

components, and 

piping elements in the 

ECCS 

(3.2.1-1) 

Cumulative fatigue 

damage 

TLAA, evaluated 

in accordance with 

10 CFR 54.21(c) 

Yes TLAA Fatigue is a 

TLAA (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 

BWRs (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 Not applicable Not applicable to 

HCGS (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 

HCGS (See SER 

Section 3.2.2.2.3)

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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.2.2.2.3)
Aging Management Review Results 

 3-256 

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 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 

One-Time 

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 

HCGS (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 Periodic 

Inspection 

Consistent with 

GALL Report 

(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 

One-Time 

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 

HCGS (See SER 

Section 3.2.2.2.4)

Elastomer seals and 

components in the 

standby gas 

treatment system 

exposed to air – 

indoor uncontrolled 

(3.2.1-11) 

Hardening and 

loss of strength 

due to elastomer 

degradation 

A plant-specific 

AMP is to be 

evaluated. 

Yes Periodic 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.2.2.2.5)
Aging Management Review Results 

 3-257 

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 

high-pressure 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 Not applicable to 

BWRs (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 

HCGS (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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(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 Not applicable Not applicable 

(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 

One-Time 

Inspection 

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.2.2.2.8)

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 

microbiologicallyinfluenced 

corrosion 

Buried Piping and 

Tanks 

Surveillance or 

Buried Piping and 

Tanks Inspection 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.2.2.2.9)

Stainless steel piping, 

piping components, 

and piping elements 

exposed to treated 

water > 60 °C 

(140 °F) 

(3.2.1-18) 

Cracking due to 

SCC and IGSCC 

BWR Stress 

Corrosion 

Cracking and 

Water Chemistry 

No BWR Stress 

Corrosion 

Cracking and 

Water Chemistry 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-258 

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 

(3.2.1-19) 

Wall thinning due 

to 

flow-accelerated 

corrosion 

Flow-Accelerated 

Corrosion 

No Flow-Accelerated 

Corrosion 

Consistent with 

GALL Report 

CASS piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated or 

unborated) > 250 °C 

(482 °F) 

(3.2.1-20) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

Thermal Aging 

Embrittlement of 

CASS 

No Not applicable Not applicable to 

HCGS (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 

HCGS (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 

HCGS (See SER 

Section 3.2.2.1.1)

Steel bolting and 

closure bolting 

exposed to air – 

outdoor (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 

(See SER 

Sections 

3.2.2.1.2, 

3.3.2.1.2, and 

3.5.2.1.4) 

Steel closure bolting 

exposed to air – 

indoor uncontrolled 

(external) 

(3.2.1-24) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening 

Bolting Integrity No Bolting Integrity 

Program 

ASME Section XI, 

Subsection IWE 

10 CFR Part 50, 

Appendix J 

Consistent with 

GALL Report 

(See SER 

Sections 

3.2.2.1.4 and 

3.5.2.1.2) 

Stainless steel piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water > 60 °C 

(140 °F) 

(3.2.1-25) 

Cracking due to 

SCC 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 
Aging Management Review Results 

 3-259 

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 

closed-cycle cooling 

water 

(3.2.1-26) 

Loss of material 

due to general, 

pitting, and crevice 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

HCGS 

Stainless steel piping, 

piping components, 

piping elements, and 

heat exchanger 

components exposed 

to closed-cycle 

cooling water 

(3.2.1-28) 

Loss of material 

due to pitting and 

crevice corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

HCGS 

External surfaces of 

steel components 

including ducting, 

piping, ducting 

closure bolting, and 

containment isolation 

piping external 

surfaces exposed to 

air – indoor 

uncontrolled 

(external); 

condensation 

(external) and air – 

outdoor (external) 

(3.2.1-31) 

Loss of material 

due to general 

corrosion 

External Surfaces 

Monitoring 

No External Surfaces 

Monitoring 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-260 

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 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 Not applicable Not applicable to 

HCGS (See SER 

Section 3.2.2.1.1)

Steel encapsulation 

components exposed 

to air – indoor 

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 

HCGS (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 Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Consistent with 

GALL Report 

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 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

Steel heat exchanger 

components exposed 

to raw water 

(3.2.1-36) 

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

Stainless steel piping, 

piping components, 

and piping elements 

exposed to raw water 

(3.2.1-37) 

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

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 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle 

Cooling Water 

System 

No Periodic 

Inspection 

Fire Water System 

Consistent with 

GALL Report 

(See SER 

Section 3.2.2.1.3)
Aging Management Review Results 

 3-261 

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 heat 

exchanger 

components exposed 

to raw water 

(3.2.1-39) 

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

Steel and stainless 

steel heat exchanger 

tubes (serviced by 

open-cycle 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 

HCGS 

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 Not applicable Not applicable to 

HCGS 

Gray cast iron piping, 

piping components, 

piping elements 

exposed to 

closed-cycle cooling 

water 

(3.2.1-42) 

Loss of material 

due to selective 

leaching 

Selective 

Leaching of 

Materials 

No Not applicable Not applicable to 

HCGS 

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 

HCGS 

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 Selective 

Leaching of 

Materials 

Consistent with 

GALL Report 

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 Not applicable Not applicable to 

BWRs 
Aging Management Review Results 

 3-262 

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 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 Not applicable Not applicable to 

BWRs 

CASS piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

> 250 °C (482 °F) 

(3.2.1-47) 

Loss of fracture 

toughness due to 

thermal aging 

embrittlement 

Thermal Aging 

Embrittlement of 

CASS 

No Not applicable Not applicable to 

BWRs 

Stainless steel or 

stainless-steel-clad 

steel piping, piping 

components, piping 

elements, and tanks 

(including safety 

injection 

tanks/accumulators) 

exposed to treated 

borated water > 60 °C 

(140 °F) 

(3.2.1-48) 

Cracking due to 

SCC 

Water Chemistry No Not applicable Not applicable to 

BWRs 

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 Not applicable Not applicable to 

BWRs 

Aluminum piping, 

piping components, 

and piping elements 

exposed to air – 

indoor 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 Not applicable Not applicable to 

HCGS 

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 
Aging Management Review Results 

 3-263 

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 air – 

indoor uncontrolled 

(external) 

(3.2.1-53) 

None None No None Consistent with 

GALL Report 

(See SER 

Sections 2.3.3.10 

and 3.3.2.3.10) 

Steel piping, piping 

components, and 

piping elements 

exposed to air – 

indoor controlled 

(external) 

(3.2.1-54) 

None None No Not applicable Not applicable to 

HCGS 

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete 

(3.2.1-55) 

None None No Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

BWRs 

The staff’s review of the ESF component groups followed several approaches. One approach, 

documented in SER Section 3.2.2.1, discusses the staff’s review of AMR results for components 

the applicant indicated are consistent with the GALL Report and require no further evaluation. 

Another approach, documented in SER Section 3.2.2.2, discusses the staff’s review of AMR 

results for components the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER 

Section 3.2.2.3, discusses the staff’s review of AMR results for components 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 components is documented in 

SER Section 3.0.3. 
Aging Management Review Results 

 3-264 

3.2.2.1 AMR Results That Are Consistent with the GALL Report 

In LRA Section 3.2.2.1, the applicant identified the materials, environments, and AERMs. The 

applicant identified the following programs that manage the aging effects of ESF components: 

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

● Bolting Integrity 

● BWR Stress Corrosion Cracking 

● External Surfaces Monitoring 

● Flow-Accelerated Corrosion 

● Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

● Lubricating Oil Analysis 

● One-Time Inspection 

● Periodic Inspection 

● Selective Leaching of Materials 

● Small-Bore Class 1 Piping Inspection 

● TLAA 

● Water Chemistry 

LRA Tables 3.2.2-1 to 3.2.2-8 summarize AMRs for the ESF components and indicate AMRs 

claimed to be consistent with the GALL Report. 

For component groups evaluated in the GALL Report for which the applicant had claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed a review to determine whether the plant-specific components in these GALL Report 

component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR line item. The notes describe how the information 

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

Notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR line 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 line 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 line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

AMP identified in the GALL Report. The staff audited these line items to verify consistency with 

the GALL Report and 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 line 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 audited these 
Aging Management Review Results 

 3-265 

line items to verify consistency with the GALL Report. The staff also determined whether the 

AMR line 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 line 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 audited these line items to 

verify consistency with the GALL Report. The staff confirmed whether the AMR line item of the 

different component was applicable to the component under review and whether it had reviewed 

and accepted the exceptions to the GALL Report AMPs. The staff also determined whether the 

AMP identified by the applicant was consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions. 

Note E indicates that the AMR line item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff audited these line 

items to verify consistency with the GALL Report. The staff also 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. 

LRA Tables 3.2.2-1 to 3.2.2-8 provide a summary of the AMR results for component types 

associated with the ESF. The summary information for each component type included intended 

function; material; environment; AERM; AMPs; GALL Report, Volume 2 item; cross reference to 

LRA Table 3.2.1; and generic and plant-specific notes related to consistency with the GALL 

Report. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, it did verify that the material presented in the LRA was 

applicable and that the applicant had identified the appropriate GALL Report AMRs. 

On the basis of its review, the staff determines that, for AMRs not requiring further evaluation, 

as identified in LRA Table 3.2.1, the applicant’s references to the GALL Report are acceptable 

and no further evaluation is required. 

The staff notes that in LRA Tables 3.2.2-4 and 3.2.2-8 there are AMR line items for carbon steel 

tanks exposed to treated water and gray cast iron tanks exposed to lubricating oil. The staff 

also notes that the LRA does not have a line item for the tank material exposed to an air or 

wetted gas internal environment as would occur when the tank is partially full. The staff further 

notes that in each instance, the LRA line items manage the aging of the tank internals using the 

appropriate chemistry controlling AMP, Water Chemistry and Lubricating Oil programs 

respectively, and the One-Time Inspection Program. The staff finds the existing line items 

acceptable because the chemistry program will minimize contaminant concentrations and thus 

mitigate loss of material due to various corrosion mechanisms for tank internal surfaces at the 

fluid to air transition zone, and the One-Time Inspection Program will provide reasonable 

assurance that an aging effect is not occurring or that the aging effect is occurring slowly 

enough as to not affect a components intended function. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-266 

3.2.2.1.1 AMR Results Identified as Not Applicable 

LRA Table 3.2.1, item 3.2.1-20 addresses loss of fracture toughness due to thermal aging 

embrittlement in CASS piping, piping components, and piping elements exposed to treated 

water (borated or unborated) greater than 250 °C (482 °F). The applicant stated that this line 

item is not applicable because there are no CASS piping, piping components, or piping 

elements subject to treated water greater than 250 °C (482 °F) in the ESF systems. The staff 

reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any 

AMR results for the ESF systems that include CASS piping, piping components, and piping 

elements exposed to treated water (borated or unborated) greater than 250 °C (482 °F). The 

staff also reviewed the applicant’s UFSAR and noted that Table 6.1-2 states that core spray and 

RHR system LPCI valves can be constructed of CASS material. By letter dated August 18, 

2010, the staff issued RAI 3.2.1.20-01 requesting that the applicant state whether any of the 

core spray and RHR system LPCI RCPB valves or valves located inside the primary 

containment are constructed of CASS material or exposed to a temperature greater 250 °C 

(482 °F). In its response dated September 1, 2010, the applicant stated that it conducted a 

confirmatory review and found that there are no valves constructed of CASS that are exposed to 

an operating environment greater 250 °C (482 °F) during normal operation in the core spray and 

RHR LPCI systems. The staff finds the applicant’s response acceptable because it performed a 

confirmatory review for the specific material and temperature limit as requested by the staff, and 

no valves constructed of CASS material exposed to an operating environment greater 250 °C 

(482 °F) during normal operation exists in the core spray and RHR LPCI systems. The staff 

confirmed that no in-scope CASS piping, piping components, and piping elements exposed to 

treated water (borated or unborated) greater than 250 °C (482 °F) are present in the ESF 

systems and, therefore, the staff finds the applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1-21 addresses high-strength steel closure bolting exposed to air with 

steam or water leakage in the ESF systems. The GALL Report recommends the use of GALL 

AMP XI.M18, “Bolting Integrity,” to manage cracking due to cyclic loading or SCC for this 

component group. The applicant stated that this item is not applicable because there is no 

high-strength closure bolting in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 

3.2 and confirmed that the applicant’s LRA does not have any AMR results for the ESF systems 

that include high-strength steel closure bolting exposed to air with steam or water leakage. The 

staff reviewed the applicant’s UFSAR and confirmed that no in-scope high-strength steel closure 

bolting exposed to air with steam or water leakage is present in the ESF systems and, therefore, 

the staff finds the applicant’s determination acceptable. 

LRA Table 3.2.1, item 3.2.1-22 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends the use of GALL AMP XI.M18, “Bolting 

Integrity,” to manage loss of material due to general corrosion for this component group. The 

applicant stated that this item is not applicable because the AMR methodology for steel closure 

bolting predicts pitting and crevice corrosion, in addition to general corrosion, and as a result, 

item 3.2.1-23 is credited for this component instead. The staff evaluated the applicant’s claim 

and found it acceptable because the applicant: (1) identified the loss of material due to general, 

pitting, and crevice corrosion which is a more conservative approach than the loss of material 

due to general corrosion for this component group and (2) has credited an alternate Table 1, 

item 3.2.1-23 to manage this component group. 

LRA Table 3.2.1, item 3.2.1-32 addresses loss of material due to general corrosion in steel 

piping and ducting components and internal surfaces exposed internally to uncontrolled indoor 

air. The applicant stated that this line item is not applicable because AMR methodology 
Aging Management Review Results 

 3-267 

assumes internal surfaces are exposed to an air/gas-wetted environment, which includes 

condensation, and as a result, item 3.2.1-34 is credited for this component instead. The staff 

evaluated the applicant’s claim and found it acceptable because the applicant credited an 

alternate item 3.2.1-34 to manage this component group, which is being managed for loss of 

material due to pitting and crevice corrosion, in addition to general corrosion. 

LRA Table 3.2.1, item 3.2.1-33 addresses loss of material due to general, pitting, and crevice 

corrosion in steel encapsulation components exposed internally to uncontrolled indoor air. The 

applicant stated that this line item is not applicable because there are no steel encapsulation 

components exposed to indoor uncontrolled air in the ESF system. The staff reviewed LRA 

Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA does not have any AMR results 

for the ESF system that include steel encapsulation components exposed internally to 

uncontrolled indoor air. The staff also reviewed the applicant’s UFSAR and confirmed that no 

in-scope steel encapsulation components exposed internally to uncontrolled indoor air are 

present in the ESF system and, therefore, the staff finds the applicant’s determination 

acceptable. 

3.2.2.1.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

LRA Table 3.2.1, item 3.2.1-23 addresses steel closure bolting exposed to air – outdoor 

(external) or air – indoor uncontrolled (external) which are being managed for loss of material 

due to general, pitting, and crevice corrosion. The LRA credits the ASME Section XI, 

Subsection IWE Program to manage the aging effect. The GALL Report recommends GALL 

AMP XI.M18, “Bolting Integrity,” to ensure that the aging effects are adequately managed. In 

LRA Table 3.5.2-7 (Primary Containment), the applicant aligned AMR results for carbon and low 

alloy steel bolting exposed to air – indoor with item 3.2.1-23. The applicant cited generic note E, 

indicating that the AMR result is consistent with the GALL Report for material, environment, and 

aging effect, but a different AMP is credited. 

The staff reviewed the applicant’s ASME Section XI, Subsection IWE Program and its 

evaluation is documented in SER Section 3.0.3.2.14. During its review of AMR result lines 

associated with components for which the GALL Report recommends the Bolting Integrity 

Program, the staff noted that several other programs were identified to manage aging for bolting 

in the LRA. The staff issued RAI B.2.1.12-01 requesting that the applicant explain why 

programs other than the Bolting Integrity Program were credited to manage aging for structural 

bolting. 

In it response, which is evaluated in SER Section 3.0.3.2.4, the applicant added a number of 

AMR result lines, including some associated with LRA Table 3.2.1, item 3.2.1-23. The added 

AMR result lines credit the Bolting Integrity Program, in addition to the previously credited 

program, to manage loss of material due to general, pitting, and crevice corrosion and cite 

generic note B, indicating that the results are consistent with the GALL Report for component, 

material, environment, and aging effect, but the AMP takes some exception(s) to the GALL 

Report. The staff finds the applicant’s proposed combination of programs acceptable to 

manage aging for these components because: (1) the programs include visual inspections of 

bolting which are capable of detecting loss of preload, (2) the use of the Bolting Integrity 

Program is consistent with the recommendations in the GALL Report, and (3) supplementing 

the inspections performed by the Bolting Integrity Program with inspections performed by the 

ASME Section XI, Subsection IWE Program provides a more comprehensive approach to 

monitoring aging for these components. 
Aging Management Review Results 

 3-268 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.2.2.1.3 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 being managed for loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion and fouling. The LRA credits the Fire 

Water System Program for stainless steel flow elements, strainers, electric heaters, piping and 

fittings, and valves bodies in the fire protection system. The GALL Report recommends GALL 

AMP XI.M20, “Open-Cycle Cooling Water System Program,” to ensure that these aging effects 

are adequately managed. The AMR line items cite generic note E. The LRA also cites 

plant-specific note 5, indicating that the Fire Water System program is substituted to manage 

the aging effect applicable to this component type, material, and environment combination. 

GALL AMP XI.M20 relies on implementation of the recommendations of GL 89-13, which 

includes using preventive measures (i.e., water chemistry control), periodic visual inspections, 

and performance testing to manage these aging effects. In its review of components associated 

with item 3.2.1-38 for which the applicant cited generic note E, the staff noted that the applicant 

credited the Fire Water System Program to manage aging for these stainless steel components 

in LRA Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Water System Program and its evaluation is documented 

in SER Section 3.0.3.2.8. The staff noted that the Fire Water System Program proposes to 

manage the aging effects of the stainless steel components in the fire protection system through 

the use of preventive measures (including non-intrusive volumetric examinations), periodic 

inspections, performance monitoring, and performance testing to ensure that aging effects are 

managed and that wall thickness is maintained within acceptable limits. The staff finds the 

applicant’s proposed program acceptable to manage aging for these components because: 

(1) the Fire Water System Program includes preventive measures to detect aging prior to loss of 

function, performance monitoring, and periodic visual inspections which are as effective as the 

GALL Report recommended AMP at managing aging for these components; and (2) the 

components are in the fire protection system and are not within the scope of GL 89-13 and, 

therefore, GALL AMP XI.M20 would not apply. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.2.1, item 3.2.1-38 addresses stainless steel containment isolation piping and 

component 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 LRA credits 

the Periodic Inspection Program to manage aging for components in the equipment and floor 

drainage and radwaste systems. The GALL Report recommends GALL AMP XI.M20, 

“Open-Cycle Cooling Water System,” to ensure that these aging effects are adequately 

managed. The AMR line items cite generic note E, which indicate that the line item is consistent 
Aging Management Review Results 

 3-269 

with the GALL Report for the material, environment, and aging effect, but a different AMP is 

credited. 

GALL AMP XI.M20 recommends preventive measures including proper selection of materials 

and coatings, periodic flushes and cleaning, and raw water chemistry control, as well as visual 

inspections and NDE testing for components exposed to open-cycle cooling water. Open-cycle 

cooling water is water that transfers heat from safety-related components to the ultimate heat 

sink. 

The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is documented 

in SER Section 3.0.3.3.2. The staff noted that the Periodic Inspection Program includes 

periodic visual inspections of components and ultrasonic wall thickness measurements to detect 

loss of material and fouling. The staff also notes that the equipment and floor drainage and 

radwaste systems do not contain safety-related components exposed to open-cycle cooling 

water, so use of the Open-Cycle Cooling Water Program would not be appropriate. The staff 

finds the applicant’s use of the Periodic Inspection Program acceptable for managing aging of 

these components because it performs periodic visual inspections and wall thickness 

measurements that are appropriate to detect loss of material and fouling. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.2.2.1.4 Loss of Preload Due to Thermal Effects, Gasket Creep, and Self-Loosening 

LRA Table 3.2.1, item 3.2.1-24 addresses steel closure bolting exposed to air – indoor 

uncontrolled (external) which is being managed for loss of preload due to thermal effects, 

gasket creep, and self-loosening. The LRA credits the ASME Section XI, Subsection IWE 

Program and the 10 CFR Part 50, Appendix J Program to manage the aging effect. The GALL 

Report recommends GALL AMP XI.M18, “Bolting Integrity,” to ensure that the aging effects are 

adequately managed. In LRA Table 3.5.2-7 (Primary Containment), the applicant aligned AMR 

results for carbon and low alloy steel bolting exposed to air – indoor with item 3.2.1-24. The 

applicant cited generic note E, indicating that the AMR result is consistent with the GALL Report 

for material, environment, and aging effect, but a different AMP is credited. 

The staff reviewed the applicant’s ASME Section XI, Subsection IWE Program and the 

10 CFR Part 50, Appendix J Program and its evaluations are documented in SER 

Sections 3.0.3.2.14, and 3.0.3.1.16, respectively. During its review of AMR result lines 

associated with components for which the GALL Report recommends the Bolting Integrity 

Program, the staff noted that several other programs were identified to manage aging for bolting 

in the LRA. The staff issued RAI B.2.1.12-01 requesting that the applicant explain why 

programs other than the Bolting Integrity Program were credited to manage aging effects in 

structural bolting. 

In it response, which is evaluated in SER Section 3.0.3.2.4, the applicant added a number of 

AMR result lines, including some associated with LRA Table 3.2.1, item 3.2.1-24. The added 

AMR result lines credit the Bolting Integrity Program, in addition to the previously credited 

program, to manage loss of preload due to thermal effects, gasket creep, and self-loosening 

and cite Note B, indicating that the results are consistent with the GALL Report for component, 

material, environment, and aging effect, but the AMP takes some exception(s) to the GALL 
Aging Management Review Results 

 3-270 

Report. The staff finds the applicant’s proposed combination of programs acceptable to 

manage aging for these components because: (1) the programs include visual inspections of 

bolting which are capable of detecting loss of preload, (2) the use of the Bolting Integrity 

Program is consistent with the recommendations in the GALL Report, and (3) supplementing 

the inspections performed by the Bolting Integrity Program with inspections performed by the 

ASME Section XI, Subsection IWE Program and 10 CFR Part 50, Appendix J Program provides 

a more comprehensive approach to monitoring aging for these components. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.2.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further 

Evaluation Is Recommended 

LRA Section 3.2.2.2 provides further evaluation of aging management as recommended by the 

GALL Report for the ESF components. The applicant provided information concerning how it 

will manage the following aging effects: 

● cumulative fatigue damage 

● loss of material due to cladding 

● 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 

● 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 microbiologically-influenced 

corrosion 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which further evaluation is recommended, the staff 

audited and reviewed the applicant’s evaluations to determine whether they adequately address 

those issues. In addition, the staff reviewed the applicant’s further evaluations against the 

criteria in SRP-LR Section 3.2.2.2. The staff’s review of the applicant’s further evaluation 

follows. 
Aging Management Review Results 

 3-271 

3.2.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.2.2.2.1 addresses the applicant’s AMR basis for managing cumulative fatigue 

damage in ESF system components that were designed to applicable design analysis criteria in 

the ASME Code Section III, Articles NC-3000 or ND-3000 (as applicable to Code Class 2 or 3 

components, respectively) or in the American National Standards Institute (ANSI) B31.1 Code, 

and for which implicit fatigue analyses were required. In this LRA Section, the applicant stated 

that the evaluation of fatigue is a TLAA as defined in 10 CFR 54.3, and that the TLAAs are 

evaluated in accordance with the TLAA acceptance criteria in 10 CFR 54.21(c)(1). The 

applicant stated that metal fatigue as a TLAA for the HPCI, RCIC, and RHR systems is 

discussed in LRA Section 4.3. 

In LRA Table 3.2.1, the applicant stated that AMR item 3.2.1-1 for managing of cumulative 

fatigue damage for the applicant’s ESF components is consistent with the staff’s AMR item 

recommendations in AMR item 1 of Table 2 in the GALL Report, Volume 1, Revision 1. The 

applicant stated that, for these AMRs, cumulative fatigue damage in the components will be 

managed using a TLAA and that LRA Section 4.3.4 describes and evaluates implicit fatigue 

analysis-based TLAAs for these components. 

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 fatigue of ESF components is a TLAA as defined in 10 CFR 54.3, and that 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 the staff’s recommended acceptance criteria and 

review procedures for reviewing these TLAAs in SRP-LR Section 4.3, “Metal Fatigue Analysis.” 

The staff also reviewed LRA Section 3.2.2.2.1 and the AMRs discussed in this section against 

the staff’s AMR items for evaluating cumulative fatigue damage in BWR ESF designs, as given 

in the GALL Report. 

With regard to the applicant’s metal fatigue AMR item 3.2.1-1, the staff noted that AMR item 1 in 

Table 2 of the GALL Report, Volume 1 and AMR item V.D2-32 in the GALL Report, Volume 2 

identify that cumulative fatigue damage is an applicable aging effect for steel and stainless steel 

piping, piping components, and piping elements in the ECCS. The staff also noted that these 

GALL AMRs recommend that the TLAA on metal fatigue be used to manage the impact of 

cumulative fatigue damage in these components. The staff noted that, in conformance with this 

recommendation, the applicant included an applicable line item in LRA Tables 3.2.2-4, 3.2.2-6, 

and 3.2.2-7 for piping, piping components, and piping elements that received ASME Code 

Section III CUF or ANSI B31.1 design code analysis calculations. The staff noted that the 

applicant credited the TLAA analysis in LRA Section 4.3.4 with the management of cumulative 

fatigue damage in these components. The staff found that the applicant’s AMR assessment 

was in conformance with the recommendations both in the SRP-LR and in AMR item 1 of the 

GALL Report, Volume 1, Table 2 and AMR item V.D2-32 in the GALL Report, Volume 2. Based 

on this review, the staff finds the applicant’s AMR analysis on cumulative fatigue damage of 

piping, piping components, and piping elements to be acceptable because it is in conformance 

with the recommendations in SRP-LR Section 3.2.2.2.1 and the GALL AMR items that are 

invoked by this SRP-LR section. The staff evaluates the TLAA analysis for the support skirt and 

attachment welds component in SER Section 4.3.4. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.1 criteria. For those items that apply to LRA Section 3.2.2.2.1, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
Aging Management Review Results 

 3-272 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.2.2.2.2 Loss of Material Due to Cladding 

LRA Section 3.2.2.2.2 refers to Table 3.2.1, item 3.2.1-2 and addresses loss of material due to 

cladding. The applicant stated that this aging effect is not applicable to HCGS, which is a BWR. 

SRP-LR Section 3.2.2.2.2 states that loss of material due to cladding breach could occur for 

PWR steel pump casing with stainless steel cladding exposed to treated borated water. 

SRP-LR Table 3.2-1 identifies item 2 applicable to PWRs. 

The staff verified that SRP-LR Section 3.2.2.2.2 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR steel with 

stainless steel cladding pump casing exposed to treated borated water. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.2.2.2.2 do not apply to HCGS because the guidance is applicable to PWRs. 

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 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 and components internal surfaces exposed 

to treated water which are being managed for loss of material due to pitting and crevice 

corrosion. The applicant stated that this line item is not applicable because its ESF 

system stainless steel containment isolation piping, piping components, and piping 

elements exposed to treated water are evaluated with other Class 1 components under 

LRA Table 3.1.1, item 3.1.1-15. The applicant also stated that the above listed hardware 

is addressed in LRA Section 3.1.2.2.2, item 3, which implements the Water Chemistry 

and the One-Time Inspection Programs to ensure effective aging management 

practices. The staff reviewed LRA Sections 2.3.2 and 3.2, and confirmed that the 

applicant’s LRA addresses loss of material due to pitting and crevice corrosion of 

internal surfaces of stainless steel containment isolation piping, piping components, and 

piping elements exposed to treated water for ESF systems using item 3.1.1-15 and that 

loss of material is managed with the Water Chemistry and One-Time Inspection 

Programs as recommended in the GALL Report. Based on its review of the LRA and 

UFSAR, the staff confirmed that loss of material due to pitting and crevice corrosion of 

internal surfaces of stainless steel containment isolation piping, piping components, and 

piping elements exposed to treated water in the ESF systems is managed under an 

alternate SRP-LR designation with similar acceptance criteria which are consistent with 

the GALL Report and, therefore, the staff finds the applicant’s determination acceptable. 

 (2) LRA Section 3.2.2.2.3.2 refers to Table 3.2.1, item 3.2.1-4 and addresses stainless steel 

piping, piping components, and piping elements exposed to soil. The applicant stated 

that this aging effect is not applicable because HCGS does not have any stainless steel 

piping, piping components, or piping elements exposed to soil in the ESF systems. 

 SRP-LR Section 3.2.2.2.3.2 states that loss of material from pitting and crevice corrosion 

could occur for stainless steel piping, piping components, and piping elements exposed 

to soil. 
Aging Management Review Results 

 3-273 

 The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.2.2.2.3, item 

2 is not applicable to HCGS because HCGS does not have any stainless steel piping, 

piping components, or piping elements exposed to soil in the ESF systems and the staff 

guidance in this SRP-LR section is only applicable to BWRs in the ESF system with 

stainless steel piping, piping components, or piping elements exposed to soil. 

 (3) LRA Section 3.2.2.2.3 is referenced by LRA Table 3.2.1, item 3.2.1-5 and addresses 

stainless steel and aluminum piping, piping components, and 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 applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the One-Time 

Inspection Program will be implemented to verify the effectiveness of the Water 

Chemistry Program to manage the loss of material due to pitting and crevice corrosion in 

stainless steel piping, piping components, and piping elements and tanks exposed to 

treated water in the containment hydrogen recombiner system, core spray system, HPCI 

system, RCIC system, and RHR system. 

 The staff reviewed LRA Section 3.2.2.2.3, item 3 against the criteria in SRP-LR 

Section 3.2.2.2.3, item 3, which states that: (1) loss of material due to pitting and crevice 

corrosion could occur for BWR stainless steel and aluminum piping, piping components, 

and piping elements exposed to treated water; (2) the existing AMP relies on monitoring 

and control of water chemistry to mitigate corrosion; and (3) control of water chemistry 

does not preclude corrosion at locations of stagnant flow conditions. The effectiveness 

of the water chemistry program, therefore, should be verified using a one-time inspection 

to ensure that corrosion does not occur. The GALL Report recommends a one-time 

inspection of select components at susceptible locations as an acceptable method to 

verify the effectiveness of the Water Chemistry Program and ensure that an aging effect 

is not occurring or is progressing very slowly so that the component’s intended function 

will be maintained during the period of extended operation. 

 The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. The 

staff finds the combination of programs acceptable to manage aging for these 

components because the programs: (1) provide for periodic sampling of reactor coolant 

to maintain contaminants at acceptable limits to preclude loss of material due to pitting 

and crevice corrosion; and (2) will perform one-time inspections of stainless steel piping 

components, piping elements, and tanks exposed to treated water. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.3, item 3 criteria. For those line items that apply to LRA 

Section 3.2.2.2.3, item 3, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (4) LRA Section 3.2.2.2.3.4 is associated with Table 3.2.1, item 3.2.1-6 and addresses 

stainless steel and copper alloy piping, piping components, piping elements, and heat 

exchangers exposed to lubricating oil in the HPCI system and RCIC system, 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 requirements by stating that the One-Time Inspection Program will 

be used to verify the effectiveness of the Lubricating Oil Analysis Program. 
Aging Management Review Results 

 3-274 

 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 that loss of material due to pitting and crevice 

corrosion could occur for stainless steel and copper alloy piping, piping components, 

piping elements, and heat exchangers 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. However, control of lube oil 

contaminants may not always have been adequate to preclude corrosion. Therefore, the 

effectiveness of lubricating oil control should be verified to ensure that corrosion does 

not occur. A one-time inspection of select 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 reviewed the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs and their evaluations are documented in SER Sections 3.0.3.2.13 and 

3.0.3.1.11, respectively. In its review of components associated with LRA item 3.2.1-6, 

the staff finds the applicant’s proposal to manage aging using the Lubricating Oil 

Analysis and One-Time Inspection Programs acceptable because: (1) the applicant will 

perform sufficient inspections for each material-environment combination to provide an 

overall assessment of any aging degradation that may be occurring; (2) 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; (3) recurring surveillance and maintenance activities provides the ability 

to detect aging of the material-environment combination prior to loss of function; and 

(4) inspection results will be trended. 

 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 those line items that apply to LRA 

Section 3.2.2.2.3.4, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (5) LRA Section 3.2.2.2.3.5 refers to Table 3.2.1, item 3.2.1-7 and addresses partially 

encased stainless steel tanks with breached moisture barrier exposed to raw water. The 

applicant stated that this aging effect is not applicable because HCGS does not have 

any partially encased stainless steel tanks in the ESF system. 

 SRP-LR Section 3.2.2.2.3.5 states that loss of material from pitting and crevice corrosion 

could occur for partially encased stainless steel tanks exposed to raw water due to 

cracking of the perimeter seal from weathering. 

 The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.2.2.2.3, item 

5 is not applicable to HCGS because HCGS does not have any partially encased 

stainless steel tanks exposed to raw water in the ESF systems and the staff guidance in 

this SRP-LR section is only applicable to BWRs in the ESF system with partially 

encased stainless steel tanks with breached moisture barrier exposed to raw water. 

 (6) LRA Section 3.2.2.2.3, item 6, referenced by LRA Table 3.2.1, item 3.2.1-8, addresses 

stainless steel piping, piping components, piping elements, and tanks exposed to wetted 

air and gas, which are being managed for loss of material due to pitting and crevice 
Aging Management Review Results 

 3-275 

corrosion by the Periodic Inspection Program. The applicant addressed the further 

evaluation criteria by stating that the Periodic Inspection Program includes visual 

inspections and nondestructive volumetric examination of external and internal surfaces 

of non-steel components to ensure that environmental conditions are not causing 

material degradation. 

 The staff reviewed LRA Section 3.2.2.2.3, item 6 against the criteria described in 

SRP-LR Section 3.2.2.2.3, item 6, which states that loss of material due to pitting and 

crevice corrosion could occur for stainless steel piping, piping components, piping 

elements, and tanks exposed to internal condensation. It continues by stating that the 

GALL Report recommends further evaluation of a plant-specific AMP and that the 

acceptance criteria are described in Branch Technical Position RSLB-1. 

 The staff’s evaluation of the applicant’s Periodic Inspection Program is documented in 

SER Section 3.0.3.3.2. In its review of components associated with item 3.2.1-8, the 

staff finds the applicant’s proposal to manage aging using the Periodic Inspection 

Program acceptable because visual inspections and nondestructive volumetric 

examinations can detect the loss of material due to pitting and crevice corrosion, which 

will ensure that existing environmental conditions are not causing material degradation 

that could result in a loss of the component’s intended function. 

 Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.2.2.2.3, item 6 criteria. For those items that apply to LRA 

Section 3.2.2.2.3, item 6, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that 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). 

Based on a review of the programs identified, the staff concludes that the applicant’s programs 

meet SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA 

Section 3.2.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling 

The staff reviewed LRA Section 3.2.2.2.4 against the criteria in SRP-LR Section 3.2.2.2.4. 

 (1) LRA Section 3.2.2.2.4.1 is associated with Table 3.2.1, item 3.2.1-9 and addresses 

steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil in 

the HPCI, RCIC, and the closed-cycle cooling water systems, which are being managed 

for reduction of heat transfer due to fouling by the Lubricating Oil Analysis and One-Time 

Inspection Programs. The applicant addressed the further evaluation requirements by 

stating that the One-Time Inspection Program will be used to verify the effectiveness of 

the Lubricating Oil Analysis Program. 

 The staff reviewed LRA Section 3.2.2.2.4.1 against the criteria in SRP-LR 

Section 3.2.2.2.4, item 1, which states that reduction of heat transfer due to fouling could 

occur for steel, stainless steel, and copper alloy heat exchanger tubes exposed to 

lubricating oil. The SRP-LR also states that the existing program relies on monitoring 
Aging Management Review Results 

 3-276 

and control of lube oil chemistry to mitigate reduction of heat transfer due to fouling. 

However, control of lube oil chemistry may not always have been adequate to preclude 

fouling. Therefore, the effectiveness of lube oil chemistry control should be verified to 

ensure that fouling does not occur. A one-time inspection of select components at 

susceptible locations is an acceptable method to determine whether an aging effect is 

not occurring or an aging effect is progressing very slowly such that the component’s 

intended function will be maintained during the period of extended operation. 

 The staff’s evaluation of the applicant’s Lubricating Oil Analysis Program and One-Time 

Inspection Program is documented in SER Sections 3.0.3.2.13 and 3.0.3.1.11, 

respectively. In its review of components associated with Table 3.2.1, item 3.2.1-9, the 

staff finds the applicant’s proposal to manage aging using the above programs 

acceptable because the Lubricating Oil Analysis Program provides for periodic sampling 

of lubricating oil to maintain contaminants at acceptable limits to preclude loss of heat 

transfer due to fouling. In addition, the One-Time Inspection Program will include a 

sample of susceptible heat exchanger components in low or stagnant flow areas to verify 

the effectiveness of the Lubricating Oil Analysis Program. 

 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 line items that apply to LRA 

Section 3.2.2.2.4.1, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (2) LRA Section 3.2.2.2.4, item 2 is associated with Table 3.2.1, item 3.2.1-10 and 

addresses stainless steel heat exchanger tubes exposed to treated water. The GALL 

Report recommends the Water Chemistry and One-Time Inspection programs to 

manage reduction of heat transfer for this component group. The applicant stated that 

this item is not applicable because, other than the RHR system, HCGS has no in-scope 

stainless steel heat exchanger tubes exposed to treated water in the ESF systems, and 

that the stainless steel heat exchanger components in the RHR system have been 

evaluated with the closed-cycle cooling water system components in Table 3.3.1, 

item 3.3.1-3. 

 The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant’s LRA 

does not have any AMR results for the ESF systems that include stainless steel heat 

exchanger tubes exposed to treated water in the ESF systems. The staff also reviewed 

the UFSAR and confirmed that, other than the RHR system, there are no in-scope heat 

exchangers constructed of stainless steel exposed to treated water in the ESF systems, 

and these components in the RHR system are further evaluated in LRA 

Section 3.3.2.2.2, therefore, the staff finds the applicant’s determination acceptable. 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.2.2.2.4 criteria. For those line items that apply to LRA 

Section 3.2.2.2.4, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-277 

3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5. 

LRA Section 3.2.2.2.5 refers to Table 3.2.1, item 3.2.1-11 and addresses elastomer seals and 

components (door seals and flexible connections) in the filtration, recirculation, and ventilation 

system exposed to air – indoor uncontrolled or to an air/gas – wetted environment. The 

applicant stated that hardening and loss of strength in these components will be managed by 

the Periodic Inspection Program. The applicant addressed the further evaluation requirement 

by stating that the Periodic Inspection Program is used to manage aging effects of components 

that are not covered by other AMPs, including external and internal surfaces of non-steel 

components, and that the Periodic Inspection Program includes visual inspections and physical 

manipulation of elastomer components. 

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5, which 

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 air – indoor uncontrolled. The GALL Report recommends 

further evaluation of a plant-specific AMP to ensure that these aging effects are adequately 

managed. 

The staff reviewed a description of the applicant’s filtration, recirculation, and ventilation system 

in LRA Section 2.3.2.4 and in the applicant’s UFSAR Section 6.8. The staff noted that the 

system is an ESF with intended functions equivalent to standby gas treatment systems at other 

BWRs. On this basis, the staff found the applicant’s alignment of the filtration, recirculation, and 

ventilation system with item 3.2.1-11 to be acceptable. 

The staff reviewed the applicant’s Periodic Inspection Program, and its evaluation is 

documented in SER Section 3.0.3.3.2. In its review of components associated with LRA 

item 3.3.1-11, for which the applicant assigned generic note E, the staff noted that the Periodic 

Inspection Program is a plant-specific program that proposes to detect the aging of elastomer 

door seals and flexible connections through the use of visual inspections and physical 

manipulations. The staff finds the applicant’s proposal to manage aging using the Periodic 

Inspection Program acceptable because the program performs visual inspections and physical 

manipulations that are capable of detecting hardening and loss of strength in elastomer 

components; and the program initiates corrective actions, implemented through the applicant’s 

corrective action program, if indications of age-related degradation are found. 

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.2.2.2.5 criteria. For those line items that apply to LRA Section 3.2.2.2.5, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.2.2.2.6 Loss of Material Due to Erosion 

LRA Section 3.2.2.2.6 refers to Table 3.2.1, item 3.2.1-12 and addresses loss of material due to 

erosion. The applicant stated that this aging effect is not applicable to HCGS, which is a BWR. 
Aging Management Review Results 

 3-278 

SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion could occur in the stainless 

steel HPSI pump miniflow recirculation orifice exposed to treated borated water. SRP-LR 

Table 3.2-1 identifies item 12 applicable to PWRs. 

The staff verified that SRP-LR Section 3.2.2.2.6 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR stainless steel 

HPSI pump miniflow orifices exposed to treated borated water. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.2.2.2.6 do not apply to HCGS because the guidance is applicable to PWRs. 

3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling 

The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7. 

LRA Section 3.2.2.2.7 is associated with Table 3.2.1, item 3.2.1-13 and addresses steel drywell 

and suppression chamber spray system nozzle and flow orifice internal surfaces exposed to 

indoor uncontrolled air which are being managed for loss of material due to general corrosion 

and fouling. The applicant stated that this line item is not applicable because it has no steel 

spray nozzles in its ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and 

confirmed that the applicant’s LRA does not have any AMR results for the ESF systems that 

include steel spray nozzles. The staff also reviewed the applicant’s UFSAR and confirmed that 

no in-scope steel spray nozzles are present in the ESF systems and, therefore, the staff finds 

the applicant’s determination acceptable. 

Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.7 criteria do not apply. 

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 criteria in SRP-LR Section 3.2.2.2.8. 

 (1) LRA Section 3.2.2.2.8, item 1, referenced by LRA Table 3.2.1, item 3.2.1-14 and 

addresses steel piping, piping components, and piping elements exposed to treated 

water 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 applicant 

addressed the further evaluation criteria of the SRP-LR by stating that it will implement a 

One-Time Inspection Program to verify the effectiveness of the Water Chemistry 

Program to manage loss of material due to general, pitting, and crevice corrosion of 

steel piping, piping components, and elements and tanks exposed to treated water at 

susceptible locations (containment hydrogen recombiner, core spray, HPCI, RCIC, and 

RHR systems). 

 The staff reviewed LRA Section 3.2.2.2.8, item 1 against the criteria in SRP-LR 

Section 3.2.2.2.8, item 1, which states that: (1) loss of material due to general, pitting, 

and crevice corrosion could occur for BWR steel piping, piping components, and piping 

elements exposed to treated water; (2) the existing AMP relies on monitoring and control 

of water chemistry to mitigate corrosion; and (3) control of water chemistry does not 

preclude corrosion at locations of stagnant flow conditions. The effectiveness of the 

water chemistry program, therefore, should be verified using a one-time inspection to 

ensure that corrosion does not occur. The GALL Report recommends a one-time 

inspection of select components at susceptible locations as an acceptable method to 
Aging Management Review Results 

 3-279 

verify the effectiveness of the Water Chemistry Program and ensure that an aging effect 

is not occurring or is progressing very slowly so that the component’s intended function 

will be maintained during the period of extended operation. 

 The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection 

programs are documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. The 

staff finds this combination of programs acceptable to manage aging for these 

components because the programs: (1) provide for periodic sampling of treated water to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 

pitting, and crevice corrosion; and (2) will perform one-time inspections of steel, piping 

components, piping elements, and tanks exposed to treated water. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.8, item 1 criteria. For those line items that apply to LRA 

Section 3.2.2.2.8, item 1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (2) LRA Section 3.2.2.2.8, item 2, referenced by LRA Table 3.2.1, item 3.2.1-15, addresses 

steel containment isolation piping, piping components, and piping elements exposed to 

treated water. The GALL Report, Table 3.2.1, item 3.2.1-15 recommends the water 

chemistry and one-time inspection programs to manage the loss of material on the 

internal surfaces due to general, pitting, and crevice corrosion for this component group. 

The applicant stated that this item was not applicable because the related components 

in the ESF systems are evaluated with other Class 1 components, as addressed in 

Table 3.1.1, item 3.1.1-13 and with other non-reactor coolant pressure boundary 

components, as addressed in Table 3.2.1, item 3.2.1-14. The staff evaluated the 

applicant’s claim and found it acceptable because the comparable components in the 

ESF systems reference either Table 3.1.1, item 3.1.1-13 or Table 3.2.1, item 3.2.1-14, 

which are further evaluated in SER Section 3.1.2.2.2, item 2 and Section 3.2.2.2.8, 

item 1, respectively. In addition, both these items use the Water Chemistry and 

One-Time Inspection programs, which are the same as those recommended for 

Table 3.2.1, item 3.2.1-15. 

 (3) LRA Section 3.2.2.2.8.3 is associated with Table 3.2.1, item 3.2.1-16 and addresses 

steel piping, piping components, and piping elements exposed to lubricating oil in the 

HPCI and RCIC systems, 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 requirements by stating that 

the One-Time Inspection Program will be used to verify the effectiveness of the 

Lubricating Oil Analysis Program. 

 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 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. 

However, control of lube oil contaminants may not always have been adequate to 

preclude corrosion. Therefore, the effectiveness of lubricating oil control should be 

verified to ensure that corrosion does not occur. A one-time inspection of select 
Aging Management Review Results 

 3-280 

components at susceptible locations is an acceptable method to determine whether an 

aging effect is not occurring or an aging effect is progressing very slowly such that the 

component’s intended function will be maintained during the period of extended 

operation. 

 The staff reviewed the applicant’s Lubricating Oil Analysis and One-Time Inspection 

programs and their evaluations are documented in SER Sections 3.0.3.2.13 and 

3.0.3.1.11, respectively. In its review of components associated with LRA item 3.2.1-16, 

the staff finds the applicant’s proposal to manage aging using the Lubricating Oil 

Analysis and One-Time Inspection programs acceptable because: (1) the applicant will 

perform sufficient inspections for each material-environment combination to provide an 

overall assessment of any aging degradation that may be occurring; (2) 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; (3) recurring surveillance and maintenance activities provides the ability 

to detect aging of the material-environment combination prior to loss of function; and 

(4) inspection results will be trended. 

 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 those line items that apply to LRA 

Section 3.2.2.2.8.3, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.2.2.2.8 criteria. For those line items that apply to LRA 

Section 3.2.2.2.8, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

LRA Section 3.2.2.2.9 refers to Table 3.2.1, item 3.2.1-17 and addresses loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion. The applicant stated that 

this aging effect is not applicable because HCGS does not have any steel (with or without 

coating or wrapping) piping, piping components, or piping elements buried in soil in the ESF 

systems. 

SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion could occur for steel (with or without coating or wrapping) 

piping, piping components, and piping elements buried in soil. 

The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.2.2.2.9 is not 

applicable to HCGS because HCGS does not have any steel (with or without coating or 

wrappings) piping, piping components, or piping elements buried in soil in the ESF systems and 

the staff guidance in this SRP-LR section is only applicable to BWRs in the ESF system with 
Aging Management Review Results 

 3-281 

steel (with or without coating or wrappings) piping, piping components, or piping elements 

buried in soil. 

3.2.2.2.10 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. 

3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.2.2-1 through 3.2.2-8, 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 3.2.2-1 through 3.2.2-8, the applicant indicated, via Notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to a 

line 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 line 

item component is not evaluated in the GALL Report. Note G indicates that the environment for 

the AMR line item component and material is not evaluated in the GALL Report. Note H 

indicates that the aging effect for the AMR line 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 line item component, material, and environment 

combination is not applicable. Note J indicates that neither the component nor the material and 

environment combination for the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant had 

demonstrated that the aging effects will be adequately managed so that the intended function(s) 

will be maintained consistent with the CLB during the period of extended operation. The staff’s 

evaluation is discussed in the following sections. 

3.2.2.3.1 Engineered Safety Features – Containment Hydrogen Recombiner System – 

Summary of Aging Management Evaluation – LRA Table 3.2.2-1 

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the 

containment hydrogen recombiner system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.2.2.1. 

3.2.2.3.2 Engineered Safety Features – Core Spray System – Summary of Aging Management 

Evaluation – LRA Table 3.2.2-2 

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the 

core spray system component groups. 
Aging Management Review Results 

 3-282 

In LRA Table 3.2.2-2, the applicant stated that stainless steel bolting components exposed to 

treated water are being managed for loss of material due to pitting and crevice corrosion and 

loss of preload due to thermal effects, gasket creep, and self-loosening by the Bolting Integrity 

Program. The AMR line items cite generic note G, which indicate that the environment is not 

addressed in the GALL Report for this component and material. 

The staff reviewed the applicant’s Bolting Integrity Program and its evaluation is documented in 

SER Section 3.0.3.2.4. The staff finds the applicant’s Bolting Integrity Program acceptable to 

manage loss of material and loss of preload for these components because it performs visual 

inspections of bolting for pressure retaining components for visible leakage and fastener 

degradation to detect loss of material and loss of preload; and it has incorporated industry 

guidance on good bolting practices into its installation procedures. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.3.3 Engineered Safety Features – Filtration, Recirculation, and Ventilation System– 

Summary of Aging Management Evaluation – LRA Table 3.2.2-3 

In LRA Table 3.2.2-3, the applicant stated that polymer ducting and components exposed to air 

– indoor (external) or air/gas – wetted (internal) have no AERM and that for this component, 

material, and environment combination, no AMP is needed. The AMR line items cite generic 

note F, indicating that the material is not in the GALL Report for this component. 

The staff reviewed all material entries in the GALL Report and confirmed that polymer material 

is not included in the GALL Report. For these AMR results, the applicant also cited 

plant-specific note 3, stating that: 

The polymer (plexiglass) material located indoors and subject to an indoor air or 

air-gas (wetted) environment is not subject to significant aging effects. Polymer 

materials do not experience aging effects unless exposed to temperatures, 

radiation, or chemicals capable of attacking the specific polymer chemical 

composition[.] Polymer materials are selected for compatibility with the 

environment during the design, and if properly selected[,] will not experience 

significant degradation. Polymer (plexiglass) material in this non-aggressive air 

environment is not expected to experience significant aging effects. This is 

consistent with plant operating experience. 

Based on its review of technical literature (e.g., Roff, W.J., Fibres, Plastics, and Rubbers: A 

Handbook of Common Polymers, Academic Press Inc., New York, 1956), and current industry 

research and operating experience related to plexiglass and related polymers, the staff has 

determined that, in the absence of specific environmental stressors such as ultraviolet light, high 

radiation, or ozone concentrations, components made of these materials do not exhibit aging 

effects of concern during the period of extended operation. The staff has determined that for 

plexiglass and related polymer components in a plant indoor air or air/gas – wetted 

environment, there are no aging effects that cause degradation of the components during the 

period of extended operation. On the basis that the subject components have no aging effects 

that cause degradation during the period of extended operation, the staff finds the applicant’s 
Aging Management Review Results 

 3-283 

AMR results for these components, indicating that no AERM and no AMP is needed, to be 

acceptable. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging 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). 

3.2.2.3.4 Engineered Safety Features – High Pressure Coolant Injection System – Summary of 

Aging Management Evaluation – LRA Table 3.2.2-4 

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the 

HPCI system component groups. 

In LRA Table 3.2.2-4, the applicant stated that stainless steel bolting components exposed to 

treated water are being managed for loss of material due to pitting and crevice corrosion and 

loss of preload due to thermal effects, gasket creep, and self-loosening by the Bolting Integrity 

Program. The AMR line items cite generic note G, which indicate that the environment is not 

addressed in the GALL Report for this component and material. 

The staff reviewed the applicant’s Bolting Integrity Program and its evaluation is documented in 

SER Section 3.0.3.2.4. The staff finds the applicant’s Bolting Integrity Program acceptable to 

manage loss of material and loss of preload for these components because it performs visual 

inspections of bolting for pressure retaining components for visible leakage and fastener 

degradation to detect loss of material and loss of preload; and it has incorporated industry 

guidance on good bolting practices into its installation procedures. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.3.5 Engineered Safety Features – Hydrogen and Oxygen Analyzer System – Summary of 

Aging Management Evaluation – LRA Table 3.2.2-5 

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the 

hydrogen and oxygen analyzer system component groups. 

In LRA Table 3.2.2-5, the applicant stated that air cooled stainless steel heat exchanger 

components exposed externally to indoor air and internally to wetted air or gas are being 

managed for reduction of heat transfer and fouling by the Periodic Inspection Program. The 

AMR line item for exposure to indoor air cites generic note G, which indicates that the 

environment is not addressed in the GALL Report for this component and material. The AMR 

line item for exposure to wetted air or gas cites generic note H, which indicates that the aging 

effect is not addressed in the GALL Report for this component, material, and environment 

combination. 
Aging Management Review Results 

 3-284 

The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is documented 

in SER Section 3.0.3.3.2. The staff finds the applicant’s Periodic Inspection Program 

acceptable to manage reduction of heat transfer and fouling for these components because it 

performs visual inspections of heat transfer surfaces which are capable of detecting reduction of 

heat transfer and fouling. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.3.6 Engineered Safety Features – Reactor Core Isolation Cooling System– Summary of 

Aging Management Evaluation – LRA Table 3.2.2-6 

In LRA Table 3.2.2-6, the applicant stated that stainless steel bolting components exposed to 

treated water are being managed for loss of material due to pitting and crevice corrosion and 

loss of preload due to thermal effects, gasket creep, and self-loosening by the Bolting Integrity 

Program. The AMR line items cite generic note G, which indicates that the environment is not 

addressed in the GALL Report for this component and material. 

The staff reviewed the applicant’s Bolting Integrity Program and its evaluation is documented in 

SER Section 3.0.3.2.4. The staff finds the applicant’s Bolting Integrity Program acceptable to 

manage loss of material and loss of preload for these components because it performs visual 

inspections of bolting for pressure retaining components for visible leakage and fastener 

degradation to detect loss of material and loss of preload; and it has incorporated industry 

guidance on good bolting practices into its installation procedures. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.3.7 Engineered Safety Features – Residual Heat Removal System – Summary of Aging 

Management Evaluation – LRA Table 3.2.2-7 

In LRA Table 3.2.2-7, the applicant stated that stainless steel bolting components exposed to 

treated water are being managed for loss of material due to pitting and crevice corrosion and 

loss of preload due to thermal effects, gasket creep, and self-loosening by the Bolting Integrity 

Program. The AMR line items cite generic note G, which indicates that the environment is not 

addressed in the GALL Report for this component and material. 

The staff reviewed the applicant’s Bolting Integrity Program and its evaluation is documented in 

SER Section 3.0.3.2.4. The staff finds the applicant’s Bolting Integrity Program acceptable to 

manage loss of material and loss of preload for these components because it performs visual 

inspections of bolting for pressure retaining components for visible leakage and fastener 

degradation to detect loss of material and loss of preload; and it has incorporated industry 

guidance on good bolting practices into its installation procedures. 
Aging Management Review Results 

 3-285 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.3.8 Engineered Safety Features – Vacuum Relief Valve System – Summary of Aging 

Management Evaluation – LRA Table 3.2.2-8 

The staff reviewed LRA Table 3.2.2-8, which summarizes the results of AMR evaluations for the 

vacuum relief valve system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.2.2.1. 

3.2.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the ESF system components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-286 

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

auxiliary systems components and component groups of the: 

● chilled water system 

● closed-cycle cooling water system 

● compressed air system 

● containment inerting and purging system 

● control area chilled water system 

● control rod drive system 

● control room and control area HVAC systems 

● cranes and hoists 

● equipment and floor drainage system 

● fire protection system 

● fire pump house ventilation system 

● fresh water supply system 

● fuel handling and storage system 

● fuel pool cooling and cleanup system 

● hardened torus vent system 

● hydrogen water chemistry system 

● leak detection and radiation monitoring system 

● makeup demineralizer system 

● primary containment instrument gas system 

● primary containment leakage rate testing system 

● process and post-accident sampling system 

● radwaste system 

● reactor building ventilation system 

● reactor water cleanup system 

● remote shutdown panel room HVAC system 

● service water intake ventilation system 

● service water system 

● standby diesel generator area ventilation systems 

● standby diesel generators and auxiliary systems 

● standby liquid control system 

● torus water cleanup system 

● traversing incore probe system 

3.3.1 Summary of Technical Information in the Application 

LRA Section 3.3 provides AMR results for the auxiliary systems components and component 

groups. LRA Table 3.3.1, “Summary of Aging Management Evaluations for the Auxiliary 

Systems,” is a summary comparison of the applicant’s AMRs with those evaluated in the GALL 

Report for the auxiliary systems components 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 
Aging Management Review Results 

 3-287 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.3.2 Staff Evaluation 

The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for auxiliary system components within the 

scope of license renewal and subject to an AMR, will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

The staff conducted an onsite audit of AMPs to ensure the applicant’s claim that certain AMPs 

were consistent with the GALL Report. The purpose of this audit was to examine the applicant’s 

AMPs and related documentation and to verify the applicant’s claim of consistency with the 

corresponding GALL Report AMPs. The staff did not repeat its review of the matters described 

in the GALL Report. The staff’s evaluations of the AMPs are documented in SER Section 3.0.3. 

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 Sections 3.3.2.1 and 3.3.2.2. 

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. 

The review evaluated whether all plausible aging effects were identified and whether the aging 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff’s evaluation are discussed in SER Section 3.3.2.3. 

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line items and the plant’s operating experience to 

verify the applicant’s claims. 

Table 3.3-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.3 and addressed in the GALL Report. 
Aging Management Review Results 

 3-288 

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 air – 

indoor uncontrolled 

(external) 

(3.3.1-1)

Cumulative fatigue 

damage

TLAA to be 

evaluated for 

structural girders of 

cranes. See 

SRP-LR Section 4.7 

for generic guidance 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes TLAA Fatigue is a TLAA 

(See SER 

Section 3.3.2.2.1) 

Steel and stainless 

steel piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to air – 

indoor 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 Fatigue is a TLAA 

(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 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.2) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to sodium 

pentaborate 

solution > 60 °C 

(140 °F) 

(3.3.1-4) 

Cracking due to 

SCC 

Water Chemistry and 

One-Time Inspection

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.3.2.2.3) 

Stainless steel and 

stainless clad steel 

heat exchanger 

components 

exposed to treated 

water > 60 °C 

(140 °F) 

(3.3.1-5) 

Cracking due to 

SCC 

A plant-specific AMP 

is to be evaluated. 

Yes Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.3) 
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 

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 Periodic Inspection Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.3) 

Stainless steel 

non-regenerative 

heat exchanger 

components 

exposed to treated 

borated water 

> 60 °C (140 °F) 

(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 Not applicable Not applicable to 

BWRs (See SER 

Section 3.3.2.2.4) 

Stainless steel 

regenerative heat 

exchanger 

components 

exposed to treated 

borated water 

> 60 °C (140 °F) 

(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 

SCC and cyclic 

loading. A 

plant-specific AMP is 

to be evaluated. 

Yes Not applicable Not applicable to 

BWRs (See SER 

Section 3.3.2.2.4) 

Stainless steel 

high-pressure pump 

casing in PWR 

chemical and 

volume control 

system 

(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 Not applicable Not applicable to 

BWRs (See SER 

Section 3.3.2.2.4) 

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 

HCGS (See SER 

Section 3.3.2.2.4) 
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

Elastomer seals 

and components 

exposed to air – 

indoor 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 Periodic Inspection 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 Not applicable Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.5) 

Boral®, boron steel 

spent fuel storage 

racks 

neutron-absorbing 

sheets exposed to 

treated water or 

treated borated 

water 

(3.3.1-13) 

Reduction of 

neutron-absorbing 

capacity and loss 

of material due to 

general corrosion 

A plant-specific AMP 

is to be evaluated. 

Yes Boral Monitoring 

Program and Water 

Chemistry 

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 

One-Time 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 

One-Time Inspection

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.3.2.2.7) 

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 

One-Time Inspection 

to evaluate the 

thickness of the 

lower portion of the 

tank 

Yes Not applicable Not applicable to 

HCGS (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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.7) 
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 diesel engine 

exhaust piping, 

piping components, 

and piping elements 

exposed to diesel 

exhaust 

(3.3.1-18) 

Loss of 

material/general 

(steel only), pitting, 

and crevice 

corrosion 

A plant-specific AMP 

is to be evaluated. 

Yes Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

Periodic Inspection 

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 

microbiologicallyinfluenced 

corrosion 

Buried Piping and 

Tanks Surveillance 

or 

Buried Piping and 

Tanks Inspection 

No 

Yes 

Buried Piping 

Inspection 

Aboveground Steel 

Tanks; RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”; and 

Structures 

Monitoring Program 

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 

microbiologicallyinfluenced 

corrosion and 

fouling 

Fuel Oil Chemistry 

and One-Time 

Inspection 

Yes Fuel Oil Chemistry 

and One-Time 

Inspection 

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 

microbiologicallyinfluenced 

corrosion and 

fouling 

Lubricating Oil 

Analysis and 

One-Time Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.9) 

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 

HCGS (See SER 

Section 3.3.2.2.10)
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

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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.10)

Copper alloy HVAC 

piping, piping 

components, 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 Periodic Inspection 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 

One-Time Inspection

Yes Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.10)

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 Periodic Inspection 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 Fire Water System Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.10)
Aging Management Review Results 

 3-293 

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 soil 

(3.3.1-29) 

Loss of material 

due to pitting and 

crevice corrosion 

A plant-specific AMP 

is to be evaluated. 

Yes Not applicable Not applicable to 

HCGS (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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(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 

microbiologicallyinfluenced 

corrosion 

Fuel Oil Chemistry 

and One-Time 

Inspection 

Yes Fuel Oil Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.2.12)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.3.1-33) 

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 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 air – 

indoor uncontrolled 

(internal or external) 

(3.3.1-34) 

Loss of material 

due to wear 

A plant-specific AMP 

is to be evaluated. 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.3.2.2.13)
Aging Management Review Results 

 3-294 

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 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 Not applicable Not applicable to 

BWRs (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 

neutron-absorbing 

capacity due to 

boraflex 

degradation 

Boraflex Monitoring No Not applicable Not applicable to 

HCGS (See SER 

Section 3.3.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60 °C 

(140 °F) 

(3.3.1-37) 

Cracking due to 

SCC and IGSCC 

BWR Reactor Water 

Cleanup System 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.3.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60 °C 

(140 °F) 

(3.3.1-38) 

Cracking due to 

SCC 

BWR Stress 

Corrosion Cracking 

and Water Chemistry

No BWR Stress 

Corrosion Cracking 

and Water 

Chemistry 

Consistent with 

GALL Report 

Stainless steel 

BWR spent fuel 

storage racks 

exposed to treated 

water > 60 °C 

(140 °F) 

(3.3.1-39) 

Cracking due to 

SCC 

Water Chemistry No Not applicable Not applicable to 

HCGS 

Steel tanks in diesel 

fuel oil system 

exposed to air – 

outdoor (external) 

(3.3.1-40) 

Loss of material 

due to general, 

pitting, and crevice 

corrosion 

Aboveground Steel 

Tanks 

No Aboveground Steel 

Tanks 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-295 

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 

(3.3.1-41) 

Cracking due to 

cyclic loading and 

SCC 

Bolting Integrity No Not applicable Not applicable to 

HCGS (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 

HCGS (See SER 

Section 3.3.2.1.1) 

Steel bolting and 

closure bolting 

exposed to air – 

indoor uncontrolled 

(external) or air – 

outdoor (external) 

(3.3.1-43) 

Loss of material 

due to general, 

pitting, and crevice 

corrosion 

Bolting Integrity No Bolting Integrity 

Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) Handling 

Systems

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.2) 

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 

Bolting Integrity

Not applicable to 

HCGS (See SER 

Section 3.3.2.1.1) 

Steel closure 

bolting exposed to 

air – indoor 

uncontrolled 

(external) 

(3.3.1-45) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening 

Bolting Integrity No Bolting Integrity 

ASME Section XI, 

Subsection IWF 

Structures 

Monitoring Program 

Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) Handling 

Systems 

RG 

1.127,”Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants””

Consistent with 

GALL Report 

(See SER 

Sections 3.3.2.1.3 

and 3.5.2.1.2)
Aging Management Review Results 

 3-296 

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 

piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water > 60 °C 

(140 °F) 

(3.3.1-46) 

Cracking due to 

SCC 

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 

(3.3.1-47) 

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 

Stainless steel; 

steel with stainless 

steel cladding heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water 

(3.3.1-49) 

Loss of material 

due to 

microbiologicallyinfluenced 

corrosion 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

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 
Aging Management Review Results 

 3-297 

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 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 

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 Compressed Air 

Monitoring 

Periodic Inspection 

and Fire Protection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.5) 

Steel ducting 

closure bolting 

exposed to air – 

indoor 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 air – 

indoor uncontrolled 

(external) 

(3.3.1-56) 

Loss of material 

due to general 

corrosion 

External Surfaces 

Monitoring 

No External Surfaces 

Monitoring 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-298 

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 and 

components 

external surfaces 

exposed to air – 

indoor uncontrolled 

(external) 

(3.3.1-57) 

Loss of material 

due to general 

corrosion 

External Surfaces 

Monitoring 

No External Surfaces 

Monitoring 

Fire Protection 

Fire Water System 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.4) 

Steel external 

surfaces exposed to 

air – indoor 

uncontrolled 

(external), air – 

outdoor (external), 

and condensation 

(external) 

(3.3.1-58) 

Loss of material 

due to general 

corrosion 

External Surfaces 

Monitoring 

No External Surfaces 

Monitoring 

Fire Protection 

Fire Water System 

Structures 

Monitoring Program 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.4) 

Steel heat 

exchanger 

components 

exposed to air – 

indoor uncontrolled 

(external) or air – 

outdoor (external) 

(3.3.1-59) 

Loss of material 

due to general, 

pitting, and crevice 

corrosion 

External Surfaces 

Monitoring 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.3.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to air – 

outdoor (external) 

(3.3.1-60) 

Loss of material 

due to general, 

pitting, and crevice 

corrosion 

External Surfaces 

Monitoring 

No External Surfaces 

Monitoring 

Fire Protection 

Fire Water System 

Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) Handling 

Systems 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.2) 

Elastomer fire 

barrier penetration 

seals exposed to 

air – outdoor or 

air – indoor 

uncontrolled 

(3.3.1-61) 

Increased 

hardness, 

shrinkage, and 

loss of strength 

due to weathering 

Fire Protection No Fire Protection 

Structures 

Monitoring Program 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.10)
Aging Management Review Results 

 3-299 

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 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 

HCGS 

Steel fire rated 

doors exposed to 

air – outdoor or 

air – indoor 

uncontrolled 

(3.3.1-63) 

Loss of material 

due to wear 

Fire Protection No Fire Protection Consistent with 

GALL Report 

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 Not applicable Not applicable to 

HCGS 

Reinforced concrete 

structural fire 

barriers - walls, 

ceilings, and floors 

exposed to air – 

indoor 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 

HCGS (See SER 

Section 3.3.2.1.1) 

Reinforced concrete 

structural fire 

barriers - walls, 

ceilings, and floors 

exposed to air – 

outdoor 

(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 Fire Protection and 

Structures 

Monitoring Program 

Consistent with 

GALL Report 

Reinforced concrete 

structural fire 

barriers - walls, 

ceilings, and floors 

exposed to air – 

outdoor or air – 

indoor uncontrolled 

(3.3.1-67) 

Loss of material 

due to corrosion of 

embedded steel 

Fire Protection and 

Structures Monitoring 

Program 

No Fire Protection and 

Structures 

Monitoring Program 

Consistent with 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water 

(3.3.1-68) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Fire Water System No Fire Water System 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.6) 
Aging Management Review Results 

 3-300 

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 

(3.3.1-69) 

Loss of material 

due to pitting and 

crevice corrosion, 

and fouling 

Fire Water System No Not applicable Not applicable to 

HCGS 

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water 

(3.3.1-70) 

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Fire Water System No Fire Water System Consistent with 

GALL Report 

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 Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.2) 

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) 

microbiologicallyinfluenced 

corrosion 

Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components 

No Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

Fire Protection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.9) 

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 

Consistent with 

GALL Report 

Steel cranes - rails 

exposed to air – 

indoor 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 
Aging Management Review Results 

 3-301 

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 

exposed to raw 

water 

(3.3.1-75) 

Hardening and 

loss of strength 

due to elastomer 

degradation; loss 

of material due to 

erosion 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Consistent with 

GALL Report 

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 

microbiologicallyinfluenced 

corrosion, fouling, 

and lining/coating 

degradation 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Consistent with 

GALL Report 

Steel heat 

exchanger 

components 

exposed to raw 

water 

(3.3.1-77) 

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle Cooling 

Water System 

No Fire Water System 

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.7) 

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 Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

HCGS 

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 

microbiologicallyinfluenced 

corrosion 

Open-Cycle Cooling 

Water System 

No Not applicable Not applicable to 

HCGS 
Aging Management Review Results 

 3-302 

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 piping, 

piping components, 

and piping elements 

exposed to raw 

water 

(3.3.1-81) 

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle Cooling 

Water System 

No Open-Cycle 

Cooling Water 

System 

Periodic Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.8) 

Copper alloy heat 

exchanger 

components 

exposed to raw 

water 

(3.3.1-82) 

Loss of material 

due to pitting, 

crevice, galvanic, 

and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle Cooling 

Water System 

No Not applicable 

Periodic Inspection 

Not applicable to 

HCGS 

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 Not applicable 

Periodic Inspection 

Not applicable to 

HCGS 

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 

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 
Aging Management Review Results 

 3-303 

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

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 

HCGS 

Boraflex spent fuel 

storage racks 

neutron-absorbing 

sheets exposed to 

treated borated 

water 

(3.3.1-87) 

Reduction of 

neutron-absorbing 

capacity due to 

boraflex 

degradation 

Boraflex Monitoring No Not applicable Not applicable to 

BWRs 

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 

BWRs 

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 Not applicable Not applicable to 

BWRs 

Stainless steel and 

steel with stainless 

steel cladding 

piping, piping 

components, piping 

elements, tanks, 

and fuel storage 

racks exposed to 

treated borated 

water > 60 °C 

(140 °F) 

(3.3.1-90) 

Cracking due to 

SCC 

Water Chemistry No Not applicable Not applicable to 

BWRs 
Aging Management Review Results 

 3-304 

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 Not applicable Not applicable to 

BWRs 

Galvanized steel 

piping, piping 

components, and 

piping elements 

exposed to air – 

indoor uncontrolled 

(3.3.1-92) 

None None No None Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.2) 

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 air – 

indoor uncontrolled 

(external) 

(3.3.1-94) 

None None No None Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.5) 

Steel and aluminum 

piping, piping 

components, and 

piping elements 

exposed to air – 

indoor controlled 

(external) 

(3.3.1-95) 

None None No Not applicable Not applicable to 

HCGS 

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 

 3-305 

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 Compressed Air 

Monitoring 

Consistent with 

GALL Report 

(See SER 

Section 3.3.2.1.11)

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 Not applicable Not applicable to 

BWRs 

The staff’s review of the auxiliary systems component groups followed several approaches. 

One approach, documented in SER Section 3.3.2.1, discusses the staff’s review of AMR results 

for components the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.3.2.2, discusses the staff’s 

review of AMR results for components 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, discusses the staff’s review of AMR results for components the applicant 

indicated are not consistent with or not addressed in the GALL Report. The staff’s review of 

AMPs credited to manage or monitor aging effects of the auxiliary systems components is 

documented in SER Section 3.0.3. 

3.3.2.1 AMR Results That Are 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: 

● ASME Section XI Inservice Inspection, IWB, IWC, and IWD 

● Aboveground Steel Tanks 

● Bolting Integrity 
Aging Management Review Results 

 3-306 

● Boral Monitoring Program 

● Buried Non-Steel Piping Inspection 

● Buried Piping Inspection 

● BWR Stress Corrosion Cracking 

● Closed-Cycle Cooling Water System 

● Compressed Air Monitoring 

● External Surfaces Monitoring 

● Fire Protection 

● Fire Water System 

● Flow-Accelerated Corrosion 

● Fuel Oil Chemistry Program 

● Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

● Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

● Lubricating Oil Analysis 

● One-Time Inspection 

● Open-Cycle Cooling Water System 

● Periodic Inspection 

● Selective Leaching of Materials 

● Small-Bore Class 1 Piping Inspection 

● Structures Monitoring Program 

● TLAA 

● Water Chemistry 

LRA Tables 3.3.2-1 through 3.3.2-32 summarize AMRs for the auxiliary systems components 

and indicate AMRs claimed to be consistent with the GALL Report. 

For component groups evaluated in the GALL Report for which the applicant had claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 
Aging Management Review Results 

 3-307 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR line item. The notes describe how the information 

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

Notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR line 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 line 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 line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

AMP identified in the GALL Report. The staff audited these line items to verify consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 

Note C indicates that the component for the AMR line 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 audited these 

line items to verify consistency with the GALL Report. The staff also determined whether the 

AMR line 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 line 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 audited these line items to 

verify consistency with the GALL Report and confirmed whether the AMR line item of the 

different component was applicable to the component under review. The staff confirmed 

whether it had reviewed and accepted the exceptions to the GALL Report AMPs. It 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 line item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff audited these line 

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 did not repeat its review of the matters described in the GALL Report; however, it 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 is discussed below. 

The staff reviewed the LRA to confirm that the applicant: (1) provided a brief description of the 

system, components, materials, and environments; (2) stated that the applicable aging effects 
Aging Management Review Results 

 3-308 

were reviewed and evaluated in the GALL Report; and (3) identified those aging effects for the 

auxiliary systems components that are subject to an AMR. 

On the basis of its audit and review, the staff determines that, for AMRs not requiring further 

evaluation, as identified in LRA Table 3.3.1, the applicant’s references to the GALL Report are 

acceptable and no further staff review is required. 

The staff notes that in LRA Tables 3.3.2-2, 3.3.2-5, 3.3.2-9, 3.3.2-10, 3.3.2-16, 3.3.2-22, 

3.3.2-24, 3.3.2-27, 3.3.2-29, and 3.3.2-30, there are multiple tank line items exposed to material 

and environment combinations including carbon steel exposed to closed-cycle cooling water, 

treated water, raw water, and fuel oil and stainless steel exposed to treated water, raw water, 

and sodium pentaborate. The staff also notes that the LRA does not have a line item for the 

tank material exposed to an air or wetted gas internal environment as would occur when the 

tank is partially full. The staff further notes that in each instance, LRA line items manage the 

aging of the tank internal surfaces using a program that requires an internal inspection of the 

tank when appropriate (for example, the Closed-Cycle Cooling Water Program requires a 

one-time inspection of stagnant flow areas and internals of selected chemical mixing tanks). 

These programs include the Closed-Cycle Cooling Water System, Inspection of Internal 

Surfaces of Miscellaneous Piping and Ducting Components, Periodic Inspections, One-Time 

Inspections, and the Fire Water System Programs. The staff finally notes that in appropriate 

cases, the LRA line items uses a chemistry control program inclusive of the Water Chemistry, 

Fuel Oil, and Closed-Cycle Cooling Water System Programs. The staff finds the existing line 

items acceptable because the chemistry program will minimize contaminant concentrations and 

thus mitigate loss of material due to various corrosion mechanisms for tank internal surfaces at 

the fluid to air transition zone, and the inspection related programs will provide reasonable 

assurance that an aging effect is not affecting the components intended function. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

In RAI B.2.1.12-01, the staff asked the applicant to explain how the applicant ensures that other 

AMPs credited for aging management of component support and structural bolting include all 

the recommendations for aging management of bolting in GALL AMP XI.M18. LRA 

Tables 3.3.2-8 and 3.3.2-13 were revised as a result of the response to RAI B.2.1.12-01, dated 

June 14, 2010. The revision added AMR items in these tables to reference the applicant’s 

Bolting Integrity Program to manage the aging for bolting AMR items. Existing bolting AMR 

items which reference other AMPs are used in conjunction with the added bolting AMR items to 

properly manage aging for bolting components. The staff’s evaluation of the applicant’s Bolting 

Integrity Program is documented in SER Section 3.0.3.2.4. The staff notes that the Bolting 

Integrity Program is supplemented by other AMPs, including but not limited to the Structures 

Monitoring, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems, External Surfaces Monitoring, and Buried Piping Inspection Programs. These other 

AMPs supplement the Bolting Integrity Program by implementing the requirements of the Bolting 

Integrity Program for pressure retaining bolted joints, component support bolting, and structural 

bolting within the scope of license renewal. The applicant’s action revised the LRA to add 

bolting component items in the tables mentioned above that are consistent with the GALL 

Report and have designated them as such with generic note B. 
Aging Management Review Results 

 3-309 

3.3.2.1.1 AMR Results Identified as Not Applicable 

LRA Table 3.3.1, item 3.3.1-36 addresses reduction of neutron-absorbing capacity due to 

Boraflex degradation in Boraflex spent fuel storage racks neutron-absorbing sheets exposed to 

treated water. The applicant stated that this line item is not applicable because there are no 

Boraflex spent fuel storage racks neutron-absorbing sheets exposed to treated water for the 

auxiliary systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the 

applicant’s LRA does not have any AMR results that include Boraflex spent fuel storage racks 

neutron-absorbing sheets exposed to treated water. The staff also reviewed the applicant’s 

UFSAR and confirmed that no in-scope Boraflex spent fuel storage racks neutron-absorbing 

sheets exposed to treated water are present in the spent fuel storage system and, therefore, the 

staff finds the applicant’s determination acceptable. 

LRA Table 3.3.1, item 3.3.1-37 addresses cracking due to SCC and IGSCC in stainless steel 

piping, piping components, and piping elements exposed to treated water greater than 60 °C 

(140 °F). The applicant stated that this line item is not applicable because it has met the 

screening criteria for not implementing GALL AMP XI.M25, “BWR Reactor Water Cleanup 

System.” The staff reviewed the applicant’s claim of meeting the screening criteria and 

confirmed that it matched that of GALL AMP XI.M25 and, therefore, the staff finds the 

applicant’s determination acceptable. 

LRA Table 3.3.1, item 3.3.1-41 addresses high-strength steel closure bolting exposed to air with 

steam or water leakage in the auxiliary systems. The GALL Report recommends GALL 

AMP XI.M18, “Bolting Integrity,” to manage cracking due to cyclic loading or SCC for this 

component group. The applicant stated that this item is not applicable because there is no 

high-strength closure bolting in the auxiliary systems. The staff reviewed LRA Sections 2.3.3 

and 3.3 and confirmed that the applicant’s LRA does not have any AMR results for the auxiliary 

systems that include high-strength steel closure bolting exposed to air with steam or water 

leakage. The staff reviewed the applicant’s UFSAR and confirmed that no in-scope 

high-strength steel closure bolting exposed to air with steam or water leakage is present in the 

auxiliary systems and, therefore, the staff finds the applicant’s determination acceptable. 

LRA Table 3.3.1, item 3.3.1-42 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL AMP XI.M18, “Bolting Integrity,” to 

manage loss of material due to general corrosion for this component group. The applicant 

stated that this item is not applicable because the AMR methodology for steel closure bolting 

predicts pitting and crevice corrosion in addition to general corrosion, and as a result, item 

3.3.1-43 is credited for this component instead. The staff evaluated the applicant’s claim and 

found it acceptable because the applicant: (1) identified the loss of material due to general, 

pitting, and crevice corrosion aging effect which is a more conservative approach than the loss 

of material due to general corrosion aging effect for this component group; and (2) has credited 

an alternate Table 1, item 3.3.1-43 to manage this component group. 

LRA Table 3.3.1, item 3.3.1-44 addresses steel compressed air system closure bolting exposed 

to condensation. The GALL Report recommends GALL AMP XI.M18, “Bolting Integrity,” to 

manage loss of material due to general, pitting, and crevice corrosion for this component group. 

The applicant stated that this item is not applicable because steel closure bolting is evaluated by 

item 3.3.1-43, and also that the Bolting Integrity Program is used to manage loss of material due 

to general, pitting, and crevice corrosion of the steel bolting. The staff evaluated the applicant’s 

claim and found it acceptable because the applicant has credited an alternate Table 1, 

item 3.3.1-43 to manage this component group which applies the same AMP as that 
Aging Management Review Results 

 3-310 

recommended for item 3.3.1-44 and is also capable of managing the aging effect for this 

component group. 

LRA Table 3.3.1, item 3.3.1-59 addresses loss of material due to general, pitting, and crevice 

corrosion in steel heat exchanger components exposed externally to uncontrolled indoor and 

outdoor air. The GALL Report recommends GALL AMP XI.M36, “External Surfaces 

Monitoring.” The applicant stated that this line item is not applicable because AMR 

methodology assumes steel heat exchanger components are located indoors and exposed to 

uncontrolled indoor air, and as a result, item 3.3.1-58 is credited to manage aging for this 

component instead. LRA Table 3.3.1-58 addresses steel external surfaces exposed to indoor 

uncontrolled or outdoor air. The GALL Report also recommends GALL AMP XI.M36 to manage 

aging effects for this component group. The staff evaluated the applicant’s claim and found it 

acceptable because although the applicant credited an alternate line item (3.3.1-58) to manage 

this component group, the components are being managed by the same AMP as recommended 

for item 3.3.1-59, which performs visual inspections capable of detecting loss of material. 

LRA Table 3.3.1, item 3.3.1-65 addresses reinforced concrete structural fire barriers (i.e., walls, 

ceilings, and floors) exposed to indoor uncontrolled air being managed for cracking and spalling 

due to aggressive chemical attack and reaction with aggregates. The LRA states that this line 

item is not applicable and that these aging effects and mechanisms for concrete structural fire 

barriers are addressed with the applicable building structure in LRA Section 3.5. The GALL 

Report recommends the use of GALL AMP XI.M26, “Fire Protection,” and GALL AMP XI.S6, 

“Structures Monitoring,” to manage these aging effects. The staff notes that the Structures 

Monitoring Program performs inspections such that structures are inspected at least once in 10 

years, while the Fire Protection Program performs inspections on an 18 month frequency for fire 

barriers outside containment. The staff reviewed LRA Section 3.5 and could not determine 

where this material, environment, and aging effect were addressed for fire barriers because 

there were no entries for these components being managed by the Fire Protection Program. 

By letter dated June 22, 2010, the staff issued RAI 3.3.1.65-1 requesting that the applicant 

identify how reinforced concrete structural fire barriers (e.g., walls, ceilings, and floors) exposed 

to indoor uncontrolled air are being adequately managed for the aging effects of cracking and 

spalling due to aggressive chemical attack and reaction with aggregates. 

In its response dated July 19, 2010, the applicant stated that above-grade and interior concrete 

is not exposed to an aggressive chemical attack, and reaction with aggregates is not an 

applicable aging effect because it uses only low alkali cement that has been tested in 

accordance with ASTM C289 and C295 to resist reaction with aggregates. The applicant also 

stated that cracking, loss of bond, and loss of material are applicable aging effects for concrete 

and are being managed under item 3.5.1-23; and that the AMR result line to manage these 

aging effects using the Fire Protection Program was inadvertently omitted from Table 3.3.2-10. 

As a result, the applicant revised Table 3.3.2-10 to add an AMR result line for reinforced 

concrete fire barriers (e.g., walls, ceilings, and floors) exposed to indoor uncontrolled air which 

are being managed for cracking, loss of bond, and loss of material by the Fire Protection 

Program under item 3.5.10-23, which cites generic note E. The applicant further stated that 

even though the AMR result line was inadvertently omitted, the Fire Protection Program 

includes inspections of these fire barriers once every 18 months. 

The staff finds the applicant’s response to RAI 3.3.1.65-1, its determination that item 3.3.1-65 is 

not applicable, and its proposal to manage aging for reinforced concrete fire barrier walls, 

ceilings, and floors using the Fire Protection and Structures Monitoring Programs acceptable 
Aging Management Review Results 

 3-311 

because: (1) addition of an AMR result which manages aging using the Fire Protection Program 

ensures the affected components are inspected at least once every 18 months, which is an 

appropriate frequency for inspection of fire barriers; (2) the components that would have been 

managed using item 3.3.1-65 are being appropriately managed by item 3.5.1-23; (3) the 

applicant uses only low alkali cement which has been shown to not cause a reaction with 

aggregates; (4) the fire barriers are exposed to plant indoor air, which would not be expected to 

include aggressive chemicals; and (5) the programs both perform visual inspections which are 

effective at detecting cracking, loss of bond, and loss of material. The staff’s concern described 

in RAI 3.3.1.65-1 is resolved. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that 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). 

3.3.2.1.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

LRA Table 3.3.1, item 3.3.1-60 addresses steel piping, piping components, and piping elements 

exposed to air. In LRA Table 3.3.2-8, the applicant credits item 3.3.1-60 to manage aging for 

cranes and hoists. For this line item, the LRA credits the Inspection of Overhead Heavy Load 

and Light Load (Related to Refueling) Program to manage the aging effect. The GALL Report 

recommends GALL AMP XI.M36, “External Surfaces Monitoring,” to ensure that these aging 

effects are adequately managed. The associated AMR line item cites generic note E, indicating 

that the LRA AMR is consistent with the GALL Report item for material, environment, and aging 

effect, but a different AMP is credited. 

For those line items associated with generic note E in Table 3.3.2-8, the staff noted that the 

applicant selected a Table 1 line item for piping, piping components, and piping elements, 

whereas for line items associated with generic note E in LRA Table 3.3.2-8, the component is 

listed as cranes/hoists. GALL AMP XI.M36 recommends using visual inspections to manage 

the aging of these line items. In its review of components associated with item 3.3.1-60 for 

which the applicant cited generic note E, the staff noted that the Inspection of Overhead Heavy 

Load and Light Load (Related to Refueling) Handling Systems Program proposes to manage 

the aging of carbon steel cranes and hoists through the use of visual inspections. 

The staff’s evaluation of the applicant’s Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems Program is documented in SER Section 3.0.3.2.6. 

The staff noted that the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program proposes to manage the aging effects of the structural 

steel components of plant cranes and hoists through the use of periodic visual inspections. In 

its review of components associated with item 3.3.1-60, the staff finds the applicant’s proposal 

to manage aging using the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program acceptable because the alternate AMP is able to 

properly manage the loss of material due to general, pitting, and crevice corrosion through the 

use of methods similar to those recommended by GALL AMP XI.M35, “External Surfaces 

Monitoring.” 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-312 

LRA Table 3.3.1, item 3.3.1-43 addresses steel bolting and closure bolting exposed to air – 

indoor uncontrolled (external) or air – outdoor (external) which are being managed for loss of 

material due to general, pitting, and crevice corrosion. The LRA credits the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program to 

manage the aging effect. The GALL Report recommends GALL AMP XI.M18, “Bolting 

Integrity,” to ensure that these aging effects are adequately managed. The associated AMR line 

item cites generic note E, indicating that the LRA AMR is consistent with the GALL Report item 

for material, environment, and aging effect, but a different AMP is credited. 

For those line items associated with generic note E, GALL AMP XI.M18 recommends using 

visual inspections to manage the aging of these line items. In its review of components 

associated with item 3.3.1-43 for which the applicant cited generic note E, the staff noted that 

the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program proposes to manage the aging of carbon and low alloy steel bolting through 

the use of visual inspections. 

The staff reviewed the applicant’s Inspection of Overhead Heavy Load and Light Load (Related 

to Refueling) Handling Systems Program and its evaluation is documented in SER 

Section 3.0.3.2.6. The staff noted that the applicant’s Inspection of Overhead Heavy Load and 

Light Load (Related to Refueling) Handling Systems Program uses procedures that have 

incorporated the guidance from ANSI B30.2, which includes proper installation and design 

criteria, and periodic visual inspections for loss of material. Also, the staff issued 

RAI B.2.1.12-01 requesting that the applicant explain why programs other than the Bolting 

Integrity Program were credited to manage aging effects for structural bolting. 

In its response, which is evaluated in SER Section 3.0.3.2.4, the applicant added a number of 

AMR result lines, including some associated with LRA Table 3.3.1, item 3.3.1-43. The added 

AMR result lines credit the Bolting Integrity Program, in addition to the previously credited 

program to manage loss of material due to general, pitting, and crevice corrosion and cite 

generic note B, indicating that the results are consistent with the GALL Report for component, 

material, environment, and aging effect, but the AMP takes some exception(s) to the GALL 

Report. The staff finds the applicant’s proposed combination of programs acceptable to 

manage aging for these components because: (1) the programs include visual inspections of 

bolting which are capable of detecting loss of preload, (2) the use of the Bolting Integrity 

Program is consistent with the recommendations in the GALL Report, and (3) supplementing 

the inspections performed by the Bolting Integrity Program with inspections performed by the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program provides a more comprehensive approach to monitoring aging for these components. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-71 addresses steel piping, piping components, and piping elements 

exposed internally to moist air or condensation being managed for loss of material due to 

general pitting and crevice corrosion. The LRA credits the Fire Protection Program for steel and 

galvanized steel piping and fittings, and steel spray nozzles in the fire protection system. The 

GALL Report recommends GALL AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to ensure that these aging effects are 

adequately managed. The AMR line items cite generic note E, which indicate that the line item 
Aging Management Review Results 

 3-313 

is consistent with the GALL Report for the material, environment, and aging effect, but a 

different AMP is credited. The AMR line items also cite plant-specific note 1, indicating that the 

Fire Protection Program is substituted to manage the aging effects applicable to this component 

type, material, and environment combination. GALL AMP XI.M38 recommends performing 

inspections of the internal surfaces of piping and components to manage loss of material. 

The staff reviewed the applicant’s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.7. The staff noted that the Fire Protection Program includes: (1) external 

visual inspections of fire barriers, seals, and doors; and (2) external visual inspections and 

functional testing of the diesel driven fire pump and halon and CO2 fire suppression systems. In 

its review of components associated with item 3.3.1-71 for which the applicant cited generic 

note E, the staff noted that the applicant credited the Fire Protection Program to manage aging 

for steel and galvanized steel piping and fittings, and steel spray nozzles in LRA Table 3.3.2-10. 

However, the staff also noted that the Fire Protection Program does not include criteria for 

inspections of the internal surfaces of components to detect loss of material. 

By letter dated June 22, 2010, the staff issued RAI 3.3.1-01 requesting that the applicant justify 

how the Fire Protection Program will adequately manage the aging effect of loss of material due 

to general, pitting, and crevice corrosion for these components in a wetted air or gas internal 

environment. 

In its response dated July 19, 2010, the applicant stated that the galvanized steel piping and 

components in Table 3.3.2-10 are subject to the same internal environment as the external 

surfaces because the halon system uses open spray nozzles and the nozzles and piping are 

located in the control room, which is temperature and humidity controlled and is not subject to 

condensation or wetting that could cause corrosion. The applicant also stated that it has 

galvanized steel piping and steel spray nozzles in the foam fire suppression system that are 

subject to internal condensation or wetting. As a result, the applicant revised LRA 

Table 3.3.2-10 to: (1) add a line item for galvanized steel piping and fittings exposed internally to 

indoor air which references item 3.3.1-92 and cites generic note A; and (2) revise the line items 

associated with item 3.3.1-77 which cite note E and manage steel odorizers, piping and fittings, 

and galvanized steel piping, fittings, and spray nozzles exposed to wetted air or gas such that 

the revised items will be managed by the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program and cite generic note A. 

The staff finds the applicant’s response to RAI 3.3.1-01 and proposed programs to manage 

aging for these components acceptable because the applicant: (1) revised the environment for 

the stainless steel spray nozzles appropriately and aligned the components to an appropriate 

line item for the given material and environment combination; and (2) revised the LRA to include 

an inspection program that is applicable for managing aging for the internal surfaces of 

components and is consistent with the GALL Report recommendations for the given material, 

aging effect, and environment combination. The staff’s concern described in RAI 3.3.1-01 is 

resolved. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-60 addresses steel piping, piping components, and piping elements 

exposed externally to outdoor air which are being managed for loss of material due to general, 
Aging Management Review Results 

 3-314 

pitting, and crevice corrosion. The LRA credits the Fire Water System Program in addition to 

the External Surfaces Monitoring Program for steel, gray cast iron, ductile cast iron, and 

galvanized steel piping and fittings, fire hydrants, hose manifolds, valve bodies, and thermowells 

in the fire protection system. The GALL Report recommends GALL AMP XI.M36, “External 

Surfaces Monitoring,” to ensure that these aging effects are adequately managed. The AMR 

line items cite generic note E. The AMR line items also cite plant-specific note 12, indicating 

that the Fire Water System Program will be used in addition to the External Surfaces Monitoring 

Program. 

GALL AMP XI.M36 recommends using periodic visual inspections of the external surfaces of 

steel components to manage these aging effects. In its review of components associated with 

item 3.3.1-60 for which the applicant cited generic note E, the staff noted that the applicant 

credited both the Fire Water System and External Surfaces Monitoring Program to manage 

aging for these items in LRA Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Water System Program and its evaluation is documented 

in SER Section 3.0.3.2.8. The staff noted that the Fire Water System Program proposes to 

manage the aging effects of the steel components through the use of periodic visual 

inspections. The staff finds the proposed program acceptable to manage aging for these 

components because: (1) the proposed inspection method of visual inspection is the same and 

there are no substantive differences between the other program elements as compared to the 

GALL Report recommended AMP, and (2) the applicant is using the Fire Water System 

Program in addition to the External Surfaces Monitoring Program, which provides a more 

conservative approach to managing this aging effect. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-60 addresses steel piping, piping components, and piping elements 

exposed externally to outdoor air which are being managed for loss of material due to general, 

pitting, and crevice corrosion. The LRA credits the Fire Protection Program in addition to the 

External Surfaces Monitoring Program to manage aging for steel piping and fittings, spray 

nozzles, and valve bodies in the fire protection system. The GALL Report recommends GALL 

AMP XI.M36, “External Surface Monitoring,” to ensure that these aging effects are adequately 

managed. The AMR line items cite generic note E, indicating that the LRA AMR is consistent 

with the GALL Report item for material, environment, and aging effect, but a different AMP is 

credited. The AMR line items also cite plant-specific note 15, indicating that the Fire Protection 

Program will be used in addition to the External Surfaces Monitoring Program. 

GALL AMP XI.M36 recommends using periodic visual inspections of the external surfaces of 

steel components to manage these aging effects. In its review of components associated with 

item 3.3.1-60 for which the applicant cited generic note E, the staff noted that the applicant 

credited both the Fire Protection and External Surfaces Monitoring Programs to manage aging 

for these items in LRA Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Protection and External Surfaces Monitoring Programs 

and its evaluations are documented in SER Sections 3.0.3.2.7 and 3.0.3.1.13, respectively. The 

staff noted that the Fire Protection Program proposes to manage the aging effects of the steel 

components through the use of periodic visual inspections. The staff finds the proposed 
Aging Management Review Results 

 3-315 

program acceptable to manage aging for these components because: (1) the proposed 

inspection method of visual inspection is the same as the inspection method in the GALL Report 

recommended AMP, and (2) the applicant is using the Fire Protection Program in addition to the 

External Surfaces Monitoring Program, which provides an effective approach to managing this 

aging effect. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-60 addresses steel piping, piping components, and piping elements 

exposed externally to outdoor air which are being managed for loss of material due to general, 

pitting, and crevice corrosion. The LRA credits the Fire Protection Program to manage aging for 

steel doors in the fire protection system. The GALL Report recommends GALL AMP XI.M36, 

“External Surfaces Monitoring,” to ensure that these aging effects are adequately managed. 

The AMR line items cite generic note E, indicating that the LRA AMR is consistent with the 

GALL Report item for material, environment, and aging effect, but a different AMP is credited. 

The AMR line items also cite plant-specific note 1, indicating that the Fire Protection Program is 

substituted to manage the aging effects applicable to this component type, material, and 

environment combination. 

GALL AMP XI.M36 recommends using periodic visual inspections of the external surfaces of 

steel components to manage these aging effects. In its review of components associated with 

item 3.3.1-60 for which the applicant cited generic note E, the staff noted that the applicant 

credited the Fire Protection Program to manage aging for steel doors in LRA Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.7. The staff noted that the Fire Protection Program proposes to manage 

the aging effects of the steel doors through the use of periodic visual inspections. The staff 

finds the proposed program acceptable to manage aging for these components because the 

proposed inspection method of visual inspection is the same as the inspection method in the 

GALL Report recommended AMP. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.2.1, item 3.2.1-23 addresses steel bolting and closure bolting exposed externally to 

outdoor air or indoor uncontrolled air which are being managed for loss of material due to 

general, pitting, and crevice corrosion. The LRA credits the External Surfaces Monitoring 

Program to manage loss of material for carbon and low alloy steel bolting in the filtration, 

recirculation, and ventilation system. The GALL Report recommends GALL AMP XI.M18, 

“Bolting Integrity,” to ensure these aging effects are adequately managed. The AMR line items 

cite generic note E. GALL AMP XI.M18 recommends performing periodic visual inspections to 

manage loss of material. 

The staff reviewed the applicant’s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.1.13. The staff noted that the applicant’s External Surfaces 

Monitoring Program includes periodic visual inspections of bolting for signs of degradation due 
Aging Management Review Results 

 3-316 

to loss of material and leakage at bolted joints. The staff finds the applicant’s proposed program 

acceptable to manage aging for these components because it uses visual inspections to detect 

loss of material, which is consistent with the inspection methods in the recommended GALL 

Report AMP, and has incorporated the guidance recommended in GALL AMP XI.M18. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.3 Loss of Preload Due to Thermal Effects, Gasket Creep, and Self-Loosening 

LRA Table 3.3.1, item 3.3.1-45 addresses carbon and low alloy steel bolting in the cranes and 

hoists system (LRA Table 3.3.2-8) and in the fuel handling and storage system (LRA 

Table 3.3.2-13); it also addresses carbon and low alloy steel or galvanized steel component 

support bolting or structural bolting in various buildings (LRA Tables 3.5.2-1, 3.5.2-2, 3.5.2-3, 

3.5.2-4, 3.5.2-5, 3.5.3-7, 3.5.2-8, 3.5.2-11, and 3.5.2-12). For all AMR result lines associated 

with item 3.3.1-45, the environment is air – indoor and the aging effect being managed is loss of 

preload. The applicant stated that it associated these components with auxiliary system item 

3.3.1-45 because of similarity of the component, material, environment, and aging effect 

combination. For item 3.3.1-45, the GALL Report recommends GALL AMP XI.M18, “Bolting 

Integrity,” to manage loss of preload. The AMR line items in the LRA recommend managing 

loss of preload due to self-loosening with four alternative programs: (1) the Structures 

Monitoring Program; (2) the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program; (3) the ASME Section XI, Subsection IWF Program; and 

(4) the RG 1.127,”Inspection of Water-Control Structures Associated with Nuclear Power Plants” 

Program.” Where the applicant credits an alternative to the Bolting Integrity Program, the LRA 

cites generic note E, indicating that the result is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. 

During its review of AMR result lines associated with components for which the GALL Report 

recommends the Bolting Integrity Program, the staff noted that several other programs were 

identified to manage aging for bolting in the LRA. The staff issued RAI B.2.1.12-01 requesting 

that the applicant explain why programs other than the Bolting Integrity Program were credited 

to manage aging effects for structural and component support bolting. 

In its response, which is evaluated in SER Section 3.0.3.2.4, the applicant added a number of 

AMR result lines, including some associated with LRA Table 3.3.1, item 3.3.1-45. The added 

AMR result lines credit the Bolting Integrity Program in addition to the previously credited 

programs to manage loss of material due to general, pitting, and crevice corrosion and cite 

generic note B, indicating that the results are consistent with the GALL Report for component, 

material, environment, and aging effect, but the AMP takes some exception(s) to the GALL 

Report. The staff finds the applicant’s proposed combination of programs acceptable to 

manage aging for these components because: (1) the programs include visual inspections of 

bolting which are capable of detecting loss of preload, (2) the use of the Bolting Integrity 

Program is consistent with the recommendations in the GALL Report, and (3) supplementing 

the inspections performed by the Bolting Integrity Program with inspections performed by the 

other alternative programs provides a more comprehensive approach to monitoring aging for 

these components. 
Aging Management Review Results 

 3-317 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.4 Loss of Material Due to General Corrosion 

LRA Table 3.3.1, items 3.3.1-57 and 3.3.1-58 address steel piping and components external 

surfaces exposed to indoor uncontrolled air, outdoor air, and condensation being managed for 

loss of material due to general corrosion. The LRA credits the Fire Water System Program in 

addition to the External Surfaces Monitoring Program for carbon steel, gray cast iron, and 

ductile cast iron piping and fittings, pump casings, strainer bodies, valve bodies, and tanks 

(retarding chambers) in the fire protection system. The GALL Report recommends GALL 

AMP XI.M36, “External Surfaces Monitoring,” to ensure that these aging effects are adequately 

managed. The AMR line items cite generic note E. The AMR line items also cite plant-specific 

note 12, indicating that the Fire Water System Program will be used in addition to the External 

Surfaces Monitoring Program. 

GALL AMP XI.M36 recommends using periodic visual inspections of the external surfaces of 

steel components to manage these aging effects. In its review of components associated with 

items 3.3.1-57 and 3.3.1-58 for which the applicant cited generic note E, the staff noted that the 

applicant credited both the Fire Water System and External Surfaces Monitoring Programs to 

manage aging for these components in LRA Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Water System Program and its evaluation is documented 

in SER Section 3.0.3.2.8. The staff noted that the Fire Water System Program proposes to 

manage the aging effects of these components through the use of periodic visual inspections to 

detect corrosion. The staff finds the applicant’s proposed program acceptable to manage aging 

for these components because: (1) the proposed inspection method of periodic visual 

inspections is the same as that in the GALL Report recommended AMP, and (2) the applicant is 

using the Fire Water System Program in addition to the External Surfaces Monitoring Program, 

which provides a more conservative approach to managing this aging effect. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-57 addresses steel piping and components external surfaces 

exposed to indoor air which are being managed for loss of material due to general corrosion. 

The LRA credits the Fire Protection Program to manage aging for steel filter housings in the fire 

protection system. The GALL Report recommends GALL AMP XI.M36, “External Surfaces 

Monitoring,” to ensure that these aging effects are adequately managed. The AMR line item 

cites generic note E, indicating that the LRA AMR is consistent with the GALL Report item for 

material, environment, and aging effect, but a different AMP is credited. The AMR line item also 

cites plant-specific note 1, indicating that the Fire Protection Program is substituted to manage 

the aging effects applicable to this component type, material, and environment combination. 

GALL AMP XI.M36 recommends using periodic visual inspections of the external surfaces of 

steel components to manage these aging effects. 
Aging Management Review Results 

 3-318 

The staff reviewed the applicant’s Fire Protection Programs and its evaluation is documented in 

SER Section 3.0.3.2.7. In its review of components associated with item 3.3.1-57 for which the 

applicant cited generic note E, the staff noted that the Fire Protection Program proposes to 

manage the aging effects of the steel component’s external surfaces through the use of periodic 

visual inspections. The staff finds the applicant’s proposed program acceptable to manage 

aging for these components because the proposed inspection methods in the Fire Protection 

Program are the same as those methods recommended by the GALL Report recommended 

AMP. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-57 addresses steel piping and components external surfaces 

exposed to indoor air which are being managed for loss of material due to general corrosion. 

The LRA credits the Fire Protection Program in addition to the External Surfaces Monitoring 

Program for steel piping and fittings, odorizers, and valve bodies in the fire protection system. 

The GALL Report recommends GALL AMP XI.M36, “External Surfaces Monitoring,” to ensure 

that these aging effects are adequately managed. The AMR line item cites generic note E, 

indicating that the LRA AMR is consistent with the GALL Report item for material, environment, 

and aging effect, but a different AMP is credited. The AMR line item also cites plant-specific 

note 15, indicating that the Fire Protection Program will be used in addition to the External 

Surfaces Monitoring Program. GALL AMP XI.M36 recommends using periodic visual 

inspections of the external surfaces of steel components to manage these aging effects. 

The staff reviewed the applicant’s Fire Protection and External Surfaces Monitoring Programs 

and its evaluations are documented in SER Sections 3.0.3.2.7 and 3.0.3.1.13, respectively. In 

its review of components associated with item 3.3.1-57 for which the applicant cited generic 

note E, the staff noted that the Fire Protection Program proposes to manage the aging effects of 

the steel component’s external surfaces through the use of periodic visual inspections. The 

staff finds the applicant’s proposed program acceptable to manage aging for these components 

because: (1) the proposed inspection methods in the Fire Protection Program are the same as 

those recommended by the GALL Report recommended AMP, and (2) the applicant is using the 

Fire Protection Program in addition to the External Surfaces Monitoring Program, which 

provides a more conservative approach to managing this aging effect. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-58 addresses steel piping and components external surfaces 

exposed to indoor uncontrolled air, outdoor air, and condensation being managed for loss of 

material due to general corrosion. The LRA credits the Fire Protection Program to manage 

these aging effects for the external surfaces of carbon steel doors and the Fire Protection and 

External Surfaces Monitoring programs to manage the aging effects for halon gas bottles in the 

fire protection system. The GALL Report recommends GALL AMP XI.M36, “External Surfaces 

Monitoring,” to ensure that these aging effects are adequately managed. The AMR line items 

cite generic note E indicating that the LRA AMR is consistent with the GALL Report item for 

material, environment, and aging effect, but a different AMP is credited. The AMR line items 
Aging Management Review Results 

 3-319 

also cite plant-specific note 1, indicating that the Fire Protection Program is substituted to 

manage the aging effects applicable to this component type, material, and environment 

combination. 

GALL AMP XI.M36 recommends using periodic visual inspections of the external surfaces of 

steel components to manage these aging effects. In its review of components associated with 

item 3.3.1-58 for which the applicant cited generic note E, the staff noted that the applicant 

credited the Fire Protection Program to manage aging for these components in LRA 

Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.7. The staff noted that the Fire Protection Program proposes to manage 

the aging effects of these components through the use of periodic visual inspections to detect 

corrosion. The staff finds the applicant’s proposed program acceptable to manage aging for 

these components because the proposed inspection method of periodic visual inspections is 

consistent with that in the GALL Report recommended AMP and is appropriate to detect loss of 

material. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.5 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.3.1, item 3.3.1-54 addresses stainless steel piping, piping components, and piping 

elements exposed to internal condensation which are being managed for loss of material due to 

pitting and crevice corrosion. The LRA credits the Periodic Inspection Program to manage 

aging for stainless steel piping, fittings, valve bodies, flow elements, restricting orifices, and 

thermowells exposed internally to wetted air or gas. The GALL Report recommends GALL 

AMP XI.M24, “Compressed Air Monitoring,” to ensure that these aging effects are adequately 

managed. The AMR line items cite generic note E, which indicate that the line item is consistent 

with the GALL Report for the material, environment, and aging effect, but a different AMP is 

credited. The AMR line items also cite plant-specific note 1, indicating that the Periodic 

Inspection Program is substituted to manage the aging effects applicable to this component 

type, material, and environment combination. 

GALL AMP XI.M24 recommends performing periodic air quality checks to ensure contaminants 

are maintained within industry standards, leakage testing to ensure the integrity of the system, 

and inspections for corrosion. In its review of components associated with item 3.3.1-54 for 

which the applicant cited generic note E, the staff noted that the applicant credited the Periodic 

Inspection Program to manage aging for stainless steel components in LRA Tables 3.3.2-4, 

3.3.2-15, 3.3.2-17, 3.3.2-20, 3.3.2-21, 3.3.2-29, and 3.3.2-31. 

The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is documented 

in SER Section 3.0.3.3.2. The staff noted that the Periodic Inspection Program includes 

periodic visual inspections of components and ultrasonic wall thickness measurements to detect 

loss of material; but it does not include any preventive measures, such as air quality checks, 

which are included in the GALL Report recommended AMP. By letter dated July 12, 2010, the 

staff issued RAI 3.3.1.54-01, requesting that the applicant explain how these stainless steel 

components will be adequately managed by the Periodic Inspection Program. 
Aging Management Review Results 

 3-320 

In its response dated July 26, 2010, the applicant stated that the Compressed Air Monitoring 

Program is not applicable because the components in question are not in systems where 

internal air quality is maintained and are designed to be subject to the accumulation of moisture 

and contaminants. The applicant also stated that plant operating experience from several 

inspections of stainless steel components exposed to internal condensation and wetting with 

more than 30 years of inservice time indicates that stainless steel performs satisfactorily in this 

environment with adequate corrosion resistance. The staff finds the applicant’s response to 

RAI 3.3.1.54-01 and its proposal to manage aging for these components using the Periodic 

Inspection Program acceptable because: (1) the components described above are not exposed 

to air that is filtered and dried and, therefore, the preventive measures in GALL AMP XI.M24 

would not be appropriate; (2) the visual inspections and ultrasonic wall thickness examinations 

performed by the Periodic Inspection Program are appropriate for detecting the stated aging 

effects; and (3) the frequency of inspections is consistent with plant operating experience. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

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 being managed for loss of 

material due to pitting and crevice corrosion. The LRA credits the Fire Protection Program for 

managing the aging of stainless steel spray nozzles in the fire protection system. The GALL 

Report recommends GALL AMP XI.M24, “Compressed Air Monitoring,” to ensure that these 

aging effects are adequately managed. The AMR line items cite generic note E, which indicates 

that the line item is consistent with the GALL Report for the material, environment, and aging 

effect, but a different AMP is credited. The AMR line items also cite plant-specific note 1, 

indicating that the Fire Protection Program is substituted to manage the aging effects applicable 

to this component type, material, and environment combination. GALL AMP XI.M24 

recommends managing aging for compressed air system piping exposed to internal 

condensation by monitoring and controlling contaminants in the air in order to limit loss of 

material due to corrosion, and leakage testing to detect loss of material. 

The staff reviewed the applicant’s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.7. The staff noted that the Fire Protection Program includes: (1) external 

visual inspections of fire barriers, seals, and doors; and (2) external visual inspections and 

functional testing of the diesel driven fire pump, and halon and CO2 fire suppression systems. 

In its review of components associated with item 3.3.1-54 for which the applicant cited generic 

note E, the staff also noted that the applicant credited the Fire Protection Program to manage 

aging for stainless steel spray nozzles in LRA Table 3.3.2-10. However, the staff further noted 

that the Fire Protection Program does not include criteria for inspections of the internal surfaces 

of components or leakage testing which could detect loss of material for the stainless steel 

spray nozzles. 

By letter dated June 22, 2010, the staff issued RAI 3.3.1-01 requesting that the applicant justify 

how the Fire Protection Program will manage the aging effect of loss of material due to pitting 

and crevice corrosion for these components in a wetted air or gas internal environment. 

In its response dated July 19, 2010, the applicant stated that the stainless steel spray nozzles 

are located in an indoor air environment and are inspected during the periodic functional testing 

of the halon and CO2 fire suppression systems. The applicant also stated that the internal and 
Aging Management Review Results 

 3-321 

external surfaces of the spray nozzles are subject to the same environment and are not subject 

to condensation or wetting that could cause corrosion. As a result, the applicant revised LRA 

Table 3.3.2-10 to change the environment for the internal surfaces of the spray nozzles to 

indoor air, referencing item 3.3.1-94, with generic note A. The staff finds the applicant’s 

response to RAI 3.3.1-01 and its proposal to manage aging for stainless steel spray nozzles in 

accordance with item 3.3.1-94 acceptable because: (1) the spray nozzles have been 

appropriately aligned to an alternative line item for exposure of stainless steel components to 

indoor uncontrolled air, and (2) the spray nozzles are located in an indoor air environment and 

stainless steel components are not expected to experience aging effects when exposed to 

indoor air. The staff’s concern described in RAI 3.3.1-01 is resolved. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.6 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 being managed for loss of material due to general, pitting, crevice, 

galvanic, and microbiologically-influenced corrosion and fouling. The LRA credits the Fire 

Water System Program to manage aging for gray cast iron (retarding chamber) tanks exposed 

to raw water in LRA Table 3.3.2-10. The AMR line items cite generic note C. 

The staff’s evaluation of the Fire Water System Program is documented in SER 

Section 3.0.3.2.8. The staff noted that the applicant’s Fire Water System Program performs wall 

thickness evaluations of fire protection piping using non-intrusive techniques (e.g., volumetric 

testing) to identify loss of material due to corrosion. However, it was not clear to the staff 

whether volumetric inspections performed by the Fire Water System Program to detect loss of 

material due to corrosion will be performed on the internal surface (specifically the bottom) of 

the retarding chamber tanks. By letter dated June 14, 2010, the staff issued RAI 3.3.2.10-1, 

requesting that the applicant clarify if these tanks are included in the sample of fire protection 

system components that will be volumetrically inspected for wall thickness evaluation to detect 

loss of material prior to loss of intended function. 

In its response dated July 12, 2010, the applicant stated that the retarding chamber tanks are 

self draining tanks with a capacity of approximately 2 gallons that prevent spurious actuation of 

the alarm pressure switch. The applicant also stated that the retarding chamber tanks are 

normally drained, not at system low points, is not in the flowpath of water to the sprinkler heads, 

and provides system alarm function only. The applicant further stated that the retarding 

chamber tanks are not included in the sample of components that will be volumetrically 

inspected. The staff finds the applicant’s response to RAI 3.3.2.10-1 and the use of the Fire 

Water System Program to manage loss of material for the retarding chamber tanks acceptable 

because the tanks: (1) provide for system alarm function only, (2) are not part of the flowpath of 

water to the sprinkler heads, and (3) do not contain stagnant water. Therefore, the tanks do not 

require volumetric testing and are being adequately managed by the system flow testing 

performed by the Fire Water System Program. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 
Aging Management Review Results 

 3-322 

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 3.3.1-68 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 microbiologically-influenced corrosion and fouling. The LRA credits the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage 

aging for various steel (i.e., carbon, galvanized, ductile iron, gray cast iron) components in the 

fresh water supply, radwaste, and equipment and floor drainage systems. The GALL Report 

recommends GALL AMP XI.M27, “Fire Water System,” to ensure these aging effects are 

adequately managed. The AMR line items cite generic note E, indicating that the LRA AMR is 

consistent with the GALL Report item for material, environment and aging effect, but a different 

AMP is credited. 

GALL AMP XI.M27 recommends that fire protection system piping be subjected to flow testing, 

and wall thickness evaluations or visual inspections to identify loss of material and fouling. 

However, the applicant referenced generic note E and cited item 3.3.1-68 for components in 

systems other than the fire protection system. The staff reviewed all AMR result lines in the 

GALL Report where steel components exposed to raw water are being managed for loss of 

material and fouling and noted that there are entries for this combination in other systems; and 

that those entries recommend GALL AMP XI.M20, “Open-Cycle Cooling Water System” to 

ensure that these aging effects are adequately managed. The staff also noted that GALL AMP 

XI.M20 recommends preventive measure including proper selection of materials and coatings, 

periodic flushes and cleaning, and raw water chemistry control as well as visual inspections and 

NDE testing for components exposed to open-cycle cooling water. The staff further notes that 

open-cycle cooling water is water which transfers heat from safety related components to the 

ultimate heat sink. 

The staff reviewed the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program and its evaluation is documented in SER Section 3.0.3.1.14. 

The staff notes that the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program includes inspections of the internal surfaces of a representative 

sample of components to detect loss of material and fouling when the components become 

accessible for inspection and at plant-specific intervals based on operating experience. The 

staff also noted that the components for which the applicant referenced generic note E and cited 

item 3.3.1-68 are in the fresh water supply, radwaste, and equipment and floor drainage 

systems and do not include any safety-related components exposed to open-cycle cooling 

water; therefore, the GALL Report recommended programs are not appropriate to manage 

aging for these components. The staff finds the applicant’s Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable to manage aging for these 

components because it includes visual inspections of the internal surfaces of components which 

are appropriate to detect loss of material and fouling. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-323 

3.3.2.1.7 Loss of Material due to General, Pitting, Crevice, Galvanic, and 

Microbiologically-Influenced Corrosion and Fouling 

LRA Table 3.3.1, items 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, crevice, galvanic, 

and microbiologically-influenced corrosion and fouling. The LRA credits the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage the 

aging effect. The GALL Report recommends GALL AMP XI.M20, “Open-Cycle Cooling Water 

System,” to ensure that these aging effects are adequately managed. The associated AMR line 

item in Table 3.3.2-12, identified as carbon steel piping and fittings in the fresh water supply 

system, cites generic note E, which indicates that the line item is consistent with the GALL 

Report for the material, environment, and aging effect, but a different AMP is credited. 

GALL AMP XI.M20 recommends to visually monitor the condition of the open-cycle cooling 

water (or service water) system components and their coated surfaces against aggressive water 

environment for loss of material. In addition, when necessary, the program performs 

nondestructive (e.g., UT, eddy current) testing to measure wall thinning and preventive 

measures (e.g., chemical treatment, system flushing) to assure that aging effects due to MIC, 

biofouling, and silt are managed for safety-related components within the scope of GL 89-13. 

Inspections are performed annually or during refueling outages. 

In its review of components associated with item 3.3.1-77, 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 aging of the referenced carbon steel piping 

and fittings items through visual inspections during surveillances, maintenance activities, and 

outages. When the inspections yield evidence for loss of material or fouling that could 

potentially impair these components’ intended function, the applicant then evaluates the 

degraded conditions and if warranted, implements its corrective action program. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.1.14. The staff notes 

that the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program includes inspections of the internal surfaces of a representative sampling 

of components to detect loss of material and fouling when the components become accessible 

for inspection, and at plant-specific intervals based on operating experience. The staff also 

notes that the components for which the applicant referenced generic note E and cited 

item 3.3.1-77 are in the radwaste, and equipment and floor drainage systems and do not include 

any safety-related components exposed to open-cycle cooling water; therefore, the GALL 

Report recommended program is not appropriate to manage aging for these components. In its 

review of components associated with item 3.3.1-77, 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: (1) the components being managed by the program 

are nonsafety-related and not within the scope of GL 89-13; therefore, the preventive measures 

in GALL AMP XI.M20 are not appropriate; and (2) its visual inspections are as comprehensive 

as the GALL Report recommended AMP inspections for this nonsafety-related item in the fresh 

water supply system. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-324 

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, crevice, galvanic, 

and microbiologically-influenced corrosion and fouling. The LRA credits the Fire Water System 

Program for steel piping and fittings in the fire protection system. The GALL Report 

recommends GALL AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these 

aging effects are adequately managed. The AMR line item cites generic note E. The AMR line 

item also cites plant-specific note 5, indicating that the Fire Water System Program is 

substituted to manage the aging effects applicable to this component type, material, and 

environment combination. 

GALL AMP XI.M20 relies on implementation of the recommendations of GL 89-13, which 

includes using preventive measures (i.e., water chemistry control), periodic visual inspections, 

and performance testing to manage these aging effects. In its review of components associated 

with item 3.3.1-77 for which the applicant cited note E, the staff noted that the applicant credited 

the Fire Water System Program to manage aging for these steel components in LRA 

Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Water System Program and its evaluation is documented 

in SER Section 3.0.3.2.8. This GALL Report item recommends the Fire Water System Program 

to manage loss of material due to general, pitting, crevice, galvanic, and 

microbiologically-influenced corrosion and fouling of steel piping and piping components 

exposed to raw water. The staff finds the applicant’s proposed program acceptable to manage 

these aging effects for these components because the components are part of the fire 

protection system and using the Fire Water System Program is consistent with the 

recommendations in GALL AMR item VII.G-24. 

3.3.2.1.8 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 alloy piping, piping components, and piping 

elements exposed to raw water which are being managed for loss of material due to pitting, 

crevice, and microbiologically-influenced corrosion and fouling. The LRA credits the Periodic 

Inspection Program to manage the aging effect. The GALL Report recommends GALL 

AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these aging effects are 

adequately managed. The associated AMR line items in Tables 3.3.2-9 and 3.3.2-12 cite 

generic note E, which indicates that the line item is consistent with the GALL Report for the 

material, environment, and aging effect, but a different AMP is credited. 

GALL AMP XI.M20 recommends visually monitoring the condition of the open-cycle cooling 

water (or service water) system components and their coated surfaces against aggressive water 

environment for loss of material. In addition, when necessary, the program performs 

nondestructive (e.g., UT, eddy current) testing to measure wall thinning and preventive 

measures (e.g., chemical treatment, system flushing) to assure that aging effects due to MIC, 

biofouling, and silt are managed for safety-related components within the scope of GL 89-13. 

Inspections are performed annually or during refueling outages. 

In its review of components associated with item 3.3.1-81 for which the applicant cited generic 

note E, the staff noted that the Periodic Inspection Program proposes to manage aging of the 

referenced copper alloy piping, piping components, and piping elements through visual 

inspections and UT wall thickness measurements. When the inspections yield evidence for loss 

of material or fouling that could potentially impair these components’ intended function, then the 
Aging Management Review Results 

 3-325 

applicant will evaluate the degraded conditions and, if warranted, implement its corrective action 

program. 

The staff’s evaluation of the applicant’s Periodic Inspection Program is documented in SER 

Section 3.0.3.3.2. The staff notes that the applicant’s Periodic Inspection Program includes 

focused visual inspections and UT wall thickness measurements that will detect the presence 

and extent of loss of material aging effect. The focused visual inspections will also detect the 

presence and extent of fouling. The staff also notes that the components for which the applicant 

referenced generic note E and cited item 3.3.1-81 are in the fresh water supply system and 

equipment and floor drainage systems, and do not include any safety-related components 

exposed to open-cycle cooling water; therefore, the GALL Report recommended program is not 

appropriate to manage aging for these components. In its review of components associated 

with item 3.3.1-81, the staff finds the applicant’s proposal to manage aging using the Periodic 

Inspection Program acceptable because: (1) the components being managed by the program 

are nonsafety-related and not within the scope of GL 89-13; therefore, the preventive measures 

in GALL AMP XI.M20 are not appropriate; and (2) its visual inspections are as comprehensive 

as the GALL Report recommended AMP inspections for this nonsafety-related item in the fresh 

water supply system. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

LRA Table 3.3.1, item 3.3.1-72 addresses steel HVAC ducting and components internal 

surfaces exposed to condensation being managed for loss of material due to general, pitting, 

crevice, and microbiologically-influenced (for drip pans and drain lines) corrosion. The LRA 

credits the Fire Protection Program for galvanized steel damper housings in the fire protection 

system exposed internally to wetted air or gas. The GALL Report recommends GALL 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” to ensure that these aging effects are adequately managed. The AMR line items 

cite generic note E, indicating that the LRA AMR is consistent with the GALL Report item for 

material, environment, and aging effect, but a different AMP is credited. The AMR line items 

also cite plant-specific note 1, indicating that the Fire Protection Program is substituted to 

manage the aging effects applicable to this component type, material, and environment 

combination. 

GALL AMP XI.M38 recommends performing inspections of the internal surfaces of piping and 

components to manage loss of material when the components internal surfaces are exposed for 

maintenance and testing activities. In its review of components associated with item 3.3.1-72 

for which the applicant cited generic note E, the staff noted that the applicant credited the Fire 

Protection Program to manage aging for galvanized steel damper housings in LRA 

Table 3.3.2-10. 

The staff reviewed the applicant’s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.7. The staff noted that the Fire Protection Program includes periodic visual 

inspections and functional testing of fire dampers at least once every refueling cycle. The staff 

finds the applicant’s Fire Protection Program acceptable to manage aging for galvanized steel 
Aging Management Review Results 

 3-326 

damper housings in the fire protection system because periodic visual inspections and 

functional testing are capable of detecting loss of material for the specified components, and the 

method and frequency of periodic visual inspections performed by the program are consistent 

with those performed by the GALL Report recommended AMP. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.10 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 that is not controlled. These penetration seals are being managed 

to address increased hardness, shrinkage, and loss of strength due to weathering. In LRA 

Tables 3.5.2-2, 3.5.2-3, 3.5.2-8, and 3.5.2-12, the applicant associated item 3.1.1-61 with 

elastomer compressible joints and seals (seismic gaps) in the auxiliary building control/diesel 

generator area, the auxiliary building service/radwaste area, the reactor building, and the turbine 

building, respectively. The GALL Report recommends the Fire Protection Program to manage 

aging of components associated with item 3.1.1-61. However, for the elastomer compressible 

joints and seals for seismic gaps, the applicant credited the Structures Monitoring Program to 

manage the aging effect. 

The staff reviewed the applicant’s Structures Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.16. In its review of components associated with LRA item 

3.3.1-61 for which the applicant assigned generic note E, the staff noted that the Structures 

Monitoring Program proposes to manage hardening, shrinkage, and loss of sealing for 

elastomer components within its scope through the use of visual inspections. The staff noted 

that the GALL Report recommends GALL AMP XI.M26, “Fire Protection,” for aging management 

of components, materials, and environments associated with Table 3.3.1, item 3.3.1-61. The 

staff further noted that GALL AMP XI.M26 credits visual inspection by qualified inspectors with 

managing aging in those components. The staff noted that for elastomer components, the 

monitoring methods implemented by the Structures Monitoring Program are the same as in 

GALL AMP XI.M26 and there are no substantive differences between the other program 

elements as compared to the GALL Report. The staff finds that the applicant’s proposal to use 

the Structures Monitoring Program to manage aging of elastomer compressible joints and seals 

(seismic gaps) acceptable because the program performs visual inspections that are capable of 

detecting degradation of elastomer components within its scope and implements corrective 

actions if degradation is found, through the applicant’s corrective action program, prior to loss of 

the component’s intended function(s). 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.11 No Aging Effects Requiring Management 

LRA Table 3.3.1, item 3.3.1-98 addresses steel, stainless steel, and copper alloy piping, piping 

components, and piping elements exposed to dried air and states that these components have 

no AERM. The LRA credits the Compressed Air Monitoring Program to manage steel and 
Aging Management Review Results 

 3-327 

stainless steel piping, fitting, valve bodies, accumulators, hoses, and receiver tanks exposed 

internally to dry air or gas. The GALL Report states that these components have no AERMs 

and no AMP is recommended to ensure that these aging effects are adequately managed. The 

AMR line items cite generic note E, indicating that the LRA AMR is consistent with the GALL 

Report item for material, environment, and aging effect, but a different AMP is credited. The 

AMR line items also cite plant-specific note 1, indicating that the Compressed Air Monitoring 

Program is applied to confirm the internal environment remains sufficiently dry to preclude aging 

effects. 

In its review of components associated with item 3.3.1-98 for which the applicant cited generic 

note E, the staff noted that the applicant credited the Compressed Air Monitoring Program to 

manage aging for steel and stainless steel components in LRA Tables 3.3.2-3, 3.3.2-19, and 

3.3.2-23. The staff reviewed the applicant’s Compressed Air Monitoring Program and its 

evaluation is documented in SER Section 3.0.3.1.10. The staff noted that the Compressed Air 

Monitoring Program includes periodic air quality checks to ensure dew point, particulates, and 

contaminants are maintained within industry standards, leak testing, and visual inspections. 

The staff finds the applicant’s Compressed Air Monitoring Program acceptable to manage aging 

for steel and stainless steel components exposed to dry air or gas because periodic air quality 

checks will ensure the environment remains dry, and the leak testing and visual inspections will 

ensure aging is not occurring. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further 

Evaluation is Recommended 

LRA Section 3.3.2.2 provides further evaluation of aging management, as recommended by the 

GALL Report, for the auxiliary systems components. The applicant provided 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 microbiologically-influenced 

corrosion 
Aging Management Review Results 

 3-328 

● loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion 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 microbiologically-influenced corrosion 

● loss of material due to wear 

● loss of material due to cladding breach 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which the GALL Report recommends further 

evaluation, the staff audited and reviewed the applicant’s evaluations to determine whether they 

adequately address those issues. In addition, the staff reviewed the applicant’s further 

evaluations against the criteria 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 addresses the applicant’s aging management review basis for managing 

cumulative fatigue damage in auxiliary system components that were designed analyzed to 

applicable design analysis criteria in the ASME Code Section III, Articles NC-3000 or ND-3000 

(as applicable to Code Class 2 or 3 components, respectively) or in the ANSI B31.1 Code, and 

for which implicit fatigue analyses were required. In this LRA section, the applicant stated that 

the evaluation of fatigue is a TLAA as defined in 10 CFR 54.3, and that the TLAAs are 

evaluated in accordance with the TLAA acceptance criteria in 10 CFR 54.21(c)(1). The 

applicant stated that the HCGS piping designed to ASME Code Section III requirements for 

Class 2 or 3 components or to the ANSI B31.1 design code were analyzed using an implicit 

fatigue analysis that assumes a reduction in the component’s allowable secondary stress range 

if more than 7,000 full-range thermal cycles are expected over the component’s design lifetime. 

In LRA Table 3.3.1, the applicant stated that the AMR item 3.3.1-1 for managing of cumulative 

fatigue damage in the applicant’s cranes and hoists system components are consistent with the 

staff’s AMR item recommendations in AMR item 1 of Table 3 in the GALL Report, Volume 1, 

Revision 1. The applicant stated that AMR item 3.3.1-2 for managing of cumulative fatigue 

damage in applicable heat exchangers and piping, piping components, and piping elements in 

the HPCI, main steam, RCIC, and RWCU systems are consistent with the staff’s AMR item 

recommendations in AMR item 2 of the GALL Report, Volume 1, Table 3. The applicant stated 

that, for these AMRs, cumulative fatigue damage in the components will be managed using a 

TLAA, and that LRA Section 4.3.4 describes and evaluates implicit fatigue analysis-based TLAA 

for these components. 

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 ESF components is a TLAA as defined in 10 CFR 54.3, and that 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 the staff’s recommended acceptance criteria and 

review procedures for reviewing these TLAAs in SRP-LR Section 4.3, “Metal Fatigue Analysis.” 
Aging Management Review Results 

 3-329 

The staff also reviewed LRA Section 3.3.2.2.1 and the AMRs discussed in this section against 

the staff’s AMR items for evaluating cumulative fatigue damage in the GALL Report. 

With regard to the applicant’s metal fatigue AMR item 3.3.1-1, the staff noted that AMR item 1 in 

Table 3 of the GALL Report, Volume 1 and AMR item VII.B-2 in the GALL Report, Volume 2 

identify that cumulative fatigue damage is an applicable aging effect for steel cranes or 

structural girders exposed to air. The staff also noted that these GALL Report AMRs 

recommend that the TLAA on metal fatigue be used to manage the impact of cumulative fatigue 

damage in these components. The staff noted that, in conformance with this recommendation, 

the applicant included an applicable line item in LRA Table 3.3.2-8 for steel cranes or structural 

girders that received ASME Code Section III CUF or ANSI B31.1 design code analysis 

calculations. The staff noted that the applicant credited the TLAA analysis in LRA Section 4.7.1 

with the management of cumulative fatigue damage in these components. The staff found that 

the applicant’s AMR assessment is in conformance with the recommendations both in the 

SRP-LR and in AMR item 1 of the GALL Report, Volume 1, Table 3 and AMR item VII.B-2 in the 

GALL Report, Volume 2. Based on this review, the staff finds the applicant’s AMR analysis on 

cumulative fatigue damage of steel cranes or structural girders to be acceptable because it is in 

conformance with the recommendations in SRP-LR Section 3.3.2.2.1 and the GALL Report 

AMR items that are invoked by this SRP-LR section. The staff evaluates the TLAA analysis for 

the support skirt and attachment welds component in SER Section 4.7.1. 

With regard to the applicant’s metal fatigue AMR item 3.3.1-2, the staff noted that AMR item 2 in 

Table 3 of the GALL Report, Volume 1 and AMR item VII.E3-14 in the GALL Report, Volume 2 

identify that cumulative fatigue damage is an applicable aging effect for steel and stainless steel 

piping, piping components, piping elements, and heat exchanger components. The staff also 

noted that these GALL Report AMRs recommend that the TLAA on metal fatigue be used to 

manage the impact of cumulative fatigue damage in these components. The staff noted that, in 

conformance with this recommendation, the applicant included an applicable line item in LRA 

Tables 3.2.2-4, 3.2.2-6, 3.3.2-24, and 3.4.2-4 for stainless steel piping, piping components, 

piping elements, and heat exchanger components that received ASME Code Section III CUF or 

ANSI B31.1 design code analysis calculations. The staff noted that the applicant credited the 

TLAA analysis in LRA Section 4.3.4 with the management of cumulative fatigue damage in 

these components. The staff found that the applicant’s AMR assessment is in conformance 

with the recommendations in both the SRP-LR and in AMR item 2 of the GALL Report, 

Volume 1, Table 3 and AMR item VII.E3-14 in the GALL Report, Volume 2. Based on this 

review, the staff finds the applicant’s AMR analysis on cumulative fatigue damage of piping, 

piping components, piping elements, and heat exchanger components to be acceptable 

because it is in conformance with the recommendations in SRP-LR Section 3.3.2.2.1 and the 

GALL Report AMR items that are invoked by this SRP-LR section. The staff evaluates the 

TLAA analysis for the support skirt and attachment welds component in SER Section 4.3.4. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.1 criteria. For those items that apply to LRA Section 3.3.2.2.1, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-330 

3.3.2.2.2 Reduction of Heat Transfer Due to Fouling 

The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2. 

LRA Section 3.3.2.2.2 refers to LRA Table 3.3.1, item 3.3.1-3 and addresses stainless steel 

heat exchanger tubes exposed to treated water which are being managed for reduction in heat 

transfer due to fouling by the Water Chemistry and One-Time Inspection Programs. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that the Water 

Chemistry Program manages the reduction of heat transfer for these components in the fuel 

pool cooling and RHR systems, and that a One-Time Inspection Program will be implemented to 

verify the effectiveness of the Water Chemistry Program. The LRA also states that these 

components have been evaluated with the closed-cycle cooling water system, which provides 

the cooling water to these heat exchangers. 

The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2, which 

states that reduction of heat transfer due to fouling could occur for stainless steel heat 

exchanger tubes exposed to treated water. The SRP-LR also states that the existing program 

relies on control of water chemistry to manage reduction of heat transfer due to fouling; 

however, since control may have been inadequate, the effectiveness of the Water Chemistry 

Program should be verified. The SRP-LR also states that a one-time inspection is an 

acceptable method to verify the effectiveness of the Water Chemistry Program to ensure that 

reduction of heat transfer does not occur. 

The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection Program is 

documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. In its review of 

components associated with item 3.3.1-3, the staff finds the applicant’s proposal to manage 

aging using the above programs acceptable because the Water Chemistry Program provides for 

periodic sampling of treated water to maintain contaminants at acceptable limits to preclude loss 

of heat transfer due to fouling, and the One-Time Inspection Program will verify the 

effectiveness of the Water Chemistry Program by including inspections at appropriate locations, 

including low or stagnant flow areas. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.2 criteria. For those line items that apply to LRA Section 3.3.2.2.2, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.2.3 Cracking Due to Stress-Corrosion Cracking 

The staff reviewed LRA Section 3.3.2.2.3 against the criteria in SRP-LR Section 3.3.2.2.3. 

 (1) LRA Section 3.3.2.2.3.1 refers to Table 3.3.1, item 3.3.1-4 and addresses cracking due 

to SCC. The applicant stated that this aging effect is not applicable because the 

stainless steel piping, piping components, and piping elements exposed to sodium 

pentaborate solution are maintained at a temperature less than 60 °C (140 °F) at HCGS. 

 SRP-LR Section 3.3.2.2.3.1 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 60 °C (140 °F). 
Aging Management Review Results 

 3-331 

 The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.3.2.2.3, item 

1 is not applicable to HCGS because the stainless steel piping, piping components, and 

piping elements exposed to sodium pentaborate solution are maintained at a 

temperature less than 60 °C (140 °F) at HCGS, and the staff guidance in this SRP-LR 

section is only applicable to BWR stainless steel piping, piping components, and piping 

elements exposed to sodium pentaborate solution greater than 60 °C (140 °F). 

 (2) LRA Section 3.3.2.2.3, item 2 refers to LRA Table 3.3.1-5 and addresses stainless steel 

and stainless clad steel heat exchanger components exposed to treated water greater 

than 60°C (140 °F) which are being managed for cracking due to SCC by the Water 

Chemistry and One-Time Inspection Programs. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the Water Chemistry Program provides 

for monitoring and controlling water chemistry in accordance with the EPRI BWRVIP 

BWR Water Chemistry Guidelines which prevent or mitigate cracking due to SCC. The 

applicant also stated that the One-Time Inspection Program will verify the effectiveness 

of the Water Chemistry Program in the RWCU system. 

 The staff reviewed LRA Section 3.3.2.2.3, item 2 against the criteria in SRP-LR 

Section 3.3.2.2.3, item 2, which states that cracking due to SCC could occur in stainless 

steel and stainless clad steel heat exchanger components exposed to treated water 

greater than 60 °C (140 °F). The SRP-LR also states that the GALL Report 

recommends further evaluation of a plant-specific AMP, using acceptance criteria 

described in Branch Technical Position RLSB-1, to ensure that these aging effects are 

adequately managed. 

 The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection 

Programs is documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. In its 

review of the applicant’s One-Time Inspection Program, the staff noted that the heat 

exchanger components will be subjected to enhanced visual inspection and/or 

volumetric inspection to detect cracking. Also, the applicant will use representative 

sampling to detect aging of components with similar environments, and any cracking 

discovered during these inspections will be evaluated through the corrective action 

program. In its review of components associated with item 3.3.1-5, the staff finds the 

applicant’s proposal to manage aging using the above programs acceptable because 

monitoring and controlling water chemistry in accordance with the cited standards will 

minimize cracking due to SCC, and the One-Time Inspection Program will verify the 

effectiveness of the Water Chemistry Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.3, item 2 criteria. For those line items that apply to LRA 

Section 3.3.2.2.3, item 2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (3) LRA Section 3.3.2.2.3.3 is referenced by LRA Table 3.3.1, item 3.3.1-6 and addresses 

stainless steel diesel engine exhaust expansion joints exposed to diesel exhaust which 

are being managed for SCC by the Periodic Inspection Program. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the program 

includes focused visual inspections to evaluate if material degradation is occurring which 

could result in a loss of component intended function, as a result of exposure to the 

environmental condition. 
Aging Management Review Results 

 3-332 

 The staff reviewed LRA Section 3.3.2.2.3.3 against the criteria in SRP-LR 

Section 3.3.2.2.3, item 3, which states that cracking due to SCC could occur in stainless 

steel diesel engine exhaust piping, piping components, and piping elements exposed to 

diesel exhaust. The SRP-LR recommends a plant-specific AMP to manage SCC. In 

addition, a further evaluation of the plant-specific program for these components is 

recommended to ensure that the aging effect is adequately managed. GALL Report 

item VII.H2-1 also recommends further evaluation of a plant-specific AMP to ensure that 

the aging effect is adequately managed. 

 The staff’s evaluation of the applicant’s Periodic Inspection Program is documented in 

SER Section 3.0.3.3.2. The staff notes that the program is acceptable because it 

requires visual inspections and nondestructive volumetric examinations to ensure that 

the existing environmental conditions are not causing environmental degradation that 

could result in a loss of the component’s intended function. In its review of components 

associated with item 3.3.1-6, the staff finds the applicant’s proposal to manage aging 

using the Periodic Inspection Program acceptable because it requires inspection 

techniques that will be able to properly manage the SCC aging effect. 

 Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.3.3 criteria. For those line items that apply to LRA 

Section 3.3.2.2.3.3, the staff determines that the LRA is consistent with the GALL Report 

and the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

program meets SRP-LR Section 3.3.2.2.3. For those line items that apply to LRA 

Section 3.3.2.2.3, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.4 Cracking Due to Stress-Corrosion Cracking and Cyclic Loading 

The staff reviewed LRA Section 3.3.2.2.4 against the criteria in SRP-LR Section 3.3.2.2.4. 

 (1) LRA Section 3.3.2.2.4.1 refers to Table 3.3.1, item 3.3.1-7 and addresses cracking due 

to SCC and cyclic loading. The applicant stated that this aging effect is not applicable to 

HCGS, which is a BWR. 

 SRP-LR Section 3.3.2.2.4.1 states that cracking due to SCC and cyclic loading could 

occur in stainless steel PWR non-regenerative heat exchanger components exposed to 

treated borated water greater than 60 °C (140 °F) in the chemical and volume control 

system. SRP-LR Table 3.3-1 identifies item 7 applicable to PWRs. 

 The staff verified that SRP-LR Section 3.3.2.2.4.1 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWR stainless steel non-regenerative heat exchanger components exposed to treated 

borated water greater than 60 °C (140 °F). 
Aging Management Review Results 

 3-333 

 Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.3.2.2.4.1 do not apply to HCGS because the guidance is applicable to PWRs. 

 (2) LRA Section 3.3.2.2.4.2 refers to Table 3.3.1, item 3.3.1-8 and addresses cracking due 

to SCC and cyclic loading. The applicant stated that this aging effect is not applicable to 

HCGS, which is a BWR. 

 SRP-LR Section 3.3.2.2.4.2 states that cracking due to SCC and cyclic loading could 

occur in stainless steel PWR regenerative heat exchanger components exposed to 

treated borated water greater than 60 °C (140 °F) in the chemical and volume control 

system. SRP-LR Table 3.3-1 identifies item 8 as applicable to PWRs. 

 The staff verified that SRP-LR Section 3.3.2.2.4.2 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWR stainless steel regenerative heat exchanger components exposed to treated 

borated water greater than 60 °C (140 °F). 

 Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.3.2.2.4.2 do not apply to HCGS because the guidance is applicable to PWRs. 

 (3) LRA Section 3.3.2.2.4.3 refers to Table 3.3.1, item 3.3.1-9 and addresses cracking due 

to SCC and cyclic loading. The applicant stated that this aging effect is not applicable to 

HCGS, which is a BWR. 

 SRP-LR Section 3.3.2.2.4.3 states that cracking due to SCC and cyclic loading could 

occur in the stainless steel pump casing for the PWR high-pressure pumps in the 

chemical and volume control system. SRP-LR Table 3.3-1 identifies item 9 as 

applicable to PWRs. 

 The staff verified that SRP-LR Section 3.3.2.2.4.3 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWR stainless steel high-pressure pump casings in PWR chemical and volume control 

systems. 

 Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.3.2.2.4.3 do not apply to HCGS because the guidance is applicable to PWRs. 

 (4) LRA Section 3.3.2.2.4.4 refers to Table 3.3.1, item 3.3.1-10 and addresses cracking due 

to SCC and cyclic loading. The applicant stated that this aging effect is not applicable 

because HCGS does not have any high-strength bolting in the auxiliary system. 

 SRP-LR Table 3.3-1, item 10 has a related item A-104 as evaluated in Chapter VII.E1 of 

the GALL Report. Chapter VII.E1 of the GALL Report discusses a portion of the PWR 

chemical and volume control system and its aging effect to cracking due to SCC and 

cyclic loading. 

 The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.3.2.2.4, 

item 4 is not applicable to HCGS because HCGS does not have any high-strength 

bolting in the auxiliary system and the staff guidance in this SRP-LR section is only 

applicable to high-strength steel closure bolting exposed to air with steam or water 

leakage. 
Aging Management Review Results 

 3-334 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.3.2.2.4 criteria. For those line items that apply to LRA 

Section 3.3.2.2.4, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 

 (1) LRA Section 3.3.2.2.5.1 refers to Table 3.3.1, item 3.3.1-11 and addresses elastomer 

seals and components in the filtration, recirculation, and ventilation system; the control 

room and control area HVAC system; the reactor building ventilation system; the remote 

shutdown panel room HVAC system; the service water intake ventilation system; and the 

standby diesel generator area ventilation system exposed to air – indoor (external) or to 

air or gas – wetted (external) environments. The applicant stated that hardening and 

loss of strength in these components will be managed by the Periodic Inspection 

Program. The applicant also stated that compressible joints in the reactor building are 

aligned to item 3.3.1-11 based on material, environment, and aging effect and that for 

these components, the Structures Monitoring Program will be used to manage hardening 

and loss of strength. The applicant addressed the further evaluation requirement by 

stating that the Periodic Inspection Program is used to manage aging effects of 

components that are not covered by other AMPs, including external and internal 

surfaces of non-steel components, and that the Periodic Inspection Program includes 

visual inspections and physical manipulation of elastomer components. The applicant 

also stated that the Structures Monitoring Program includes visual inspections of 

elastomer components to assure that existing environmental conditions are not causing 

material degradation that could result in a loss of component intended function. 

 The staff reviewed LRA Section 3.3.2.2.5.1 against the criteria in SRP-LR 

Section 3.3.2.2.5.1, which states that hardening and loss of strength due to elastomer 

degradation could occur in elastomer seals and components of heating and ventilation 

systems exposed to air – indoor uncontrolled. The GALL Report recommends further 

evaluation of a plant-specific AMP to ensure that these aging effects are adequately 

managed. 

 The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is 

documented in SER Section 3.0.3.3.2. In its review of components associated with LRA 

item 3.3.1-11 for which the applicant assigned generic note E, the staff noted that the 

Periodic Inspection Program is a plant-specific program that proposes to detect the 

aging of elastomer door seals and flexible connections through the use of visual 

inspections and physical manipulations. The staff finds the applicant’s proposal to 

manage aging of elastomer components in heating and ventilation systems using the 

Periodic Inspection Program acceptable because: (1) the program performs visual 

inspections and physical manipulations that are capable of detecting hardening and loss 

of strength in elastomer components, and (2) the program initiates corrective actions, 

implemented through the applicant’s corrective action program, if indications of 

age-related degradation are found. 

 The staff reviewed the applicant’s Structures Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.16. In its review of components associated with 

LRA item 3.3.1-11 for which the applicant assigned generic note E, the staff noted that 

the Structures Monitoring Program includes monitoring elastomer components within its 
Aging Management Review Results 

 3-335 

scope for hardening, shrinkage, loss of sealing, or loss of strength. The staff notes that 

for the inflatable pool seal in Table 3.5.2-8, it is not practical to perform physical 

manipulation of the elastomer due to it being in service, but also notes that visual 

inspection is adequate because it would detect air bubbles if the seal should be 

degrading. The staff finds that the applicant’s proposal to manage aging of elastomer 

compressible joints and seals (inflatable pool seals) in the reactor building with the 

Structures Monitoring Program acceptable because the program: (1) performs visual 

inspections that are capable of detecting degradation of elastomer components within its 

scope and (2) implements corrective actions if degradation is found, through the 

applicant’s corrective action program, prior to loss of the component’s intended 

function(s). 

 Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.5.1 criteria. For those line items that apply to LRA 

Section 3.3.2.2.5.1, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (2) LRA Section 3.3.2.2.5.2 refers to Table 3.3.1, item 3.3.1-12 and addresses elastomer 

compressible joints and seals (inflatable pool seals) in the reactor building exposed to 

treated water. The applicant stated that compressible joints and seals (inflatable pool 

seals) in the reactor building are aligned to item 3.3.1-12 based on material, 

environment, and aging effect and that for these components, the Structures Monitoring 

Program will be used to manage hardening and loss of strength. The applicant 

addressed the further evaluation requirement by stating that the Structures Monitoring 

Program includes visual inspections of elastomer components to assure that existing 

environmental conditions are not causing material degradation that could result in a loss 

of component intended function. 

 The staff reviewed LRA Section 3.3.2.2.5.2 against the criteria in SRP-LR 

Section 3.3.2.2.5.2, which states that hardening and loss of strength due to elastomer 

degradation could 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 GALL Report recommends that a plant-specific AMP be 

evaluated to determine and assess the qualified life of the linings in the environment to 

ensure that these aging effects are adequately managed. 

 Based on information available in the LRA, the staff was unable to determine whether 

the applicant had assessed the qualified life of the inflatable pool seals, as 

recommended in the SRP-LR for components aligned with Table 3.3.1, item 3.3.1-12. 

By letter dated July 9, 2010, the staff issued RAI 3.3.2.2.5.2 requesting that the 

applicant: (1) clarify whether it has determined a qualified life for the compressible joint 

seals aligned with item 3.3.1-12, and (2) explain how visual inspection by the Structures 

Monitoring Program will detect hardening and loss of strength adequate to ensure that 

the compressible joint seals continue to perform their intended function during the period 

of extended operation. 

 In its response dated June 6, 2010, the applicant stated that it has determined that these 

components, inflatable pool seals exposed to treated water and air – indoor environment 

which include the reactor well to dryer separator pool gate seal, spent fuel pool to the 

reactor cavity gate seals, and spent fuel pool to cask storage pool gate seals, are not 
Aging Management Review Results 

 3-336 

subject to an AMR. The applicant also stated that the basis for the reactor well to dryer 

separator pool gate seal not being within scope is that: (1) it would only be used during 

refueling outages if it becomes necessary to drain the reactor cavity without draining the 

dryer separator pool; (2) this function has not been, nor is planned to be, used; (3) the 

seal is not associated with the spent fuel storage pool; and (4) the seal has no intended 

function for license renewal. The LRA is being revised to remove these components. 

The applicant further stated that the other two seals are replaced on a 10 year basis. 

 The staff finds the applicant’s response acceptable because the seals either do not 

perform a license renewal function or they are not long-lived passive items. The staff’s 

concern described in RAI 3.3.2.2.5.2 is resolved. 

 On the basis of its review, the staff finds that the applicant has appropriately determined 

that these components do not require an AMP, as required by 10 CFR 54.4 and 

10 CFR 54.21(a)(1)(ii). 

Based on a review of the programs identified, the staff concludes that the applicant’s programs 

meet SRP-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA 

Section 3.3.2.2.5, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion 

LRA Section 3.3.2.2.6 is associated with LRA Table 3.3.1, item 3.3.1-13 and addresses the 

neutron-absorbing sheets, made of Boral or boron steel, in spent fuel storage racks exposed to 

treated or treated borated water which are being managed for reduction of neutron-absorbing 

capacity and loss of material due to general corrosion by the Boral Monitoring Program and 

Water Chemistry Program. 

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 for neutron-absorbing sheets, made of Boral or boron steel, in spent fuel storage 

racks exposed to treated or 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. 

The staff notes that the applicant has plant-specific AMPs for Boral and water chemistry that are 

reviewed in SER Sections 3.0.3.3.5 and 3.0.3.2.1, respectively. 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 and Water Chemistry Program acceptable because it is consistent 

with the GALL Report. 

Based on the programs identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.6 criteria. For those line items that apply to LRA Section 3.3.2.2.6, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-337 

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 criteria in SRP-LR Section 3.3.2.2.7. 

 (1) LRA Section 3.3.2.2.7.1 is associated with Table 3.3.1, item 3.3.1-14 and addresses 

steel piping, piping components, and piping elements exposed to lubricating oil in the 

CRD system and standby diesel generators and auxiliary systems 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 requirements by stating that the One-Time Inspection Program will 

be used to verify the effectiveness of the Lubricating Oil Analysis Program. The 

applicant also stated that items 3.3.1-15 and 3.3.1-16 do not apply because HCGS does 

not have a reactor coolant pump oil collection system or a reactor coolant pump oil 

collection system tank. The staff noted that a search of the applicant’s UFSAR showed 

that there was no reactor coolant pump oil collection system listed. 

 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 for 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 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. However, control of lube oil contaminants may not always 

have been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil 

control should be verified to ensure that corrosion does not occur. A one-time inspection 

of select components at susceptible locations is an acceptable method to ensure that 

corrosion is not occurring or is progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. 

 The staff reviewed the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs and its evaluations are documented in SER Sections 3.0.3.2.13 and 

3.0.3.1.11, respectively. In its review of components associated with LRA item 3.3.1-14, 

the staff finds the applicant’s proposal to manage aging using the Lubricating Oil 

Analysis and One-Time Inspection Programs acceptable because: (1) the applicant will 

perform sufficient inspections for each material-environment combination to provide an 

overall assessment of any aging degradation that may be occurring; (2) 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; (3) recurring surveillance and maintenance activities provide the ability 

to detect aging of the material-environment combination prior to loss of function; and 

(4) inspection results will be trended. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7, item 1 criteria. For those line items that apply to LRA 

Section 3.3.2.2.7.1, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-338 

 (2) LRA Section 3.3.2.2.7 is referenced by LRA Table 3.3.1, item 3.3.1-17 and addresses 

steel piping, piping components, and piping elements exposed to treated water which 

are being managed for loss of material due to general, pitting, and crevice corrosion. 

The applicant addressed the further evaluation criteria of the SRP-LR by stating that it 

will implement its One-Time Inspection Program to verify the effectiveness of the Water 

Chemistry Program to manage loss of material due to general, pitting, and crevice 

corrosion of the steel piping, piping components, piping elements, heat exchanger 

components and tanks exposed to treated water at select locations and systems (control 

area chilled water system, CRD system, fuel handling and storage system, fuel pool 

cooling and cleanup system, primary containment, RWCU system, standby diesel 

generators and auxiliary systems, standby liquid control system, and torus water cleanup 

system). 

 The staff reviewed LRA Section 3.3.2.2.7, item 2 against the criteria in SRP-LR 

Section 3.3.2.2.7, item 2, which states that: (1) loss of material due to general, pitting, 

and crevice corrosion could occur in steel piping, piping components, and piping 

elements in the BWR RWCU and shutdown cooling systems exposed to treated water; 

(2) the existing AMP relies on monitoring and control of water chemistry to mitigate 

corrosion; and (3) control of water chemistry does not preclude corrosion at locations of 

stagnant flow conditions. The effectiveness of the water chemistry program, therefore, 

should be verified using a one-time inspection to ensure that corrosion does not occur. 

The GALL Report recommends a one-time inspection of select components at 

susceptible locations as an acceptable method to verify the effectiveness of the Water 

Chemistry Program and ensure that an aging effect is not occurring or is progressing 

very slowly so that the component’s intended function will be maintained during the 

period of extended operation. 

 The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection 

Programs are documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. The 

staff finds this combination of programs acceptable to manage aging for these 

components because the programs: (1) provide for periodic sampling of treated water to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 

pitting, and crevice corrosion; and (2) will perform one-time inspections of steel, piping 

components, piping elements, heat exchanger components and tanks exposed to 

treated water. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7, item 2 criteria. For those line items that apply to LRA 

Section 3.3.2.2.7, item 2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (3) LRA Section 3.3.2.2.7.3 refers to LRA Table 3.3.1, item 3.3.1-18 and addresses 

stainless steel and steel diesel engine exhaust piping and components exposed to diesel 

exhaust which are being managed for loss of material due to pitting and crevice 

corrosion by the Periodic Inspection and Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Programs. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the programs include focused visual 

inspections to evaluate if material degradation occurs that results in a loss of component 

intended function as a result of exposure to the environmental condition. 
Aging Management Review Results 

 3-339 

 The staff reviewed LRA Section 3.3.2.2.7.3 against the criteria in SRP-LR 

Section 3.3.2.2.7, item 3, which states that loss of material could occur in stainless steel 

diesel engine exhaust piping, piping components, and piping elements exposed to diesel 

exhaust. The SRP-LR recommends a plant-specific AMP to manage the loss of material 

aging effect. In addition, a further evaluation of the plant-specific program for these 

components is recommended to ensure that the aging effect is adequately managed. 

GALL Report item VII.H2-2 also recommends further evaluation of a plant-specific AMP 

to ensure that the aging effect is adequately managed. 

 The staff’s evaluations of the applicant’s Periodic Inspection and Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Programs are documented 

in SER Sections 3.0.3.3.2 and 3.0.3.1.14, respectively. The staff notes that the 

programs are acceptable because they require visual inspections and nondestructive 

volumetric examinations to ensure that the existing environmental conditions are not 

causing environmental degradation that could result in a loss of the component’s 

intended function. In its review of components associated with item 3.3.1-18, the staff 

finds the applicant’s proposal to manage aging using the Periodic Inspection and 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Programs acceptable because the inspection techniques in these two programs will be 

able to properly manage the loss of material due to pitting and crevice corrosion. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7, item 3 criteria. For those line items that apply to LRA 

Section 3.3.2.2.7.3, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function will be maintained consistent with the CLB during 

the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA 

Section 3.3.2.2.7, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.8 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. 

LRA Section 3.3.2.2.8 is associated with Table 3.3.1, item 3.3.1-19 and addresses loss of 

material due to general, pitting, crevice, and microbiologically-influenced corrosion in steel 

piping, piping components, and piping elements with or without coating or wrapping in the fire 

protection and service water systems exposed to soil. The applicant stated that these items will 

be managed by the Buried Piping Inspection Program.

The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8, which 

states that loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion could occur in steel piping, piping components, and piping elements with or without 

coating or wrapping in a soil environment. The SRP-LR also states that the effectiveness of the 

buried piping and tanks inspection program should be verified to evaluate the applicant’s 
Aging Management Review Results 

 3-340 

inspection frequency and operating experience with buried components, ensuring that loss of 

material does not occur. 

The staff reviewed the LRA AMR items associated with Table 3.3.1, item 3.3.1-19 and noted 

that for the items that are consistent with the GALL Report for material, environment, and aging 

effect but a different AMP is credited (generic note E) in Table 3.3.2-10, the applicant will use 

the Aboveground Steel Tanks Program to manage the loss of material due to pitting, crevice, 

and microbiologically-influenced corrosion for the steel tanks in the fire protection system. The 

staff reviewed the applicant’s Aboveground Steel Tanks Program, The staff’s evaluation is 

documented in and its evaluation is documented in SER Section 3.0.3.2.9. The staff finds the 

use of the Aboveground Steel Tanks Program acceptable because it credits the application of 

paint as a corrosion preventive measure and requires periodic visual inspections of the 

accessible tank outer surface and wall-thickness measurements of the inaccessible tank bottom 

external surface by UT to ensure that loss of material will be adequately managed. 

The staff reviewed the LRA AMR items associated with Table 3.3.1, item 3.3.1-19 and noted 

that for the items that are consistent with the GALL Report for material, environment, and aging 

effect but a different AMP is credited (generic note E) in Tables 3.5.2-1, 3.5.2-2, 3.5.2-3, 3.5.2-5, 

3.5.2-8, 3.5.2-11, 3.5.2-12, and 3.5.2-13, the applicant will use the Structures Monitoring 

Program to manage loss of material due to pitting, crevice, and microbiologically-influenced 

corrosion for the steel piles in the auxiliary boiler building, fire water pump house, switchyard, 

and yard structures and for the steel and galvanized steel penetration sleeves in the auxiliary 

building control and diesel generator and service and radwaste areas, fire water pump house, 

reactor building, turbine building, and yard structures. The staff reviewed the applicant’s 

Structures Monitoring Program and its evaluation is documented in SER Section 3.0.3.2.16. 

For component type piles as contained in the above AMR line items, LRA Section 3.5.2.2.2.2, 

item 3 states that: 

Degradation of piles or foundation mats will manifest in settlement distortion or 

cracking, and accessible concrete examinations will detect cracks and distortion 

of Groups 1 and 3 structures. Studies have shown that steel piles driven into 

undisturbed natural soil are not appreciably affected by corrosion due to the 

oxygen deficiency in soil at a few feet below grade. Piles driven into disturbed 

soil, have been shown to experience only minor to moderate corrosion. In either 

case the observed loss of material due to corrosion was not considered 

significant enough to impact the intended function of the piles, which is consistent 

with NUREG-1557. The condition of the accessible and above grade concrete 

are used as an indicator for the condition of the inaccessible and below grade 

structural components and provides reasonable assurance that degradation of 

inaccessible structural components will be detected before a loss of an intended 

function. However inaccessible concrete for Groups 1 and 3 structures will be 

inspected for cracking and distortion due to settlement if excavated for any 

reason as required by the Structures Monitoring Program. 

The staff finds the use of the Structures Monitoring Program acceptable for managing the aging 

effects associated with these piles because the program inspects the concrete structures for 

indications of deterioration and distress, including cracking as defined in ACI 201.1R at a 

frequency not to exceed 5 years. 

Due to potential accessibility constraints associated with the penetration sleeves being located 

in a groundwater or soil environment as contained in the above AMR line items, the staff was 
Aging Management Review Results 

 3-341 

unclear how the Structures Monitoring Program, which is primarily a visual-based program, will 

be used to address the structure and aging effect combinations during the period of extended 

operation. By letter dated June 7, 2010, the staff issued RAI 3.5.2.1-1 requesting that the 

applicant describe how the Structures Monitoring Program meets GALL Report recommended 

programs and how the AMP will be used to manage aging effects, including a discussion of 

preventive measure requirements. 

In its response dated June 29, 2010, the applicant stated that: (1) the penetration sleeves were 

aligned to GALL Report item 3.3.1-19 to show agreement between the LRA and the GALL 

Report with respect to the identified aging effects and mechanisms for the material and 

environment combination (the alignment was not intended to suggest consistency with the AMP 

recommended by the GALL Report), and (2) the recommended GALL Report programs are not 

applicable for aging management of the penetration sleeves. The applicant also stated that the 

penetration sleeves are installed in concrete walls, and the majority of the sleeve is located 

within the wall, while a small portion may protrude past the wall surface and into a soil 

environment. Most of the sleeve is protected on both the outer and inner surface by concrete, 

grout, or elastomer seal material. The applicant further stated that potential degradation of the 

small portion of the steel sleeve that protrudes past the exterior wall surface and is subject to 

the groundwater or soil environment will not impact the intended function given that most of the 

sleeve is protected on both the inner and outer surface and thus degradation of this area of the 

sleeve is unlikely to penetrate to a wall depth sufficient to impact the intended function. The 

applicant stated that the Structures Monitoring Program includes inspections of the penetration 

seals and the associated sleeves on a 5 year interval. These inspections will detect material 

degradation or indications of seal leakage prior to loss of intended function. 

The staff reviewed the applicant’s response and noted that the penetration sleeves are 

structural components embedded in concrete and that the buried portion is not reasonably 

accessible for inspection. Visual inspections from the inside of the wall, on a 5 year frequency, 

will be able to detect degradation prior to a loss of intended function. Based on its review, the 

staff finds the applicant’s aging management approach acceptable because the Structures 

Monitoring Program includes appropriate inspections to detect degradation of the penetration 

sleeves prior to a loss of intended function. The staff’s concern in RAI 3.5.2.1-1 is resolved. 

The staff finds the use of the Structures Monitoring Program acceptable for managing the aging 

effects associated with these penetration sleeves for the reasons as stated in the staff’s 

evaluation of the applicant’s response to RAI 3.5.2.1-1. 

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 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that 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). 
Aging Management Review Results 

 3-342 

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion and Fouling 

The staff reviewed LRA Section 3.3.2.2.9 against the criteria in SRP-LR Section 3.3.2.2.9. 

 (1) LRA Section 3.3.2.2.9.1 is associated with Table 3.3.1, item 3.3.1-20 and addresses 

steel piping, piping components, piping elements, and tanks exposed to fuel oil in the fire 

protection and standby diesel generators and auxiliary systems which are being 

managed for loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion and fouling by the Fuel Oil Chemistry and 

One-Time Inspection Programs. The applicant addressed the further evaluation 

requirements by stating that the One-Time Inspection Program will be used to verify the 

effectiveness of the Fuel Oil Chemistry Program. 

 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 that loss of material due to general, pitting, 

crevice, and microbiologically-influenced corrosion and fouling could occur for steel 

piping, piping components, piping elements, and tanks exposed to fuel oil. The SRP-LR 

also states 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 verified to ensure that 

corrosion does not occur. A one-time inspection of select components at susceptible 

locations is an acceptable method to ensure that corrosion is not occurring or 

progressing very slowly so that the component’s intended function will be maintained 

during the period of extended operation. 

 The staff reviewed the applicant’s Fuel Oil Chemistry and One-Time Inspection 

Programs and its evaluations are documented in SER Sections 3.0.3.2.10 and 

3.0.3.1.11, respectively. The applicant stated that the One-Time Inspection Program 

includes: (1) determination of sample size based on an assessment of materials, 

environment, plausible aging effects and mechanisms, and operating experience; 

(2) identification of inspection locations based on the aging effect; (3) selection of the 

examination technique with acceptance criteria; and (4) evaluation of the results 

including the need for additional inspections or other corrective actions. The staff finds 

the applicant’s proposal to manage aging for these components acceptable because: 

(1) the Fuel Oil Chemistry Program will assure that contaminants are maintained at 

acceptable levels in fuel oil and identify the actions required if the fuel oil contaminants 

exceed limits, and (2) the One-Time Inspection Program will include a one-time 

inspection of select components at susceptible locations (e.g., low or stagnant flow 

areas) to verify the effectiveness of the Fuel Oil Chemistry Program for managing the 

effects of aging due to the potential corrosion mechanisms. 

 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 those line items that apply to LRA 

Section 3.3.2.2.9.1, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-343 

 (2) LRA Section 3.3.2.2.9.2 is associated with Table 3.3.1, item 3.3.1-21 and addresses 

steel heat exchanger components exposed to lubricating oil in the closed-cycle cooling 

water system which are being managed for loss of material due to general, pitting, 

crevice, and microbiologically-influenced corrosion and fouling by the Lubricating Oil 

Analysis and One-Time Inspection Programs. The applicant addressed the further 

evaluation requirements by stating that the One-Time Inspection Program will be used to 

verify the effectiveness of the Lubricating Oil Analysis Program. Lubricating oil systems 

are maintained to high cleanliness standards. Lubricating oil formulations include 

corrosion inhibitors; thus, the potential for water and contaminant intrusion is low 

compared to fuel oil systems, where the bulk storage, delivery, and transport of the fuel 

oil increase the likelihood of moisture and microorganism contamination. 

 The staff reviewed LRA Section 3.3.2.2.9.2 against the criteria in SRP-LR 

Section 3.3.2.2.9, item 2, which states that loss of material due to general, pitting, 

crevice, and microbiologically-influenced corrosion and fouling could occur for steel heat 

exchanger components 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. However, control of lube oil contaminants may not always 

have been adequate to preclude corrosion. Therefore, the effectiveness of lubricating oil 

control should be verified to ensure that corrosion does not occur. A one-time inspection 

of select components at susceptible locations is an acceptable method to ensure that 

corrosion is not occurring or progressing very slowly so that the component’s intended 

function will be maintained during the period of extended operation. 

 The staff reviewed the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs and its evaluations are documented in SER Sections 3.0.3.2.13 and 

3.0.3.1.11, respectively. In its review of components associated with LRA item 3.3.1-21, 

the staff finds the applicant’s proposal to manage aging using the Lubricating Oil 

Analysis and One-Time Inspection Programs acceptable because: (1) the applicant will 

perform sufficient inspections for each material-environment combination to provide an 

overall assessment of any aging degradation that may be occurring; (2) 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; (3) recurring surveillance and maintenance activities provide the ability 

to detect aging of the material-environment combination prior to loss of function; and 

(4) inspection results will be trended. 

 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 those line items that apply to LRA 

Section 3.3.2.2.9.2, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on a review of the programs identified, the staff concludes that the applicant’s programs 

meet SRP-LR Section 3.3.2.2.9 criteria. For those line items that apply to LRA 

Section 3.3.2.2.9, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-344 

3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP-LR Section 3.3.2.2.10. 

 (1) LRA Section 3.3.2.2.10.1 refers to Table 3.3.1, item 3.3.1-22 and addresses loss of 

material due to pitting and crevice corrosion. The applicant stated that this aging effect 

is not applicable because there is no steel piping with elastomer lining or steel piping 

with stainless steel cladding exposed to treated water in the auxiliary system that are 

within the scope of license renewal at HCGS. 

 SRP-LR Section 3.3.2.2.10.1 states that loss of material due to pitting and crevice 

corrosion could occur in BWR and PWR steel piping with elastomer lining or stainless 

steel cladding that are exposed to treated water and treated borated water if the cladding 

or lining is degraded. 

 The staff reviewed the applicant’s UFSAR and finds that SRP-LR Section 3.3.2.2.10, 

item 1 is not applicable to HCGS because there is no steel piping with elastomer lining 

or steel piping with stainless steel cladding exposed to treated water in the auxiliary 

system that are within the scope of license renewal at HCGS, and the staff guidance in 

this SRP-LR section is only applicable to steel piping with elastomer lining or steel piping 

with stainless steel cladding exposed to treated water in the auxiliary system that are 

within the scope of license renewal. 

 (2) LRA Section 3.3.2.2.10, item 2 referenced by LRA Table 3.3.1, items 3.3.1-23 and 

3.3.1-24 addresses stainless steel and aluminum piping, piping components, and piping 

elements and stainless steel heat exchanger components exposed to treated water 

which are being managed for loss of material due to pitting and crevice corrosion. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that the 

Water Chemistry and One-Time Inspection Programs will be used to manage this aging 

effect for related components in a variety of systems. 

 The staff reviewed LRA Section 3.3.2.2.10, item 2 against the criteria described in 

SRP-LR Section 3.3.2.2.10, item 2, which states that loss of material due to pitting and 

crevice corrosion could occur for stainless steel and aluminum piping, piping 

components, and piping elements and for stainless steel and steel with stainless steel 

cladding heat exchanger components exposed to treated water. The SRP-LR also 

states that the existing AMP relies on monitoring and controlling water chemistry to 

mitigate degradation and that a one-time inspection of components at susceptible 

locations is an acceptable method to verify the effectiveness of the water chemistry 

program. 

 The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection 

Programs is documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. In its 

review of components associated with items 3.3.1-23 and 3.3.1-24, the staff finds that 

the credited programs are acceptable because the Water Chemistry Program will ensure 

that contaminants are maintained below applicable limits to minimize loss of material 

due to pitting and crevice corrosion, and the One-Time Inspection Program will verify the 

effectiveness of the Water Chemistry Program by including inspections at appropriate 

locations, including low or stagnant flow areas. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 2 criteria. For those items that apply to LRA 
Aging Management Review Results 

 3-345 

Section 3.3.2.2.10, item 2, the staff determines that the LRA is consistent with the GALL 

Report and 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) LRA Section 3.3.2.2.10.3 refers to LRA Table 3.3.1, item 3.3.1-25 and addresses copper 

alloy HVAC piping, piping components, and piping elements exposed to condensation 

(external) which are being managed for loss of material due to pitting and crevice 

corrosion by the Periodic Inspection Program. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the Periodic Inspection Program will be 

implemented to manage loss of material due to pitting and crevice corrosion of the 

copper alloy HVAC piping, piping components, and piping elements exposed to wetted 

air or gas in the control room and control area HVAC systems; filtration, recirculation, 

and ventilation system; remote shutdown panel room HVAC system; and standby diesel 

generator area ventilation system. The applicant stated that the wetted air or gas 

environment assumed for these components includes the potential for wetting due to 

condensation. The applicant further stated that the Periodic Inspection Program 

includes visual inspections to assure that existing environmental conditions are not 

causing material degradation that could result in a loss of component intended functions. 

 The staff reviewed LRA Section 3.3.2.2.10.3 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 3, which 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 staff 

reviews the applicant’s plant-specific program to ensure that an adequate program will 

be in place for the management of these aging effects. 

 The staff’s evaluation of the applicant’s Periodic Inspection Program is documented in 

SER Section 3.0.3.3.2. The staff notes that the applicant is using the Periodic Inspection 

Program to manage loss of material due to pitting and crevice corrosion for copper alloy 

HVAC piping, piping components, and piping elements exposed to condensation by 

conducting visual inspection of copper alloy HVAC piping, piping components, and 

piping elements exposed to condensation to detect pitting and crevice corrosion. In its 

review of components associated with item 3.3.1-25, the staff finds the applicant’s 

proposal to manage aging using the Periodic Inspection Program acceptable because it 

requires visual inspection techniques which are capable of detecting loss of material due 

to corrosion by the presence of localized discoloration and surface irregularities, such as 

rust, scale, deposits, surface pitting, surface discontinuities, and coating degradation. 

 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 line items that apply to LRA 

Section 3.3.2.2.10.3, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (4) LRA Section 3.3.2.2.10.4 is associated with Table 3.3.1, item 3.3.1-26 and addresses 

copper alloy piping, piping components, and piping elements exposed to lubricating oil in 

the closed-cycle cooling water system 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 requirements by stating that 
Aging Management Review Results 

 3-346 

the One-Time Inspection Program will be used to verify the effectiveness of the 

Lubricating Oil Analysis Program. 

 The staff reviewed LRA Section 3.3.2.2.10.4, item 26 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 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. 

However, control of lube oil contaminants may not always have been adequate to 

preclude corrosion. Therefore, the effectiveness of lubricating oil control should be 

verified to ensure that corrosion does not occur. A one-time inspection of select 

components at susceptible locations is an acceptable method to ensure that corrosion is 

not occurring or progressing very slowly so that the component’s intended function will 

be maintained during the period of extended operation. 

 The staff reviewed the applicant’s Lubricating Oil Analysis and One-Time Inspection 

Programs and its evaluations are documented in SER Sections 3.0.3.2.13 and 

3.0.3.1.11, respectively. In its review of components associated with LRA item 3.3.1-26, 

the staff finds the applicant’s proposal to manage aging using the Lubricating Oil 

Analysis and One-Time Inspection Programs acceptable because: (1) the applicant will 

perform sufficient inspections for each material-environment combination to provide an 

overall assessment of any aging degradation that may be occurring; (2) 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; (3) recurring surveillance and maintenance activities provide the ability 

to detect aging of the material-environment combination prior to loss of function; and 

(4) inspection results will be trended. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10, item 4 criteria. For those line items that apply to LRA 

Section 3.3.2.2.10.4, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (5) LRA Section 3.3.2.2.10.5 refers to LRA Table 3.3.1, item 3.3.1-27 and addresses HVAC 

aluminum piping, piping components, piping elements, stainless steel ducting and 

components, and damper housing exposed to condensation which are being managed 

for loss of material due to pitting and crevice corrosion by the Periodic Inspection 

Program. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the Periodic Inspection Program will be implemented to manage loss of 

material due to pitting and crevice corrosion of the stainless steel and aluminum HVAC 

ducting and ducting components, damper housing, piping, piping components, and 

piping elements exposed to wetted air or gas in the control room and control area HVAC, 

fire pump house ventilation, makeup demineralizer, reactor building ventilation, remote 

shutdown panel room HVAC, service water intake ventilation, standby diesel generators 

and auxiliary, and standby diesel generator area ventilation systems. The applicant 

stated that the wetted air or gas environment assumed for these components includes 

the potential for wetting due to condensation. The applicant further stated that the 

Periodic Inspection Program includes visual inspections to assure that existing 
Aging Management Review Results 

 3-347 

environmental conditions are not causing material degradation that could result in a loss 

of component intended functions. 

 The staff reviewed LRA Section 3.3.2.2.10.5 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 5, which 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 damper housing components exposed to 

condensation. The SRP-LR also states that the staff reviews the applicant’s 

plant-specific program to ensure that an adequate program will be in place for the 

management of these aging effects. 

 The staff’s evaluation of the applicant’s Periodic Inspection Program is documented in 

SER Section 3.0.3.3.2. The staff notes that the applicant is using the Periodic Inspection 

Program to manage loss of material due to pitting and crevice corrosion for HVAC 

aluminum piping, piping components, and piping elements and stainless steel ducting 

and damper housing components exposed to condensation by conducting visual 

inspection of HVAC aluminum piping, piping components, and piping elements and 

stainless steel ducting and components exposed to condensation to detect pitting and 

crevice corrosion. In its review of components associated with item 3.3.1-27, the staff 

finds the applicant’s proposal to manage aging using the Periodic Inspection Program 

acceptable because it requires visual inspection techniques which are capable of 

detecting loss of material due to corrosion by the presence of localized discoloration and 

surface irregularities, such as rust, scale, deposits, surface pitting, surface 

discontinuities, and coating degradation. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10.5 criteria. For those line items that apply to LRA 

Section 3.1.2.2.10.5, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (6) LRA Section 3.3.2.2.10.6 refers to Table 3.3-1, item 3.3.1-28 and addresses copper 

alloy fire protection 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 by the Fire Protection and Fire Water System Programs. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that the Fire 

Protection and Fire Water System Programs include periodic system and component 

inspections that include inspection of the sprinkler heads and restricting orifices as part 

of surveillance activities. In addition, the Fire Water System Program includes 50-year 

sprinkler head inspections using the guidance of NFPA-25. 

 The staff reviewed LRA Section 3.3.2.2.10, item 6 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 6, which states that loss of material due to pitting and crevice 

corrosion, could occur for copper alloy fire protection system 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 program to ensure that 

these aging effects are adequately managed. 

 The staff’s evaluation of the applicant’s Fire Protection and Fire Water System Programs 

are documented in SER Sections 3.0.3.2.7 and 3.0.3.2.8, respectively. In its review of 

components associated with item 3.3.1-28 for which the applicant cited note E, the staff 
Aging Management Review Results 

 3-348 

noted that the applicant credited the Fire Protection Program to manage aging for 

copper alloy restricting orifices exposed to wetted air or gas in LRA Table 3.3.2-10. The 

staff also noted that the Fire Protection Program performs visual inspections of fire 

barriers and the external surfaces of the halon and CO2 systems and includes 

performance testing of the diesel driven fire pump fuel supply lines. The staff further 

noted that the Fire Protection Program does not include criteria for inspections of the 

internal surfaces of components which could detect loss of material for the copper alloy 

restricting orifice listed in Table 3.3.2-10. 

 By letter dated June 22, 2010, the staff issued RAI 3.3.2.2.10.6-1, requesting that the 

applicant justify how the Fire Protection Program will adequately manage loss of material 

due to pitting and crevice corrosion for copper alloy restricting orifices exposed to 

internal condensation. 

 In its response dated July 19, 2010, the applicant stated that the copper alloy restricting 

orifices in Table 3.3.2-10: (1) are located on sprinkler systems that use fused heads in 

order to allow testing of system alarms, (2) are normally isolated from the system by 

closed test valves, and (3) do not normally contain water. The applicant also stated that 

the restricting orifices have no safety or pressure boundary function and are not within 

the scope of license renewal. As a result, the applicant revised Table 3.3.2-10 to delete 

the AMR results for copper alloy restricting orifices exposed externally to indoor air and 

internally to wetted air or gas. The staff finds the applicant’s response to 

RAI 3.3.2.2.10.6-1 acceptable because the copper alloy restricting orifices in 

Table 3.3.2-10 are not within the flow path of a system credited with a safety function 

and do not contain water which could result in spatial interaction with a safety-related 

component and, therefore, are not within the scope of license renewal. The staff’s 

concern described in RAI 3.3.2.2.10.6-1 is resolved. 

 In its review of components associated with item 3.3.1-28, the staff noted that the 

applicant credited the Fire Water System Program to manage loss of material for copper 

alloy sprinkler heads exposed to wetted air or gas in LRA Table 3.3.2-10. The staff also 

noted that in it Fire Water System Program, the applicant stated an enhancement to its 

Fire Water System Program to replace or perform 50-year sprinkler head inspections 

and testing using the guidance of NFPA-25, “Standard for the Inspection, Testing and 

Maintenance of Water-Based Fire Protection Systems” (2002 Edition), Section 5-3.1.1. 

The applicant also stated that these inspections will be performed by the 50-year 

inservice date and every 10-years thereafter. The staff finds the applicant’s Fire Water 

System Program acceptable to manage loss of material for copper alloy sprinkler heads 

because the program will replace or test the sprinkler heads in accordance with industry 

standards, which is consistent with the GALL Report recommendations. 

 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 line items that apply to LRA 

Section 3.3.2.2.10, item 6, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (7) LRA Section 3.3.2.2.10.7 refers to Table 3.3.1, item 3.3.1-29 and addresses loss of 

material due to pitting and crevice corrosion in stainless steel piping, piping components, 

and piping elements exposed to soil. The applicant stated that this item is not applicable 

because the stainless steel components exposed to soil in the auxiliary systems are also 
Aging Management Review Results 

 3-349 

subject to MIC, in addition to pitting and crevice corrosion. The applicant also stated that 

the Buried Non-Steel Piping Inspection Program will be used to manage loss of material 

due to pitting, crevice, and microbiologically-influenced corrosion in stainless steel piping 

components and piping elements exposed to soil. 

 The staff reviewed LRA Section 3.3.2.2.10.7 against the criteria in SRP-LR 

Section 3.3.2.2.10.7, which states that loss of material due to pitting and crevice 

corrosion could occur in stainless steel piping, piping components, and piping elements 

in a soil environment. The GALL Report recommends further evaluation of a 

plant-specific program to ensure that the aging effect is adequately managed. The 

acceptance criteria for the further evaluation of the plant-specific AMP are described in 

Branch Technical Position RSLB-1. 

 The staff reviewed the LRA and identified in AMR items in Tables 3.3.2-10 and 3.4.2-1 

that the applicant will use the Buried Non-Steel Piping Inspection Program to manage 

the loss of material due to pitting, crevice, and microbiologically-influenced corrosion for 

the stainless steel piping and fittings exposed to soil. The AMR items cite generic 

note H indicating that the aging effect is not included in the GALL Report for this 

component, material, and environment combination. The staff further reviewed the 

applicant’s Buried Non-Steel Piping Inspection Program, which is evaluated in SER 

Section 3.0.3.3.4. The staff finds that the credited program is acceptable because the 

Buried Non-Steel Piping Inspection Program requires periodic visual inspections of the 

external surfaces of components when exposed to ensure that the loss of material aging 

effect will be adequately managed. The staff finds the applicant’s management for loss 

of material due to general, pitting, crevice, and microbiologically-influenced corrosion 

acceptable because the applicant satisfied the acceptance criteria in SRP-LR 

Section 3.3.2.2.10.7. 

 Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.3.2.2.10.7 criteria. For those items that apply to LRA 

Section 3.3.2.2.10.7, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that 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). 

 (8) LRA Section 3.3.2.2.10.8 is associated with Table 3.3.1, item 3.3.1-30 and addresses 

stainless steel piping, piping components, and piping elements exposed to sodium 

pentaborate solution which are being managed for loss of material due to pitting and 

crevice corrosion by the Water Chemistry and One-Time Inspection Programs. The 

applicant addressed the further evaluation requirements by stating that the One-Time 

Inspection Program will be used to verify the effectiveness of the Water Chemistry 

Program. 

 The staff reviewed LRA Section 3.3.2.2.10.8, item 30 against the criteria in SRP-LR 

Section 3.3.2.2.10, item 8, which states that loss of material due to pitting and crevice 

corrosion could occur in stainless steel piping, piping components, and piping elements 

of the BWR standby liquid control system exposed to sodium pentaborate solution. The 

SRP-LR also states that the existing program relies on monitoring and control of water 

chemistry to manage the aging effects of loss of material due to pitting and crevice 

corrosion. However, high concentrations of impurities at crevices and locations of 

stagnant flow conditions could cause loss of material due to pitting and crevice 

corrosion. Therefore, the GALL Report recommends that the effectiveness of the water 
Aging Management Review Results 

 3-350 

chemistry control program should be verified to ensure corrosion does not occur. A 

one-time inspection of select components at susceptible locations is an acceptable 

method to ensure that corrosion is not occurring or progressing very slowly so that the 

component’s intended function will be maintained during the period of extended 

operation. 

 The staff reviewed the applicant’s Water Chemistry and One-Time Inspection Programs 

and its evaluations are documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, 

respectively. In its review of components associated with LRA item 3.3.1-30, the staff 

finds the applicant’s proposal to manage aging using the Water Chemistry and 

One-Time Inspection Programs acceptable because the Water Chemistry Program will 

ensure that contaminants are maintained below applicable limits to minimize loss of 

material due to pitting and crevice corrosion, and the One-Time Inspection Program will 

verify the effectiveness of the Water Chemistry Program by including inspections at 

appropriate locations, including low or stagnant flow areas. 

 Based on the Programs identified, the staff concludes that the applicant’s programs 

meet SRP-LR Section 3.3.2.2.10, item 8 criteria. For those line items that apply to LRA 

Section 3.3.2.2.10.8, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.3.2.2.10 criteria. For those line items that apply to LRA 

Section 3.3.2.2.10, the staff determines that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion 

LRA Section 3.3.2.2.11 refers to Table 3.3.1, item 3.3.1-31 and addresses copper alloy piping, 

piping components, and piping elements exposed to treated water which are being managed for 

loss of material due to pitting, crevice, and galvanic corrosion by the Water Chemistry and 

One-Time Inspection Programs. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that monitoring and controlling water chemistry in accordance with specified 

guidelines prevent or mitigate loss of material aging effects in applicable components exposed 

to treated water in the HPCI and RCIC systems. The applicant also stated that the One-Time 

Inspection Program will verify the effectiveness of the Water Chemistry Program. 

The staff reviewed LRA Section 3.3.2.2.11 against the criteria described in SRP-LR 

Section 3.3.2.2.11, which states that loss of material due to pitting, crevice, and galvanic 

corrosion could occur for copper alloy piping, piping components, and piping elements exposed 

to treated water. The SRP-LR also states that the existing AMP relies on monitoring and 

controlling water chemistry to mitigate degradation and that a one-time inspection of select 

components at susceptible locations is an acceptable method to verify the effectiveness of the 

water chemistry program. 

The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection Programs is 

documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. In its review of 

components associated with item 3.3.1-31, the staff finds the applicant’s proposal to manage 
Aging Management Review Results 

 3-351 

aging using the above programs acceptable because the Water Chemistry Program will ensure 

that contaminants are maintained below applicable limits to minimize loss of material due to 

pitting, crevice, and galvanic corrosion, and the One-Time Inspection Program will verify the 

effectiveness of the Water Chemistry Program by including inspections at appropriate locations, 

including low or stagnant flow areas. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.11 criteria. For those items that apply to LRA Section 3.3.2.2.11, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

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). 

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

The staff reviewed LRA Section 3.3.2.2.12 against the criteria in SRP-LR Section 3.3.2.2.12. 

 (1) LRA Section 3.3.2.2.12.1 is associated with 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 in the fire protection system and the standby diesel 

generators and auxiliary systems which are being managed for loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion by the Fuel Oil Chemistry and 

One-Time Inspection Programs. The applicant addressed the further evaluation 

requirements by stating that the One-Time Inspection Program will be used to verify the 

effectiveness of the Fuel Oil Chemistry Program. 

 The applicant stated that for item 3.3.1-32, the applicability does not include aluminum 

piping, piping components, and piping elements exposed to fuel oil. The staff reviewed 

the LRA AMR items associated with Table 3.3.1, item 3.3.1-32 and confirmed that there 

are no aluminum piping, piping components, and piping elements exposed to fuel oil in 

the auxiliary systems. 

 The staff reviewed LRA Section 3.3.2.2.12.1 against the criteria in SRP-LR 

Section 3.3.2.2.12, item 1, which states that loss of material due to general, pitting, 

crevice, and microbiologically-influenced corrosion and fouling could occur for steel 

piping, piping components, piping elements, and tanks exposed to fuel oil. The SRP-LR 

also states 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 verified to ensure that 

corrosion does not occur. A one-time inspection of select components at susceptible 

locations is an acceptable method to ensure that corrosion is not occurring or 

progressing very slowly so that the component’s intended function will be maintained 

during the period of extended operation. 

 The staff reviewed the applicant’s Fuel Oil Chemistry and the One-Time Inspection 

Programs and its evaluations are documented in SER Sections 3.0.3.2.10 and 

3.0.3.1.11, respectively. The applicant stated that the One-Time Inspection Program 

includes: (1) determination of sample size based on an assessment of materials, 

environment, plausible aging effects and mechanisms, and operating experience; 

(2) identification of inspection locations based on the aging effect; (3) selection of the 

examination technique with acceptance criteria; and (4) evaluation of the results 
Aging Management Review Results 

 3-352 

including the need for additional inspections or other corrective actions. The staff finds 

the applicant’s proposal to manage aging for these components acceptable because: 

(1) the Fuel Oil Chemistry Program will assure that contaminants are maintained at 

acceptable levels in fuel oil and identify the actions required if the fuel oil contaminants 

exceed limits, and (2) the One-Time Inspection Program will include a one-time 

inspection of select components at susceptible locations (e.g., low or stagnant flow 

areas) to verify the effectiveness of the Fuel Oil Chemistry Program for managing the 

effects of aging due to the potential corrosion mechanisms. 

 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 line items that apply to LRA 

Section 3.3.2.2.12.1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 (2) LRA Section 3.3.2.2.12.2 is associated with Table 3.3.1, item 3.3.1-33 and addresses 

stainless steel piping, piping components, and piping elements exposed to lubricating oil 

for the standby diesel generators and auxiliary systems which are being managed for 

loss of material due to pitting, crevice, and microbiologically-influenced corrosion by the 

Lubricating Oil Analysis and One-Time Inspection Programs. The applicant addressed 

the further evaluation requirements by stating that the One-Time Inspection Program will 

be used to verify the effectiveness of the Lubricating Oil Analysis Program. The 

applicant also stated that loss of material due to MIC is not applicable for stainless steel 

in a lubricating oil environment, and industry and plant-specific operating experience 

indicates that the potential for significant degradation of lubricating oil systems due to 

MIC is minimal. Lubricating oil systems are maintained to high cleanliness standards by 

design, lubricating oil formulations include corrosion inhibitors, and the potential for 

water and contaminant intrusion is low compared to fuel oil systems, where the bulk 

storage, delivery, and transport of the fuel oil increases the likelihood of moisture and 

microorganism contamination. 

 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 

microbiologically-influenced corrosion could occur for stainless steel piping, piping 

components, and piping elements exposed to lubricating oil. The SRP-LR also states 

that the existing AMP relies on the lubricating oil analysis program for monitoring and 

control of lubricating oil contamination to manage loss of material due to corrosion. 

Corrosion or fouling may occur at locations where contaminants accumulate. The 

effectiveness of the lubricating oil chemistry control should be verified to ensure that 

corrosion does not occur. A one-time inspection of select components at susceptible 

locations is an acceptable method to ensure that corrosion is not occurring or 

progressing very slowly so that the component’s intended function will be maintained 

during the period of extended operation. 

 The staff reviewed the applicant’s Lubricating Oil Chemistry and One-Time Inspection 

Programs and its evaluations are documented in SER Sections 3.0.3.2.13 and 

3.0.3.1.11, respectively. In its review of components associated with LRA item 3.3.1-33, 

the staff finds the applicant’s proposal to manage aging using the Lubricating Oil 

Chemistry and One-Time Inspection Programs acceptable because: (1) the applicant will 

perform sufficient inspections for each material-environment combination to provide an 

overall assessment of any aging degradation that may be occurring; (2) the selection of 
Aging Management Review Results 

 3-353 

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; (3) recurring surveillance and maintenance activities provide the ability 

to detect aging of the material-environment combination prior to loss of function; and 

(4) inspection results will be trended. 

 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 those line items that apply to LRA 

Section 3.3.2.2.12.2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Based on a review of the programs identified above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA 

Section 3.3.2.2.12, the staff determines that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.13 Loss of Material Due to Wear 

LRA Section 3.3.2.2.13 refers to Table 3.3.1, item 3.3.1-34 and addresses elastomer 

components that are exposed to air – indoor uncontrolled (internal or external) and that may 

experience loss of material due to wear. The applicant stated that elastomer components 

determined to be subject to wear based on plant operating experience are periodically replaced 

and are not subject to an AMR. The applicant also stated that elastomer components that are 

not periodically replaced are evaluated for hardening and loss of strength due to elastomer 

degradation under Table 3.3.1, item 3.3.1-11 and are managed by the plant-specific Periodic 

Inspection Program. The applicant further stated that elastomeric fire barrier components are 

evaluated for increased hardness, shrinkage, and loss of strength due to weathering under 

Table 3.3.1, item 3.3.1-61 and are managed by the Fire Protection Program. 

The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13, 

which states that loss of material due to wear could occur in elastomer seals and components 

exposed to air – indoor uncontrolled (internal or external). The GALL Report recommends 

further evaluation to ensure that these aging effects are adequately managed. 

By letter dated June 3, 2010, the staff issued RAI 3.3.2.2.13-01 requesting that the applicant: 

(1) identify what systems contain in-scope elastomer components that experience wear and are 

subject to periodic replacement, (2) clarify whether the replacement frequency for elastomer 

components is based on a qualified life or a specified time period, (3) provide the technical basis 

for the component’s qualified life or replacement time period, and (4) justify that the replacement 

frequency is adequate to ensure that failure due to age-related wear does not occur between 

successive replacements. 

In its response dated June 30, 2010, the applicant stated that in-scope elastomer components 

that experience wear and are subject to periodic replacement are the inflatable elastomer seals 

in the fuel pool gates and fire hoses. The inflatable elastomer gate seals are subject to relative 

motion between two surfaces during gate installation and removal activities and are, therefore, 

potentially subject to wear or mechanical damage to the elastomer surfaces. Fire hoses are 
Aging Management Review Results 

 3-354 

subject to relative motion when installed on hose reels or hose racks, or when deployed for use 

or testing. The applicant also stated that the fuel pool gate elastomer seals were periodically 

replaced on a 54-month basis; however, a recent change allows inspections to dictate the need 

for replacement but not to exceed a 10-year replacement frequency. The applicant further 

stated that as per LRA Section 2.1.6.4, fire hoses are considered to be a consumable item 

whose replacement frequency is based on NFPA testing standards that are implemented by 

controlled station procedures. 

The staff notes that although the replacement frequency for the fire hoses are based on testing, 

this testing is controlled by plant procedures and it is a well known fact that fire hoses are 

replaced based on this testing or inspection by users. The staff finds the applicant’s response 

acceptable because the in-scope elastomer seals that are subject to wear are appropriately 

evaluated as not being long-lived passive items and thus are screened out from aging 

management. The staff’s concern described in RAI 3.3.2.2.13-01 is resolved. 

Based upon the applicant’s periodic replacement of elastomer components subject to wear, the 

staff finds that an AMR of these components is not required and finds it acceptable for the 

applicant to designate AMR results in Table 3.3.1, item 3.3.1-34 as not applicable. 

3.3.2.2.14 Loss of Material Due to Cladding Breach 

LRA Section 3.3.2.2.14 refers to Table 3.3.1, item 3.3.1-35 and addresses loss of material due 

to cladding breach. The applicant stated that this aging effect is not applicable to HCGS, which 

is a BWR. 

SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach could occur for 

PWR steel charging pump casings with stainless steel cladding exposed to treated borated 

water. SRP-LR Table 3.3-1 identifies item 35 applicable to PWRs. 

The staff verified that SRP-LR Section 3.3.2.2.14 is not applicable to HCGS because HCGS is a 

BWR and the staff guidance in this SRP-LR section is only applicable to PWR steel with 

stainless steel cladding pump casing exposed to treated borated water. 

Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.3.2.2.14 do not apply to HCGS because the guidance is applicable to PWRs. 

3.3.2.2.15 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. 

3.3.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.3.2-1 through 3.3.2-32, 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 3.3.2-1 through 3.3.2-32, the applicant indicated, via Notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to a 

line 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 line 

item component is not evaluated in the GALL Report. Note G indicates that the environment for 
Aging Management Review Results 

 3-355 

the AMR line item component and material is not evaluated in the GALL Report. Note H 

indicates that the aging effect for the AMR line 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 line item component, material, and environment 

combination is not applicable. Note J indicates that neither the component nor the material and 

environment combination for the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant had 

demonstrated that the aging effects will be adequately managed so that the intended function(s) 

will be maintained consistent with the CLB during the period of extended operation. The staff’s 

evaluation is discussed in the following sections. 

3.3.2.3.1 Auxiliary Systems – Chilled Water System – Summary of 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 

chilled water system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.2 Auxiliary Systems – Closed-Cycle Cooling Water System – Summary of 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 

closed-cycle cooling water system component groups. 

In LRA Table 3.3.2-2, the applicant stated that copper alloy heat exchanger components 

exposed to wetted air and gas are being managed for reduction of heat transfer due to fouling 

by the Periodic Inspection Program. The AMR line items cite generic note H, which indicates 

that the aging effect is not addressed in the GALL Report for this component, material, and 

environment combination. 

The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is documented 

in SER Section 3.0.3.3.2. The staff finds the monitoring program acceptable to manage aging 

for these components because it includes periodic visual inspections which can detect reduction 

of heat transfer due to fouling and is a technique that is consistent with the GALL Report for 

managing this aging effect. 

In LRA Table 3.3.2-2, the applicant stated that the copper alloy thermo-siphon heat exchanger 

components exposed to raw water are being managed for reduction of heat transfer due to 

fouling and loss of material due to pitting, crevice, and microbiologically-influenced corrosion by 

the Periodic Inspection Program. The AMR line items cite generic note G, which indicates that 

the environment is not addressed in the GALL Report for this component and material. The 

AMR line items also cite plant-specific note 4, which indicates that the components are exposed 

to a glycol-based coolant used in the compressor cooling system that was considered “raw 
Aging Management Review Results 

 3-356 

water” for the purposes of the AMR review and is not monitored by the water chemistry 

program. 

The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is documented 

in SER Section 3.0.3.3.2. The staff reviewed the GALL Report and noted that item VII.C1-6 

recommends that copper alloy heat exchanger tubes exposed to raw water be managed for 

reduction of heat transfer by GALL AMP XI.M20, “Open-Cycle Cooling Water Program.” By 

letter dated June 3, 2010, the staff issued RAI 3.2.2-02 requesting that the applicant justify the 

effectiveness of the Periodic Inspection Program in managing loss of heat transfer for these 

components. The staff also noted that there was a typographical error in the background of the 

RAI that referred to the Closed-Cycle Cooling Water Program instead of the Open-Cycle 

Cooling Water Program. In its response dated June 30, 2010, the applicant stated that the 

copper alloy heat exchanger is exposed to closed-cycle cooling water on one side that is being 

managed by the Closed-Cycle Cooling Water Program in another AMR line item and exposed to 

a glycol-based coolant on the other side which is being managed by the Periodic Inspection 

Program. The applicant also stated that the Periodic Inspection Program is adequate to 

manage aging for the copper alloy heat exchanger surfaces exposed to the glycol-based 

coolant because the program includes visual inspections of heat transfer surfaces which can 

detect fouling, and any degradation of the surfaces will be entered into the corrective action 

program. The staff finds the applicant’s response to RAI 3.2.2-02 and its proposal to manage 

aging for these components using the Periodic Inspection Program acceptable because the 

applicant’s Periodic Inspection Program includes visual inspections which can detect reduction 

of heat transfer due to fouling and loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion in a glycol-based environment, and the use of visual 

inspections is a technique that is consistent with the GALL Report for managing these aging 

effects. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-2, the applicant stated that aluminum sensor elements internally exposed to 

closed-cycle cooling water are being managed for loss of material due to pitting and crevice 

corrosion by the Closed-Cycle Cooling Water Program. The AMR line item cites generic note G 

for this item indicating that the environment is not addressed in the GALL Report for this 

component and material. 

The staff reviewed the associated line item in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because, as noted in the GALL Report, aluminum is susceptible to loss of material due to pitting 

and crevice corrosion in treated water environments, which include the closed-cycle cooling 

water system. The staff’s evaluation of the applicant’s Closed-Cycle Cooling Water System 

Program is documented in SER Section 3.0.3.2.5 and notes that the program includes corrosion 

inhibitors and water purity to mitigate corrosion. The staff finds the applicant’s proposal to 

manage aging using the Closed-Cycle Cooling Water System Program acceptable because this 

program manages loss of material by controlling closed-cycle cooling water chemistry to 

minimize corrosion by conducting visual and NDEs and by implementing a one-time inspection 

to verify the effectiveness of the program. 
Aging Management Review Results 

 3-357 

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 will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.3 Auxiliary Systems – Compressed Air System – Summary of 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 

compressed air system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.4 Auxiliary Systems – Containment Inerting and Purging System – Summary of 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 

containment inerting and purging system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.5 Auxiliary Systems – Control Area Chilled Water Systems – Summary of 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 

control area chilled water system component groups. 

In LRA Table 3.3.2-5, the applicant stated that for glass exposed to closed-cycle cooling water, 

there is no aging effect and no AMP is proposed. The AMR line items cite generic note G, 

indicating that this environment is not in the GALL Report for this component and material. 

The staff finds the applicant’s proposal acceptable because there are no known aging effects for 

glass exposed to any water environment of nuclear power plants, and this approach is 

consistent with the GALL Report which states that there are no AERMs for glass exposed to 

treated, raw, and treated borated water (GALL AMR items VII.J-11, VII J-12, and VII J-13, 

respectively). 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging for these 
Aging Management Review Results 

 3-358 

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 Table 3.3.2-5, the applicant stated that copper alloy heat exchanger components 

exposed to wetted air and gas are being managed for reduction of heat transfer due to fouling 

by the Periodic Inspection Program. The AMR line items cite generic note G, which indicates 

that the environment is not addressed in the GALL Report for this component and material. 

The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is documented 

in SER Section 3.0.3.3.2. The staff finds the monitoring program acceptable to manage aging 

for these components because it includes visual inspections which can detect reduction of heat 

transfer due to fouling and is a technique that is consistent with the GALL Report for managing 

the aging effect. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.6 Auxiliary Systems – Control Rod Drive System – Summary of 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 

CRD system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.7 Auxiliary Systems – Control Room and Control Area Heating, Ventilation, and Air 

Conditioning Systems – Summary of 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 

control room and control area HVAC system component groups. 

In LRA Table 3.3.2-7, the applicant stated that polymer ducting and components exposed to air–

indoor (external), or air or gas–wetted (internal) have no AERM and that for this component, 

material, and environment combination, no AMP is needed. The AMR line items cite generic 

note F, indicating that the material is not in the GALL Report for this component. The staff 

reviewed all material entries in the GALL Report and confirmed that polymer material is not 

included in the GALL Report. 
Aging Management Review Results 

 3-359 

For these AMR results, the applicant also cited plant-specific note 3, stating that: 

The polymer (plexiglass) material located indoors and subject to an air-indoor or 

air-gas (wetted) environment is not subject to significant aging effects. Polymer 

materials do not experience aging effects unless exposed to temperatures, 

radiation or chemicals capable of attacking the specific polymer chemical 

composition. Polymer materials are selected for compatibility with the 

environment during the design, and if properly selected will not experience 

significant degradation. Polymer (plexiglass) material in this non-aggressive air 

environment is not expected to experience significant aging effects. This is 

consistent with plant operating experience. 

Based on its review of technical literature (e.g., Roff, W.J., Fibres, Plastics, and Rubbers: A 

Handbook of Common Polymers, Academic Press Inc., New York, 1956) and current industry 

research and operating experience related to plexiglass and related polymers, the staff has 

determined that, in the absence of specific environmental stressors such as ultraviolet light, high 

radiation, or ozone concentrations, components made of these materials do not exhibit aging 

effects of concern during the period of extended operation. The staff has determined that for 

plexiglass and related polymer components in a plant indoor air, or air or gas – wetted 

environment, there are no aging effects that cause degradation of the components during the 

period of extended operation. On the basis that the subject components have no aging effects 

that cause degradation during the period of extended operation, the staff finds the applicant’s 

AMR results for these components, indicating that there is no AERM and no AMP is needed, to 

be acceptable. 

3.3.2.3.8 Auxiliary Systems – Cranes and Hoists – Summary of Aging Management 

Evaluation – LRA Table 3.3.2-8 

In LRA Table 3.3.2-8, the applicant stated that carbon steel cranes or hoists exposed to outdoor 

air are being managed for cumulative fatigue damage using a TLAA. The AMR line item cites 

generic note G, indicating that the environment is not in the GALL Report for this component 

and material. 

The staff evaluated the applicant’s claim that the cumulative fatigue damage of the carbon steel 

crane would be adequately managed by the TLAA. The TLAA, which is evaluated in SER 

Section 4.7, includes the review of existing 40-year design bases to determine the number of 

load cycles considered in the design for each of the cranes within the scope of license renewal 

and then the development of a 60-year projection for load cycles for each crane. The staff finds 

that the applicant’s management of the carbon steel crane and hoist exposed to outdoor air 

acceptable because the process followed for fatigue damage is consistent with the 

recommendation in the GALL Report for other similar environments. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-8, the applicant stated that carbon steel cranes or hoists (rail system) 

exposed to external outdoor air are being managed for loss of material due to wear by the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 
Aging Management Review Results 

 3-360 

Program. The AMR line items cite generic note G, which indicates that the environment is not 

addressed in the GALL Report for this component and material. 

The staff reviewed the applicant’s Inspection of Overhead Heavy Load and Light Load (Related 

to Refueling) Handling Systems Program and its evaluation is documented in SER 

Section 3.0.3.2.6. The staff finds the monitoring program acceptable to manage aging for these 

components because it includes visual inspections of rails in the rail system which are 

appropriate to detect loss of material due to wear. Also, the AMP is implemented through 

station procedures that are based on ASME/ANSI B30.2, B30.10, B30.11, and B30.16 and rely 

upon visual inspection to manage loss of material in an indoor air and outdoor air environment. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.9 Auxiliary Systems – Equipment and Floor Drainage System – Summary of 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 

equipment and floor drainage system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.10 Auxiliary Systems – Fire Protection System – Summary of Aging Management 

Evaluation – LRA Table 3.3.2-10 

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMRs for the fire 

protection system component groups. 

In LRA Table 3.3.2-10, the applicant stated that copper alloy piping, fittings, valves, and hose 

components exposed externally to outdoor air are being managed for loss of material due to 

pitting and crevice corrosion by the Fire Protection Program. The AMR line items cite generic 

note G, which indicates that the environment is not addressed in the GALL Report for this 

component and material. 

The staff reviewed the applicant’s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.7. The staff finds the monitoring program acceptable to manage aging for 

these components because it includes visual inspections of component external surfaces and 

functional testing which are appropriate to detect loss of material for these components. 

In its RAI response to RAI 2.3.3.10-2 dated April 6, 2010, the applicant stated that it discovered 

that the flexible metal hose components were inadvertently identified with an outdoor air 

environment but the hoses are located indoors. The applicant revised Table 3.3.2-10 

component type hoses to refer the AMR line item with Table 3.2.1, item 3.2.1-53 and cite 
Aging Management Review Results 

 3-361 

generic note A, which indicates that the component, material, environment, and aging effect is 

consistent with the GALL Report. 

The staff notes that the applicant, during its review of RAI 2.3.3.10-2, identified the following 

error in its LRA: Table 3.3.2-10 showed the environment for flexible metal hoses as “Air – 

Outdoor” and as a result, these hoses were within the scope of license renewal and subject to 

an AMR. The applicant revised Table 3.3.2-10 to show the environment for these hoses as 

“Air–Indoor” and, therefore, these hoses are consistent with the GALL Report for this AMR line 

item. The staff concurs with this correction. 

In its response to RAI 2.3.3.10-2 dated April 6, 2010, the applicant stated that fire retardant 

coatings for structural steel are within the scope of license renewal and subject to an AMR. The 

applicant revised Tables 2.3.3-10 and 3.3.2-10 to add fire retardant coatings for structural steel 

as a fire barrier that is within the scope of license renewal and subject to an AMR and added 

Note 19 to Table 3.3.2-10. Note 19 states, “based on industry standards and guidelines, 

cementitious fireproofing is susceptible to loss of material due to cracking in this environment. 

This aging effect will be monitored and managed with the fire protection program.” This note 

justifies the inclusion of fire retardant coating for structural steel in the Fire Protection Program. 

The AMR line items cite generic note F, which indicates that the material is not addressed in the 

GALL Report for this component. 

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.7. The staff noted that the applicant’s Fire Protection Program includes visual 

inspections of fire barriers at least once every 18 months for detection of cracking and loss of 

material and that these inspections are appropriate to detect cracking and loss of material for 

cementitious fire proofing. The staff finds the applicant’s currently proposed programs 

acceptable to manage cracking and loss of material for cementitious fire proofing fire barriers 

because the periodic visual inspections performed by the Fire Protection Program will confirm 

that there is no loss of material or cracking, or it will result in a corrective action to assess the 

situation. 

In its response to RAI 2.3.3.10-4 dated April 6, 2010, the applicant stated that the steel wall 

panels and windows are within the scope of license renewal and are subject to an AMR. A 

review of LRA Table 3.3.2-10 determined that the steel fire barrier materials were inadvertently 

omitted from this table. Table 3.3.2-10 was revised to add these materials to the existing fire 

barrier (walls, ceilings, and floors) component types which are exposed to an indoor air 

environment and are being managed for loss of material due to corrosion by the Fire Protection 

Program. The AMR line items cite generic note F, which indicates that the material is not 

addressed in the GALL Report for this component. 

The staff reviewed the applicant’s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.7. The staff noted that the applicant’s Fire Protection Program includes 

visual inspections of fire barriers at least once every 18 months for detection of loss of material 

and that these inspections are appropriate to detect loss of material for carbon steel. The staff 

finds the applicant’s currently proposed programs acceptable to manage loss of material for 

carbon steel fire barriers because the periodic visual inspections performed by the Fire 

Protection Program will confirm that there is no loss of material, or it will result in a corrective 

action to assess the situation. 

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 
Aging Management Review Results 

 3-362 

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). 

In LRA Table 3.3.2-10, the applicant stated that copper alloy sprinkler heads and valve body 

components exposed externally to outdoor air are being managed for loss of material due to 

pitting and crevice corrosion by the Fire Water System Program. The AMR line items cite 

generic note G, which indicates that the environment is not addressed in the GALL Report for 

this component and material. 

The staff reviewed the applicant’s Fire Water System Program and its evaluation is documented 

in SER Section 3.0.3.2.8. The staff finds the monitoring program acceptable to manage aging 

for these components because it includes visual inspections of fire protection system 

components (including sprinkler head inspections per NFPA-25), volumetric testing, and 

performance testing (e.g., system functional tests, flow tests, and flushes) which can detect loss 

of material. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Tables 3.3.2-10 and 3.3.2-27, the applicant stated that carbon or low alloy steel bolting 

externally exposed to soil is being managed for loss of material due to general, pitting, crevice, 

and microbiologically-influenced corrosion and loss of preload due to thermal effects, gasket 

creep, and self-loosening by the Bolting Integrity Program. The AMR line items cite generic 

note G, indicating that the environment is not in the GALL Report for this component and 

material. The applicant also stated that it plans to conduct external inspections in accordance 

with the frequency outlined in the Buried Piping Inspection Program or the Buried Non-Steel 

Piping Inspection Program. 

The staff’s evaluation of the Bolting Integrity and Buried Piping Inspection Programs are 

documented in SER Sections 3.0.3.2.4 and 3.0.3.2.12, respectively. The staff noted that the 

Bolting Integrity Program manages loss of material by performing visual inspections for bolted 

joint leakage. The staff also noted that the frequency established for the inspections performed 

by the Buried Piping Inspection and Buried Non-Steel Piping Inspection Programs are based on 

preventive measures, including application of external coatings and wrappings. It was unclear 

to the staff if external coatings and wrappings are used on the carbon and low alloy steel bolting 

listed in LRA Tables 3.3.2-10 and 3.3.2-27. By letter dated June 1, 2010, the staff issued 

RAI 3.3.2.3.10-01 requesting that the applicant provide additional information regarding whether 

the carbon and low alloy steel bolting exposed to soil is wrapped or coated, and if the 

components are not wrapped or coated, provide additional information regarding why the 

frequency adopted from the Buried Piping Inspection Program or the Buried Non-Steel Piping 

Inspection Program is applicable. 

In its response dated June 24, 2010, the applicant stated that station documentation and site 

interviews indicate that buried bolting was initially coated, but that buried carbon steel bolts in 

the fire protection system have been observed without coatings and that it does not take credit 

for coatings to prevent loss of intended function. The applicant also stated that buried bolting in 
Aging Management Review Results 

 3-363 

the service water system is designated as Class 3 and is inspected in accordance with ASME 

Code Section XI IWD-2500 and IWD-5000, 1998 Edition with 2000 Addenda, which allows use 

of a flow test to confirm no significant leakage in lieu of visual inspections. The applicant further 

stated that non-ASME buried bolts will be opportunistically inspected in accordance with the 

Buried Piping Inspection Program. The staff notes that ASME Code Section IX, Subsection 

IWA-5244, “Buried Components,” indicates that for buried components where a VT-2 visual 

examination cannot be performed, the examination requirement is satisfied by conducting a 

pressure loss test or a flow test. The staff finds the applicant’s response to RAI 3.3.2.3.10-01 

and its proposal to manage aging for bolting exposed to soil using the Bolting Integrity and 

Buried Piping Inspection Programs acceptable because the buried bolts will be inspected using 

either system flow tests or opportunistic inspections, which is consistent with the GALL Report 

recommendations that periodic inspections be conducted. The staff’s concern described in 

RAI 3.3.2.3.10-01 is resolved. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Tables 3.3.2-10 and 3.4.2-1, the applicant stated that stainless steel piping and fittings 

exposed externally to soil are being managed for loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion by the Buried Non-Steel Piping Inspection Program. The 

AMR line items cite generic note H, which indicates that the aging effect is not addressed in the 

GALL Report for this component, material, and environment combination. 

The staff reviewed the applicant’s Buried Non-Steel Piping Inspection Program and its 

evaluation is documented in SER Section 3.0.3.3.4. The staff finds the applicant’s proposed 

program acceptable to manage aging for these components because it uses opportunistic and 

focused visual inspections of coatings and the base metal to detect loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3) 

In LRA Table 3.3.2-10, the applicant stated that grout fire barriers (penetration seals) exposed 

to indoor and outdoor air have an aging effect of cracking due to shrinkage, and in an outdoor 

air environment, have an aging effect of loss of material due to spalling and scaling and 

cracking due to freeze-thaw. The applicant also stated that these aging effects will be managed 

by both the Fire Protection and Structures Monitoring Programs. The AMR line items cite 

generic note F, indicating that the material is not addressed in the GALL Report for this 

component. The AMR line items also cite plant-specific note 8, indicating that grout is 

susceptible to cracking due to shrinkage in this environment, based on industry standards and 

guidelines. The AMR line items further cite plant-specific note 9, indicating that grout is 

susceptible to loss of material due to spalling and scaling and cracking due to freeze-thaw in an 

air – outdoor environment. The staff reviewed the associated line items in the LRA and 

confirmed that the applicant has identified the correct aging effects for this component, material, 
Aging Management Review Results 

 3-364 

and environment combination because grout is similar to concrete, which experiences these 

same aging effects. 

The staff’s evaluation of the applicant’s Fire Protection and Structures Monitoring Programs is 

documented in SER Sections 3.0.3.2.7 and 3.0.3.2.16, respectively. The staff noted that the 

Fire Protection Program is used for other fire barriers, such as penetration seals, walls, floors, 

and ceilings, and that the grout material in this case is used as a penetration seal fire barrier. 

The staff also noted that the applicant’s Fire Protection Program includes visual inspections of 

fire barriers at least once every 18 months for detection of cracking and loss of material and that 

these inspections are appropriate to detect cracking and loss of material for grout. The staff 

further noted that the applicant’s Structures Monitoring Program also includes periodic visual 

inspections of structural concrete for cracking and loss of material at a frequency not to exceed 

5 years and that these inspections are also appropriate for detecting aging of grout. The staff 

finds the applicant’s currently proposed programs acceptable to manage cracking and loss of 

material for grout fire barriers because the periodic visual inspections performed by the Fire 

Protection and the Structures Monitoring Programs will confirm that there is no loss of material 

or cracking, or it will result in a corrective action to assess the situation. 

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). 

In LRA Table 3.3.2-10, the applicant stated that alumina silicate fire barriers (wraps) exposed to 

indoor air are being managed for change in material properties and cracking by the Fire 

Protection Program. The AMR line items cite generic note F, indicating that the material is not 

addressed in the GALL Report for this component. The AMR line items also cite plant-specific 

note 11, indicating that the Fire Protection Program will be used to manage these aging effects. 

The staff reviewed the associated line items in the LRA and noted that the LRA did not include a 

description of the change in material properties that will be managed by the program or the 

parameters that will be observed during the visual inspections of the aluminum silicate fire 

barriers (wraps). It is not clear to the staff how the visual examination would detect change in 

material properties of the aluminum silicate fire wrap. 

By letter dated June 22, 2010, the staff issued RAI 3.3.2.3.10-02 requesting that the applicant 

describe the material properties of the aluminum silicate fire barrier wraps that will be managed 

by the Fire Protection Program, the parameters that will be observed during the visual 

inspection of the aluminum silicate fire barrier wraps, and the acceptance criteria used to 

evaluate the change in material properties. The staff also requested that the applicant justify 

how the visual inspections used by the Fire Protection Program will manage the aging effect of 

change in material properties. 

In its response dated July 19, 2010, the applicant stated that change in material properties for 

fire barrier wraps include degradation due to physical damage that may occur during plant 

activities and could challenge the design thickness of the fire wrap. The applicant also stated 

that the inspection parameters include physical damage, gaps in the outer layer of the mat, hole 

in the foil, loose bands, sagging, or falling mesh wire cloth. The applicant further stated that the 

fire wrap is considered acceptable if its observed condition is the same as its designed 
Aging Management Review Results 

 3-365 

condition. The staff finds the applicant’s response to RAI 3.3.2.3.10-02 acceptable because the 

inspection parameters and acceptance criteria for fire barrier wraps are consistent with industry 

guidance. 

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.7. The staff noted that NUREG-1924, “Electrical Raceway Fire Barrier Systems 

in US Plants” (May 2010), states that aluminum silicate is commonly used as a fire resistant 

fiber in flexible fire barrier blankets and wraps. The staff also noted that the applicant’s Fire 

Protection Program includes visual inspections of fire barriers once every 18 months to detect 

cracking and loss of material and that these inspections are appropriate to detect aging for fire 

barrier blankets and wraps. The staff finds the Fire Protection Program acceptable to manage 

aging for these fire barriers because the visual inspections are capable of detecting cracking 

and change in material properties prior to loss of intended function. 

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). 

In LRA Table 3.3.2-10, the applicant stated that polymer hoses exposed externally to indoor air 

and internally to wetted air or gas have no AERMs. The AMR line items cite generic note F, 

indicating that the material is not addressed in the GALL Report for this component. The AMR 

line items also cite plant-specific note 18, which states: 

The polymer (plexiglass) material located indoors and subject to an indoor air or 

air-gas (wetted) environment is not subject to significant aging effects. Polymer 

materials do not experience aging effects unless exposed to temperatures, 

radiation or chemicals capable of attacking the specific polymer chemical 

composition. Polymer materials are selected for compatibility with the 

environment during the design, and if properly selected will not experience 

significant degradation. Polymer (teflon) material in this non-aggressive air 

environment is not expected to experience significant aging effects. This is 

consistent with plant operating experience. 

Based on industry experience, the staff noted that Teflon is susceptible to radiation, which could 

cause an aging effect of change in material properties. It is not clear to the staff where the 

polymer hoses listed in LRA Table 3.3.2-10 are located such that the environment is considered 

non-aggressive. 

By letter dated June 22, 2010, the staff issued RAI 3.3.2.3.10-03 requesting that the applicant 

explain the bounding environmental conditions used to determine that the environment is 

non-aggressive and the selection criteria used for the polymer hoses within the scope of license 

renewal. 

In its response dated July 19, 2010, the applicant stated that the polymer hoses exposed to 

indoor air or wetted air or gas in Table 3.3.2-10 includes two Teflon hoses with quick 

disconnects that connect the halon cylinders to the control room operator’s console and are 

normally disconnected and stored on a hose rack in the main control room. The applicant also 

stated that the internal environment the hoses are exposed to is halon gas but was classified as 

wetted air or gas to account for moisture infiltration. The Teflon hoses were chosen because 
Aging Management Review Results 

 3-366 

they are chemically resistant to common solvents, acids, and bases; are chemically inert; and 

are rated for temperatures up to 500 °F. The applicant further stated that the environment in the 

main control room is non-aggressive because it is climate controlled and a low radiation area. 

The staff finds the applicant’s response to RAI 3.3.2.3.10-03 acceptable because the hose 

material selected is appropriate for use in the halon system, the main control room environment 

is non-aggressive, and Teflon hoses in this non-aggressive environment would not be expected 

to experience AERMs. 

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). 

3.3.2.3.11 Auxiliary Systems – Fire Pump House Ventilation System – Summary of 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 fire pump house ventilation system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.12 Auxiliary Systems – Fresh Water Supply System – Summary of 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 fresh water supply system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.13 Auxiliary Systems – Fuel Handling and Storage System – Summary of 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 fuel handling and storage system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 
Aging Management Review Results 

 3-367 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.14 Auxiliary Systems – Fuel Pool Cooling and Cleanup System – Summary of Aging 

Management Evaluation – LRA Table 3.3.2-14 

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMRs for the fuel pool 

cooling and cleanup system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.15 Auxiliary Systems – Hardened Torus Vent System – Summary of 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 hardened torus vent system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.16 Auxiliary Systems – Hydrogen Water Chemistry System – Summary of 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 hydrogen water chemistry system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.17 Auxiliary Systems – Leak Detection and Radiation Monitoring System – Summary of 

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 leak detection and radiation monitoring system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 
Aging Management Review Results 

 3-368 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.18 Auxiliary Systems – Makeup Demineralizer System – Summary of Aging 

Management Evaluation – LRA Table 3.3.2-18 

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMRs for the makeup 

demineralizer system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.19 Auxiliary Systems – Primary Containment Instrument Gas System – Summary of 

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 primary containment instrument gas system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.20 Auxiliary Systems – Primary Containment Leakage Rate Testing System – Summary 

of 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 primary containment leakage rate testing system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.21 Auxiliary Systems – Process and Post-Accident Sampling Systems – Summary of 

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 process and post-accident sampling systems component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 
Aging Management Review Results 

 3-369 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.22 Auxiliary Systems – Radwaste System – Summary of 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 radwaste system component groups.

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.23 Auxiliary Systems – Reactor Building Ventilation System – Summary of 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 reactor building ventilation system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.24 Auxiliary Systems – Reactor Water Cleanup System – Summary of 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 RWCU system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.25 Auxiliary Systems – Remote Shutdown Panel Room Heating, Ventilation, and Air 

Conditioning System – Summary of 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 remote shutdown panel room HVAC system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 
Aging Management Review Results 

 3-370 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.26 Auxiliary Systems – Service Water Intake Ventilation System – Summary of 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 service water intake ventilation system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.27 Auxiliary Systems – Service Water System – Summary of Aging Management 

Evaluation – LRA Table 3.3.2-27 

In LRA Table 3.3.2-27, the applicant stated that the nickel-alloy bolting in the air – indoor 

(external) environment is being managed for loss of preload due to thermal effects, gasket 

creep, and self-loosening by the Bolting Integrity Program. The AMR line item cites generic 

note G, indicating that this environment is not in the GALL Report for this component and 

material. In LRA Table 3.3.2-27, the applicant stated that the nickel alloy (tube side 

components) in the raw water (internal) environment is being managed for loss of material due 

to pitting, crevice, and microbiologically-influenced corrosion and fouling by the Open-Cycle 

Cooling Water System Program. The AMR line items cite generic note H, indicating that this 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff reviewed the associated line item and the Bolting Integrity Program in the LRA and 

confirmed that the applicant had identified the correct aging effects for this component, material, 

and environment combination because loss of preload may occur for bolting exposed to indoor 

air regardless of the fabrication material. 

The staff noted that even though the loss of preload for nickel-alloy bolting exposed to air – 

indoor (external) is not specifically addressed in the GALL Report, proper maintenance 

practices require an appropriate preload to exist. Table IX.E of the GALL Report describes “loss 

of preload” as occurring due to gasket creep, thermal effects (including differential expansion 

and creep or stress relaxation), and self-loosening (which includes vibration, joint flexing, cyclic 

shear loads, and thermal cycles). The staff noted that the environment of air – indoor (external) 

could involve differential thermal expansion issues with dissimilar materials that are often found 

in the bolted joint configuration; therefore, the aging effect of concern is loss of preload. 

The staff noted that the evidence for loss of preload of the nickel-alloy bolting in air – indoor 

(external) is similar to that described for steel bolting in GALL AMR item VII.I-5 where loss of 

preload in steel bolting for the auxiliary systems is managed by GALL AMP XI.M18, “Bolting 

Integrity.” The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in 

SER Section 3.0.3.2.4. The staff noted that the Bolting Integrity Program provides for condition 

monitoring of pressure retaining bolting by performing visual inspections which are capable of 

detecting gross loosening of the bolts or leakage that is indicative of loss of preload. The staff 
Aging Management Review Results 

 3-371 

also noted that the program includes procurement controls and installation practices defined in 

plant procedures to ensure that only approved lubricants, sealants, and proper torques are 

applied to bolting which are capable of preventing loss of preload. The staff finds the applicant’s 

proposal to manage aging using the Bolting Integrity Program acceptable because it includes 

plant procedures that ensure proper torques are applied to bolting and visual inspections are 

performed to ensure that leakage and gross loosening of bolts do not occur. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-27, the applicant stated that the nickel alloy (tube side components) in the 

raw water (internal) environment is being managed for loss of material due to pitting, crevice, 

and microbiologically-influenced corrosion and fouling by the Open-Cycle Cooling Water System 

Program. The AMR line items cite generic note H, indicating that this aging effect is not in the 

GALL Report for this component, material, and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environmental combination 

because loss of material due to pitting, crevice, and microbiologically-influenced corrosion and 

fouling may occur for any corrosion resistant alloy that is exposed to raw water (water 

containing contamination like bacterial microbes). 

The staff noted that even though loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion and fouling for nickel alloy (tube side components) 

exposed to raw water (internal) is not specifically addressed in the GALL Report, proper 

maintenance practices require the plant to manage the internal corrosion of heat exchanger 

components to minimize susceptibility of corrosion and to verify that corrosion has not exceeded 

acceptable limits. The staff noted that as described in the Metals Handbook Volume 13, 9th

Edition, by the American Society for Metals, nickel is a corrosion resistant material and 

nickel-alloy heat exchanger components used in heat exchanger tubes internally exposed to 

raw water may experience loss of material. 

The staff further noted that evidence of loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion and fouling of the nickel-alloy (tube side) components in 

raw water (internal) is similar to that described for copper alloy in GALL AMR item VII.C1-9 

where loss of material due to pitting, crevice, and microbiologically-influenced corrosion and 

fouling in copper alloy for the open-cycle cooling water system (service water system) is 

managed by the Open-Cycle Cooling Water System Program, consistent with the 

recommendations of the GALL Report. 

The staff’s review of the Open-Cycle Cooling Water System Program is documented in SER 

Section 3.0.3.1.9. The staff noted that the applicant’s program provides instructions and 

controls for mitigating degradation through raw water chemistry control (sodium hypochlorite 

injection), performance-monitoring through station testing, and condition monitoring through 

inspection and testing of the service water system. The staff noted that the methods described 

in the program and the frequencies for inspections under the existing program have been 

effective in detecting the applicable aging effects and preventing significant degradation. The 

staff finds the applicant’s proposal to manage aging using the Open-Cycle Cooling Water 
Aging Management Review Results 

 3-372 

System Program acceptable because it includes raw water chemistry control (sodium 

hypochlorite injection) to mitigate corrosion and also includes performance-monitoring through 

station testing and condition monitoring through inspection and testing which are capable of 

determining if loss of material has occurred. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-27, the applicant stated that the carbon or low alloy steel with nickel-alloy 

cladding (tube side components) in the raw water (internal) environment is being managed for 

loss of material due to pitting, crevice, galvanic, and microbiologically-influenced corrosion and 

fouling by the Open-Cycle Cooling Water System Program. The AMR line items cite generic 

note H, indicating that this aging effect is not in the GALL Report for this component, material, 

and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because loss of material due to pitting, crevice, galvanic, and microbiologically-influenced 

corrosion and fouling may occur for any corrosion resistant alloy that is exposed to raw water 

(water containing contamination like bacterial microbes). 

The staff noted that even though loss of material due to pitting, crevice, galvanic, and 

microbiologically-influenced corrosion and fouling for carbon or low alloy steel with nickel-alloy 

cladding (tube side components) exposed to raw water (internal) is not specifically addressed in 

the GALL Report, proper maintenance practices require the plant to manage the internal 

corrosion of heat exchanger components to minimize susceptibility of corrosion and to verify 

that corrosion has not exceeded acceptable limits. The staff noted that as described in the 

Metals Handbook Volume 13, 9th Edition, by the American Society for Metals, nickel is a 

corrosion resistant material and nickel-clad heat exchanger components used in heat exchanger 

tubes internally exposed to raw water may experience loss of material. 

The staff further noted that evidence of loss of material due to pitting, crevice, galvanic, and 

microbiologically-influenced corrosion and fouling of the carbon or low alloy steel with 

nickel-alloy cladding (tube side components) in raw water (internal) is similar to that described 

for copper alloy in GALL AMR item VII.C1-3 where loss of material due to pitting, crevice, 

galvanic, and microbiologically-influenced corrosion and fouling in copper alloy for the 

open-cycle cooling water system (service water system) is managed by the Open-Cycle Cooling 

Water System Program, consistent with the recommendations of the GALL Report. 

The staff’s review of the Open-Cycle Cooling Water System Program is documented in SER 

Section 3.0.3.1.9. The staff noted that the applicant’s program provides instructions and 

controls for mitigating degradation through raw water chemistry control (sodium hypochlorite 

injection), performance-monitoring through station testing, and condition monitoring through 

inspection and testing of the service water system. The staff noted that the methods described 

in the program and the frequencies for inspections under the existing program have been 

effective in detecting the applicable aging effects and preventing significant degradation. The 

staff finds the applicant’s proposal to manage aging using the Open-Cycle Cooling Water 

System Program acceptable because it includes raw water chemistry control (sodium 
Aging Management Review Results 

 3-373 

hypochlorite injection) to mitigate corrosion and also includes performance-monitoring through 

station testing and condition monitoring through inspection and testing which are capable of 

determining if loss of material has occurred. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-27, the applicant stated that aluminum bronze bolting (with 8 percent 

aluminum or more) exposed to indoor air, outdoor air, and raw water are being managed for 

loss of preload due to thermal effects, gasket creep, and self-loosening and loss of material due 

to pitting, crevice, and microbiologically-influenced corrosion by the Bolting Integrity Program. 

The AMR line items cite generic note F, indicating that the material is not addressed in the 

GALL Report for this component. In addition, line items associated with mechanical closure 

bolting exposed to raw water cite plant-specific note 1, which states that inspection activities for 

bolting in a submerged environment are performed in conjunction with associated component 

maintenance activities. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because, as noted in the GALL Report, copper alloys including aluminum bronze are 

susceptible to loss of material due to pitting and crevice corrosion. The staff’s evaluation of the 

applicant’s Bolting Integrity Program is documented in SER Section 3.0.3.2.4. The staff notes 

that the applicant’s program incorporates NRC and industry recommendations and performs 

examinations in accordance with the ASME Code Section XI ISI program plan as part of a 

corporate component pressure retaining bolting program. The staff also notes that the 

inspection of submerged components by the Bolting Integrity Program has been addressed in 

RAI B.2.1.12-02 in SER Section 3.0.3.2.4. The staff finds the applicant’s proposal to manage 

aging using the Bolting Integrity Program acceptable because the program manages cracking, 

loss of material, and loss of preload by performing visual inspections for pressure retaining 

bolted joint leakage in indoor and outdoor air and in raw and treated water. 

In LRA Table 3.3.2-27, the applicant stated that aluminum bronze bolting, pump casings, and 

valve bodies (with 8 percent aluminum or more) exposed to raw water are being managed for 

loss of material due to selective leaching by the Selective Leaching of Materials Program. The 

AMR line items cited generic note F for the bolting, indicating that the material is not addressed 

in the GALL Report for this component, and generic note H for the pump casings and valve 

bodies, indicating that the aging effect is not addressed in the GALL Report for this component, 

material, and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because, as noted in the LRA, industry operating experience has identified that aluminum 

bronze is susceptible to selective leaching and HCGS has identified de-alloying of aluminum 

bronze valves in raw water environments. The staff’s evaluation of the applicant’s Selective 

Leaching of Materials Program is documented in SER Section 3.0.3.1.12. The staff finds the 

applicant’s proposal to manage aging using the Selective Leaching of Materials Program 

acceptable because it uses visual inspections, which have already identified this aging effect at 

HCGS, and hardness testing. 
Aging Management Review Results 

 3-374 

In LRA Table 3.3.2-27, the applicant stated that aluminum bronze pump casings (with 8 percent 

aluminum or more) exposed to outdoor air (external) are being managed for loss of material due 

to pitting, crevice, and microbiologically-influenced corrosion by the Open-Cycle Cooling Water 

Program. The AMR line items cite generic note G, indicating that the environment is not in the 

GALL Report for this component and material. 

The staff reviewed the associated line item in the LRA and questioned the use of the 

Open-Cycle Cooling Water Program for managing the loss of material for the external surface of 

the aluminum pump casing because the LRA describes the program as managing internal 

corrosion. By letter dated June 3, 2010, the staff issued RAI 3.2.2-1 requesting that the 

applicant justify the appropriateness for using the Open-Cycle Cooling Water Program to 

manage the aging concerns of the external pump casing exposed to outdoor air. 

In its response dated June 30, 2010, the applicant stated that the areas of the aluminum bronze 

pump casings that are exposed to the outdoor air environment are inaccessible during normal 

operation and cannot be observed during regular system walkdowns because they are below 

the floor level in the service water intake structure and subject to river water tidal variations. 

The applicant further stated that the Open-Cycle Cooling Water System Program includes 

periodic maintenance activities, as part of the GL 89-13 program, for managing loss of material, 

including removal and refurbishment of these pumps every 10 years. This activity includes a 

visual inspection of the external surfaces of the pump casing. The applicant also stated that the 

Open-Cycle Cooling Water Program includes condition monitoring activities that are able to 

detect the loss of material, and any corrosion, in excess of minor surface corrosion, will be 

entered into the corrective action program and evaluated further by engineering staff members. 

The staff finds the applicant’s response to the RAI and its proposal to manage aging using the 

above program acceptable because the Open-Cycle Cooling Water Program has specific 

preventive maintenance activities for the pump casing, which uses periodic visual inspections 

capable of identifying the loss of material for aluminum bronze components. The staff’s concern 

described in RAI 3.2.2-1 is resolved. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-27, the applicant indicated that the reduction of heat transfer due to fouling 

for titanium heat exchanger components exposed to closed-cycle cooling water (external) is not 

addressed by the GALL Report. The applicant referenced note F for this item indicating that the 

material is not in the GALL Report for this component. The applicant further indicated that the 

aging issue is managed by the Closed-Cycle Cooling Water System Program. 

The staff confirmed that the GALL Report does not include an AERM or AMP for titanium alloy 

heat exchanger components exposed to a closed-cycle cooling water environment. 

The staff further reviewed the applicant’s Closed-Cycle Cooling Water System Program 

evaluated in SER Section 3.0.3.2.5. The staff finds the monitoring program acceptable because 

it includes performance monitoring, visual inspections, and NDEs to determine component 

functionality for reduction of heat transfer due to fouling. The performance monitoring, visual 
Aging Management Review Results 

 3-375 

inspections, and NDEs are consistent with the GALL Report and thus the monitoring program 

will adequately manage the aging effect. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-27, the applicant indicated that the reduction of heat transfer due to fouling 

and loss of material due to fouling for titanium heat exchanger components exposed to raw 

water (internal) is not addressed by the GALL Report. The applicant referenced note F for this 

item, indicating that the material is not in the GALL Report for this component. The applicant 

further indicated that the aging issue is managed by the Open-Cycle Cooling Water System 

Program. 

The staff confirmed that the GALL Report does not include an AERM or AMP for titanium alloy 

heat exchanger components exposed to raw water (internal) environments. 

The staff further reviewed the applicant’s Open-Cycle Cooling Water System Program evaluated 

in SER Section 3.0.3.1.9. The staff finds that the monitoring program is acceptable because it 

includes system testing, periodic inspections, and NDEs to determine component function due 

to reduction of heat transfer due to fouling. The program includes surveillance and control 

techniques to manage the aging effect. The system testing, visual inspections, and NDEs are 

consistent with the GALL Report and thus the monitoring program adequately manages the 

aging effect. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-27, the applicant indicated that the titanium heat exchanger components 

exposed to closed-cycle cooling water (external) is not addressed by the GALL Report. The 

applicant referenced note F for this item indicating that the material is not in the GALL Report for 

this component. The applicant further indicated that no AMP is needed for this component, 

material, and environment combination when the intended function is a pressure boundary. In 

plant-specific note 10, the applicant stated that titanium material is corrosion resistant in water 

up to 260 °C (500 °F) due to a protective oxide film. The applicant indicated that this was 

consistent with plant operating experience. 

The staff confirmed that the GALL Report does not include an AERM or AMP for titanium alloy 

heat exchanger components exposed to closed-cycle cooling water (external) environments. 

The staff notes that based on multiple references (e.g., AZo Journal of Materials Online 

(http://www.azom.com), Britannica Encyclopedia, Key to Metals Database (online) Article 24), 

titanium is resistant to pitting, general, and crevice corrosion and SCC in salt water and turbine 

exhaust steam environments in essence due to its formation of very stable, continuous, highly 

adherent, and protective oxide films on metal surfaces. Based on these references, the staff 

also notes that due to its corrosion resistance capabilities, it is widely used in the refinery 
Aging Management Review Results 

 3-376 

industry for condenser tubing and the aerospace industry in temperature applications up to 

600 °C. The staff finds the applicant’s proposal that there are no AERMs or AMPs for titanium 

alloy heat exchanger components exposed to closed-cycle cooling water (external) environment 

whose intended function is a pressure boundary acceptable. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.3.2-27, the applicant stated that carbon or low alloy steel with nickel-alloy 

cladding strainer bodies exposed internally to raw water are being managed for loss of material 

due to pitting, crevice, and microbiologically-influenced corrosion and fouling by the Open-Cycle 

Cooling Water System Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the applicant’s Open-Cycle Cooling Water System Program is 

documented in SER Section 3.0.3.1.9. The staff noted that the applicant’s Open-Cycle Cooling 

Water System Program manages loss of material and fouling by controlling raw water 

chemistry, system and component performance testing, and either visual inspections or NDEs. 

The staff finds the applicant’s proposed program to manage carbon or low alloy steel with 

nickel-alloy cladding strainer bodies for loss of material and fouling acceptable because the 

performance testing, visual inspections, and NDEs used by the program are appropriate for 

detection of these aging effects and its water chemistry control activities will minimize fouling. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff’s evaluation for carbon or low alloy steel bolting externally exposed to soil which is 

being managed for loss of material or loss of preload by the Bolting Integrity Program is 

documented in SER Section 3.3.2.3.10. 

For the component type piping and fittings, the applicant proposed to assign reinforced concrete 

to the Open-Cycle Cooling Water System Program to manage the aging effects of cracking, loss 

of bond, loss of material (spalling, scaling)/corrosion of embedded steel, increase in porosity 

and permeability, and aggressive chemical attack in a raw water (internal) groundwater/soil 

environment. This item references Note J and plant-specific note 7. Plant-specific note 7 states 

that, “The Open-Cycle Cooling Water System aging management program activities are 

adequate for managing the aging effects of the internal surfaces of reinforced concrete service 

water piping. The Buried Non-Steel Piping Inspection aging management program activities are 

adequate for managing the aging effects of the external surfaces of reinforced concrete service 

water piping.” The applicant stated that these components have the intended function of 

pressure boundary and are examined using the Open-Cycle Cooling Water System Program. 

The staff’s review of the Open-Cycle Cooling Water System Program is documented in SER 

Section 3.0.3.1.9. Since the Open-Cycle Cooling Water System Program includes mitigative, 

performance-monitoring, and condition monitoring activities to manage aging effects caused by 
Aging Management Review Results 

 3-377 

biofouling, corrosion, erosion, protective coating failures, and silting in the open-cycle cooling 

water system, it is unclear to the staff that this is an adequate approach to managing aging of 

reinforced concrete piping and fitting components subjected to a raw water (internal) 

environment. By letter dated June 7, 2010, the staff issued RAI 3.5.2.1-6 requesting that the 

applicant discuss how the Open-Cycle Cooling Water System Program will adequately address 

the AERMs. A further discussion of the RAI response, as well as the adequacy of the credited 

program to manage the aging effects, is included in SER Section 3.5.2.1.8. 

3.3.2.3.28 Auxiliary Systems – Standby Diesel Generator Area Ventilation Systems – Summary 

of 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 standby diesel generator area ventilation system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.29 Auxiliary Systems – Standby Diesel Generators and Auxiliary Systems – Summary 

of Aging Management Evaluation – LRA Table 3.3.2-29 

In LRA Table 3.3.2-29, the applicant stated that copper alloy (greater than 15 percent Zn) 

bolting components exposed to indoor air are being managed for loss of preload due to thermal 

effects, gasket creep, and self-loosening by the Bolting Integrity Program. The AMR line items 

cite generic note F, which indicates that the material is not addressed in the GALL Report for 

these components. 

The staff reviewed the applicant’s Bolting Integrity Program and its evaluation is documented in 

SER Section 3.0.3.2.4. The staff finds the monitoring program acceptable to manage aging for 

these components because it includes visual inspections during maintenance or routine 

observations, such as system walkdowns, which can detect loss of preload and has 

incorporated industry guidance on proper selection of bolting materials, lubricants, and 

installation torque to ensure loss of preload does not occur. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.30 Auxiliary Systems – Standby Liquid Control System – Summary of 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 standby liquid control system component groups. 
Aging Management Review Results 

 3-378 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.31 Auxiliary Systems – Torus Water Cleanup System – Summary of 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 torus water cleanup system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.2.3.32 Auxiliary Systems – Traversing Incore Probe System – Summary of 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 traversing incore probe system component groups. 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.3.2.1. 

3.3.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the auxiliary system components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-379 

3.4 Aging Management of Steam and Power Conversion Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

steam and power conversion system components and component groups of the following: 

● condensate storage and transfer system 

● feedwater system 

● main condenser 

● main steam system 

3.4.1 Summary of Technical Information in the Application 

LRA Section 3.4 provides AMR results for the steam and power conversion system components 

and component groups. In LRA Table 3.4.1, “Summary of Aging Management Evaluations for 

Steam and Power Conversion,” the applicant provided a summary comparison of its AMRs to 

those evaluated in the GALL Report for steam and power conversion 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 

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. 

3.4.2 Staff Evaluation 

The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for steam and power conversion system 

components within the scope of license renewal and subject to an AMR will be adequately 

managed so that the intended functions will 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 AMPs to ensure the applicant’s claim that certain AMPs 

were consistent with the GALL Report. The purpose of this audit was to examine the applicant’s 

AMPs and related documentation and to verify the applicant’s claim of consistency with the 

corresponding GALL Report AMPs. The staff did not repeat its review of the matters described 

in the GALL Report. The staff’s evaluations of the AMPs are documented in SER Section 3.0.3. 

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 Sections 3.4.2.1 and 3.4.2.2. 

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. 

The review evaluated whether all plausible aging effects were identified and whether the aging 
Aging Management Review Results 

 3-380 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff’s evaluation are discussed in SER Section 3.4.2.3. 

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line items and the plant’s operating experience to 

verify the applicant’s claims. 

Table 3.4-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.4 and addressed in the GALL Report. 

Table 3.4-1 Staff Evaluation for Steam and Power Conversion 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 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 Fatigue is a TLAA 

(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 Not applicable Not applicable to 

BWRs (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 Water Chemistry 

and One-Time 

Inspection 

Consistent with 

GALL Report 

(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 3.4.2.2.7) 
Aging Management Review Results 

 3-381 

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 lubricating 

oil 

(3.4.1-7) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.4.2.2.2) 

Steel piping, piping 

components, and 

piping elements 

exposed to raw water 

(3.4.1-8) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Plant-specific Yes Not applicable Not applicable to 

HCGS (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 Not applicable Not applicable to 

HCGS (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 

microbiologicallyinfluenced 

corrosion 

Buried Piping and 

Tanks Surveillance 

or 

Buried Piping and 

Tanks Inspection 

No 

Yes Buried Piping 

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 

microbiologicallyinfluenced 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.4.2.2.5) 

Stainless steel piping, 

piping components, 

and piping elements 

exposed to steam 

(3.4.1-13) 

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 

 3-382 

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, 

piping elements, tanks, 

and heat exchanger 

components exposed 

to treated water 

> 60 °C (140 °F) 

(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) 

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 Not applicable Not applicable to 

HCGS (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 Not applicable Not applicable to 

HCGS (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 

microbiologicallyinfluenced 

corrosion 

Lubricating Oil 

Analysis and 

One-Time 

Inspection 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.4.2.2.8) 

Steel tanks exposed to 

air – outdoor (external) 

(3.4.1-20) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Aboveground Steel 

Tanks 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.4.2.1.1) 
Aging Management Review Results 

 3-383 

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 

(3.4.1-21) 

Cracking due to 

cyclic loading and 

SCC 

Bolting Integrity No Not applicable Not applicable to 

HCGS (See SER 

Section 3.4.2.1.1) 

Steel bolting and 

closure bolting exposed 

to air with steam or 

water leakage, air – 

outdoor (external), or 

air – indoor 

uncontrolled (external) 

(3.4.1-22) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion; 

loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening 

Bolting Integrity No Bolting Integrity Consistent with 

GALL Report 

Stainless steel piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water > 60 °C (140 °F) 

(3.4.1-23) 

Cracking due to 

SCC 

Closed-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

HCGS 

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 

HCGS 

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 

HCGS 
Aging Management Review Results 

 3-384 

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 air – 

outdoor (external) 

(3.4.1-28) 

Loss of material 

due to general 

corrosion 

External Surfaces 

Monitoring 

No External Surfaces 

Monitoring 

Consistent with 

GALL Report 

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 Flow-Accelerated 

Corrosion 

Consistent with 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to air – 

outdoor (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 

(See SER 

Section 3.4.2.1.3) 

Steel heat exchanger 

components exposed 

to raw water 

(3.4.1-31) 

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion and 

fouling 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

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 

microbiologicallyinfluenced 

corrosion 

Open-Cycle 

Cooling Water 

System 

No Not applicable Not applicable to 

HCGS 

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 Open-Cycle 

Cooling Water 

System 

Periodic 

Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.4.2.1.2) 

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 Not applicable Not applicable to 

HCGS 
Aging Management Review Results 

 3-385 

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 Not applicable Not applicable to 

HCGS 

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 Not applicable Not applicable to 

HCGS 

Steel, stainless steel, 

and nickel-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 Consistent with 

GALL Report 

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 Not applicable Not applicable to 

BWRs 

Stainless steel piping, 

piping components, 

and piping elements 

exposed to steam 

(3.4.1-39) 

Cracking due to 

SCC 

Water Chemistry No Not applicable Not applicable to 

BWRs 

Glass piping elements 

exposed to air, 

lubricating oil, raw 

water, and treated 

water

(3.4.1-40) 

None None No Not applicable Not applicable to 

HCGS (See SER 

Section 3.4.2.1.1) 

Stainless steel, copper 

alloy, and nickel-alloy 

piping, piping 

components, and 

piping elements 

exposed to air – indoor 

uncontrolled (external) 

(3.4.1-41) 

None None No None Consistent with 

GALL Report 
Aging Management Review Results 

 3-386 

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 air – indoor 

controlled (external) 

(3.4.1-42) 

None None No Not applicable Not applicable to 

HCGS 

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete 

(3.4.1-43) 

None None No Not applicable Not applicable to 

HCGS 

Steel, stainless steel, 

aluminum, and copper 

alloy piping, piping 

components, and 

piping elements 

exposed to gas 

(3.4.1-44) 

None None No Not applicable Not applicable to 

HCGS 

The staff’s review of the steam and power conversion system component groups followed 

several approaches. One approach, documented in SER Section 3.4.2.1, discusses the staff’s 

review of AMR results for components the applicant indicated are consistent with the GALL 

Report and require no further evaluation. Another approach, documented in SER 

Section 3.4.2.2, discusses the staff’s review of AMR results for components 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, discusses the staff’s review of AMR 

results for components 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 system components is documented in SER Section 3.0.3. 

3.4.2.1 AMR Results That Are Consistent with the GALL Report 

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the steam and power conversion system components: 

● Aboveground Non-Steel Tanks 

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

● Bolting Integrity 

● Buried Non-Steel Piping Inspection 

● Buried Piping Inspection 

● External Surfaces Monitoring 

● Flow-Accelerated Corrosion 

● Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

● One-Time Inspection 

● Periodic Inspection 
Aging Management Review Results 

 3-387 

● Small-Bore Class 1 Piping Inspection 

● TLAA 

● Water Chemistry 

LRA Tables 3.4.2-1 through 3.4.2-4 summarize the AMRs for the steam and power conversion 

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 had claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR line item. The notes describe how the information 

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

Notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR line 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 line 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 line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

AMP identified in the GALL Report. The staff audited these line items to verify consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 

Note C indicates that the component for the AMR line 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 audited these 

line items to verify consistency with the GALL Report and determined whether the AMR line 

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 line 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 audited these line items to 

verify consistency with the GALL Report and confirmed whether the AMR line item of the 

different component was applicable to the component under review. The staff confirmed 

whether it had reviewed and accepted the exceptions to the GALL Report AMPs. It 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 line item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff audited these line 

items to verify consistency with the GALL Report and determined whether the identified AMP 
Aging Management Review Results 

 3-388 

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 audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows. 

The staff notes that in LRA Table 3.4.2-1 there are AMR line items for a stainless steel tank 

exposed to treated water. The staff also notes that the LRA does not have a line item for the 

tank material exposed to an air or wetted gas internal environment as would occur when the 

tank is partially full. The staff further notes that the LRA line items manage the aging of the tank 

internals using the Water Chemistry and One-Time Inspection programs. The staff finds the 

existing line items acceptable because the chemistry program will minimize contaminant 

concentrations and thus mitigate loss of material due to various corrosion mechanisms for tank 

internal surfaces at the fluid to air transition zone. The One-Time Inspection Program will 

provide reasonable assurance that an aging effect is not occurring or that the aging effect is 

occurring slowly enough as to not affect a component’s intended function. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.4.2.1.1 Aging Management Review Results Identified as Not Applicable 

LRA Table 3.4.1, item 3.4.1-20 addresses loss of material due to general, pitting, and crevice 

corrosion in steel tanks exposed to air – outdoor. The applicant stated that this line item is not 

applicable because there are no steel tanks exposed to air – outdoor (external) in the steam and 

power conversion system. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that 

the applicant’s LRA does not have any AMR results for the steam and power conversion system 

that include steel tanks exposed to air – outdoor (external). The staff also reviewed the 

applicant’s UFSAR supplement and confirmed that no in-scope steel tanks exposed to air – 

outdoor are present in the steam and power conversion system and, therefore, the staff finds 

the applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1-21 addresses high-strength steel closure bolting exposed to air with 

steam or water leakage in the steam and power conversion system. The GALL Report 

recommends GALL AMP XI.M18, “Bolting Integrity,” to manage cracking due to cyclic loading or 

SCC for this component group. The applicant stated that this item is not applicable because 

there is no high-strength closure bolting in the steam and power conversion system. The staff 

reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant’s LRA does not have any 

AMR results for the steam and power conversion system that includes high-strength steel 

closure bolting exposed to air with steam or water leakage. The staff reviewed the applicant’s 

UFSAR supplement and confirmed that no in-scope high-strength steel closure bolting exposed 

to air with steam or water leakage is present in the steam and power conversion system and, 

therefore, the staff finds the applicant’s determination acceptable. 

LRA Table 3.4.1, item 3.4.1-40 addresses glass piping elements exposed to air, lubricating oil, 

raw water, and treated water. The applicant stated that this line item is not applicable because 

there are no glass piping elements exposed to air, lubricating oil, raw water, or treated water in 
Aging Management Review Results 

 3-389 

the steam and power conversion system. The staff reviewed LRA Sections 2.3.4 and 3.4 and 

confirmed that the applicant’s LRA does not have any AMR results for the steam and power 

conversion system that include glass piping elements exposed to air, lubricating oil, raw water, 

and treated water. The staff notes that the applicant stated that there is no AERM or 

recommended AMP for this material and component combination. The staff also notes that the 

GALL Report recommends that there is no AERM or AMP for this material and environment 

combination. The staff, therefore, finds that the applicant’s proposal that there is no AERM or 

AMP acceptable, regardless of whether or not the material and environment combination exists 

in the steam and power conversion system. 

3.4.2.1.2 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

and Fouling 

LRA Table 3.4.1, item 3.4.1-33 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 LRA credits the Periodic Inspection 

Program to manage aging for piping and fittings in the fresh water supply system. The GALL 

Report recommends GALL AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that 

these aging effects are adequately managed. The AMR line item cites generic note E, which 

indicates that the line item is consistent with the GALL Report for the material, environment, and 

aging effect, but a different AMP is credited. 

GALL AMP XI.M20 recommends preventive measures including proper selection of materials 

and coatings, periodic flushes and cleaning, and raw water chemistry control, as well as visual 

inspections and NDE testing for components exposed to open-cycle cooling water. Open-cycle 

cooling water is water that transfers heat from safety-related components to the ultimate heat 

sink. 

The staff reviewed the applicant’s Periodic Inspection Program and its evaluation is documented 

in SER Section 3.0.3.3.2. The staff noted that the Periodic Inspection Program includes 

periodic visual inspections of components and ultrasonic wall thickness measurements to detect 

loss of material and fouling. The staff also notes that the fresh water supply system supplies 

potable water for the plant and does not contain safety-related components exposed to 

open-cycle cooling water; therefore, the use of the Open-Cycle Cooling Water Program would 

not be appropriate. The staff finds the applicant’s use of the Periodic Inspection Program 

acceptable to manage aging for these components because it performs periodic visual 

inspections and wall thickness measurements that are appropriate to detect loss of material and 

fouling. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.4.2.1.3 Loss of Material Due to General, Pitting, and Crevice Corrosion 

LRA Table 3.4.1, item 3.4.1-30 addresses steel piping, piping components, and piping elements 

exposed internally to outdoor air or condensation which are being managed for loss of material 

due to general, pitting, and crevice corrosion. The LRA credits the One-Time Inspection 

Program, in addition to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program, to manage these aging effects for steel piping and fittings exposed 
Aging Management Review Results 

 3-390 

internally to wetted air or gas. The GALL Report recommends GALL AMP XI.M38, “Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to ensure these aging 

effects are adequately managed. The AMR line item that references the One-Time Inspection 

Program cites generic note E, indicating that the LRA AMR is consistent with the GALL Report 

item for material, environment, and aging effect, but a different AMP is credited. The AMR line 

item also cites plant-specific note 7, indicating that the One-Time Inspection Program is also 

being used to manage loss of material for the safety relief valve discharge line where it enters 

the torus, based upon recent industry operating experience. 

The staff reviewed the AMR results lines in the LRA and confirmed that the component for 

which the applicant referenced item 3.4.1-30 and cited generic note E, is also being managed 

by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program in another line. The staff reviewed the applicant’s One-Time Inspection Program and 

its evaluation is documented in SER Section 3.0.3.1.11. The staff finds the applicant’s 

proposed program acceptable to manage aging for these components because the One-Time 

Inspection Program performs visual or volumetric inspections of a sampling of components to 

confirm that aging is not occurring or is progressing very slowly, and the program is being 

implemented in addition to the GALL Report recommended program for these components. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.4.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further 

Evaluation is Recommended 

LRA Section 3.4.2.2 provides further evaluation of aging management, as recommended by the 

GALL Report for the steam and power conversion system 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 material due to general, pitting, crevice, and microbiologically-influenced 

corrosion and fouling 

● reduction of heat transfer due to fouling 

● loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion 

● cracking due to SCC 

● loss of material due to pitting and crevice corrosion 

● loss of material due to pitting, crevice, and microbiologically-influenced corrosion 

● loss of material due to general, pitting, crevice, and galvanic corrosion 
Aging Management Review Results 

 3-391 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which the GALL Report recommends further 

evaluation, the staff audited and reviewed the applicant’s evaluations to determine whether they 

adequately address those issues and reviewed the applicant’s further evaluations against the 

criteria in SRP-LR Section 3.4.2.2. The staff’s review of the applicant’s further evaluations 

follows. 

3.4.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.4.2.2.1 addresses the applicant’s AMR basis for managing cumulative fatigue 

damage in steam and power conversion system components that were designed and analyzed 

to applicable design analysis criteria in the ASME Code Section III, Articles NC-3000 or 

ND-3000 (as applicable to Code Class 2 or 3 components, respectively) or in the ANSI B31.1 

Code, and for which implicit fatigue analyses were required. In this LRA section, the applicant 

stated that the evaluation of fatigue is a TLAA as defined in 10 CFR 54.3 and that the TLAAs 

are evaluated in accordance with the TLAA acceptance criteria in 10 CFR 54.21(c)(1). The 

applicant stated that the HCGS piping designed to ASME Code Section III requirements for 

Class 2 or 3 components or to the ANSI B31.1 design code were analyzed using an implicit 

fatigue analysis that assumes a reduction in the component’s allowable secondary stress range 

if more than 7,000 full-range thermal cycles are expected over the component’s design lifetime. 

In LRA Table 3.4.1, the applicant stated that the AMR item 3.4.1-1 for managing cumulative 

fatigue damage for the feedwater, main steam, and reactor water cleanup system piping, piping 

components, and piping elements is consistent with the staff’s AMR item recommendations in 

AMR item 1 of Table 4 in the GALL Report, Volume 1, Revision 1. The applicant stated that, for 

these AMRs, cumulative fatigue damage in the components will be managed using a TLAA and 

that LRA Section 4.3.4 describes and evaluates implicit fatigue analysis-based TLAAs for these 

components. 

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, and that 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 the staff’s 

recommended acceptance criteria and review procedures for reviewing these TLAAs in SRP-LR 

Section 4.3, “Metal Fatigue Analysis.” The staff also reviewed LRA Section 3.4.2.2.1 and the 

applicant’s AMR items referenced to this LRA section against the staff’s AMR items for 

evaluating cumulative fatigue damage as given in AMR item 1 in the GALL Report, Volume 1, 

Table 4 and the AMR items in Section VIII of the GALL Report, Volume 2, Revision 1 that derive 

from this GALL Report, Volume 1 AMR item. 

With regard to the applicant’s metal fatigue AMR item 3.4.1-1, the staff noted that AMR item 1 in 

Table 4 of the GALL Report, Volume 1 and AMR items VIII.B2-5 and VIII.D2-6 in the GALL 

Report, Volume 2 identify that cumulative fatigue damage is an applicable aging effect for steel 

piping, piping components, and piping elements. The staff also noted that these GALL Report 

AMRs recommend that the TLAA on metal fatigue be used to manage the impact of cumulative 

fatigue damage in these components. The staff noted that, in conformance with this 

recommendation, the applicant included an applicable line item in LRA Tables 3.3.2-24, 3.4.2-2, 

and 3.4.2-4 for steel piping, piping components, and piping elements that received ASME Code 

Section III CUF or ANSI B31.1 design code analysis calculations. The staff noted that the 

applicant credited the TLAA analysis in LRA Section 4.3.4 with the management of cumulative 

fatigue damage in these components. The staff found that the applicant’s AMR assessment 
Aging Management Review Results 

 3-392 

was in conformance with the recommendations in both the SRP-LR and in AMR item 1 of the 

GALL Volume 1, Table 4 and AMR items VIII.B2-5 and VIII.D2-6 in the GALL Report, Volume 2. 

Based on this review, the staff finds the applicant’s AMR analysis on cumulative fatigue damage 

of piping, piping components, and piping elements to be acceptable because it is in 

conformance with the recommendations in SRP-LR Section 3.3.2.2.1 and the GALL Report 

AMR items that are invoked by this SRP-LR section. The staff evaluates the TLAA analysis for 

the support skirt and attachment welds component in SER Section 4.3.4. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.1 criteria. For those items that apply to LRA Section 3.4.2.2.1, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.4.2.2.2 against the criteria in SRP-LR Section 3.4.2.2.2. 

 (1) LRA Section 3.4.2.2.2, item 1 refers to Table 3.4.1, items 3.4.1-2 and 3.4.1-4 and 

addresses steel piping, piping components, piping elements, and turbine casings 

exposed to treated water or steam which are being managed for loss of material due to 

general, pitting, and crevice corrosion. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that this aging mechanism of the associated 

components in the stated environment will be managed by the Water Chemistry and 

One-Time Inspection programs for the condensate storage and transfer, feedwater, and 

main steam systems. 

 The staff reviewed LRA Section 3.4.2.2.2, item 1 against the criteria described in 

SRP-LR Section 3.4.2.2.2, item 1, which states 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 controlling water chemistry to 

mitigate degradation and that a one-time inspection of components at susceptible 

locations is an acceptable method to verify the effectiveness of the chemistry control 

program. 

 The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection 

programs is documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. In its 

review of components associated with items 3.4.1-2 and 3.4.1-4, the staff finds the 

applicant’s proposed programs acceptable because the Water Chemistry Program will 

ensure that contaminants are maintained below applicable limits to minimize loss of 

material due to general, pitting, and crevice corrosion, and the One-Time Inspection 

Program will inspect components in aggressive environments, such as low or stagnant 

flow, to verify the effectiveness of the Water Chemistry Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2, item 1 criteria. For those line items that apply to LRA 

Section 3.4.2.2.2, item 1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 
Aging Management Review Results 

 3-393 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 LRA Section 3.4.2.2.2.1 also refers to Table 3.4.1, item 3.4.1-3 and addresses the loss 

of material due to general, pitting, and crevice corrosion. The applicant stated that this 

aging effect is not applicable to HCGS, which is a BWR. 

 SRP-LR Section 3.4.2.2.2.1 states 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 staff verified that SRP-LR Section 3.4.2.2.2.1 is not applicable to HCGS because 

HCGS is a BWR and the staff guidance in this SRP-LR section is only applicable to 

PWRs. SRP-LR Table 3.4-1 identifies item 3 as applicable to PWRs. 

 Based on the above, the staff concludes that the staff’s guidance criteria of SRP-LR 

Section 3.4.2.2.2.1 do not apply to HCGS because the guidance is applicable to PWRs. 

 (2) LRA Section 3.4.2.2.2.2 refers to Table 3.4.1, item 3.4.1-7 and addresses the loss of 

material due to general, pitting, and crevice corrosion. The applicant stated that this 

aging effect is not applicable because HCGS does not have any steel piping, piping 

components, or piping elements exposed to a lubricating oil environment in the steam 

and power conversion system. 

 SRP-LR Section 3.4.2.2.2.2 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 staff reviewed the applicant’s UFSAR supplement and finds that SRP-LR 

Section 3.4.2.2.2, item 2 is not applicable to HCGS because HCGS does not have any 

steel piping, piping components, or piping elements exposed to a lubricating oil 

environment in the steam and power conversion system, and the staff guidance in this 

SRP-LR section is only applicable to BWR steel piping, piping components, or piping 

elements exposed to a lubricating oil environment in the steam and power conversion 

system. 

Based on the staff’s review and evaluation of the applicant’s programs, the staff concludes that 

the applicant’s programs satisfy SRP-LR Section 3.4.2.2.2 criteria. For those line items that 

apply to LRA Section 3.4.2.2.2, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.2.3 Loss of Material due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion and Fouling 

LRA Section 3.4.2.2.3 refers to Table 3.4.1, item 3.4.1-8 and addresses the loss of material due 

to general, pitting, crevice, and microbiologically-influenced corrosion and fouling. The applicant 

stated that this aging effect is not applicable because HCGS does not have any steel piping, 

piping components, or piping elements exposed to a raw water environment in the steam and 

power conversion system. 
Aging Management Review Results 

 3-394 

SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion and fouling could occur for steel piping, piping 

components, and piping elements exposed to raw water. 

The staff reviewed the applicant’s UFSAR supplement and finds that SRP-LR Section 3.4.2.2.3 

is not applicable to HCGS because HCGS does not have any steel piping, piping components, 

or piping elements exposed to a raw water environment in the steam and power conversion 

system, and the staff guidance in this SRP-LR section is only applicable to BWR steel piping, 

piping components, or piping elements exposed to a raw water environment in the steam and 

power conversion system. 

3.4.2.2.4 Reduction of Heat Transfer Due to Fouling 

The staff reviewed LRA Section 3.4.2.2.4 against the criteria in SRP-LR Section 3.4.2.2.4. 

 (1) LRA Section 3.4.2.2.4, item 1 refers to LRA Table 3.4.1, item 3.4.1-9 and addresses 

stainless steel and copper alloy heat exchanger tubes exposed to treated water which 

are being managed for reduction of heat transfer due to fouling by the Water Chemistry 

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 verify the 

effectiveness of the Water Chemistry Program for copper alloy heat exchanger 

components in the HPCI and RCIC systems. 

 The staff reviewed LRA Section 3.4.2.2.4, item 1 against the criteria in SRP-LR 

Section 3.4.2.2.4, item 1 which states that reduction of heat transfer due to fouling could 

occur for stainless steel and copper alloy heat exchanger tubes exposed to treated water 

and that the existing AMP relies on the control of water chemistry to manage reduction 

of heat transfer due to fouling. The SRP-LR also states that control of water chemistry 

may not always have been adequate to preclude fouling and recommends that the 

effectiveness of the water chemistry control be verified by a one-time inspection to 

ensure reduction of heat transfer does not occur. 

 The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection 

programs is documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. In its 

review of components associated with item 3.4.1-9, the staff finds the applicant’s 

proposal to manage aging using the above programs acceptable because the Water 

Chemistry Program provides for periodic sampling of treated water to maintain 

contaminants at acceptable limits to preclude loss of heat transfer due to fouling, and the 

One-Time Inspection Program will verify the effectiveness of the Water Chemistry 

Program by including inspections of select components at appropriate locations, 

including low or stagnant flow areas. 

 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 line items that apply to LRA 

Section 3.4.2.2.4, item 1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-395 

 (2) LRA Section 3.4.2.2.4.2 refers to Table 3.4.1, item 3.4.1-10 and addresses reduction of 

heat transfer due to fouling. The applicant stated that this aging effect is not applicable 

because HCGS does not have any steel, stainless steel, and copper alloy heat 

exchanger tubes exposed to a lubricating oil environment in the steam and power 

conversion system. 

 SRP-LR Section 3.4.2.2.4.2 states that reduction of heat transfer due to fouling could 

occur for steel, stainless steel, and copper alloy heat exchanger tubes exposed to 

lubricating oil. 

 The staff reviewed the applicant’s UFSAR supplement and finds that SRP-LR 

Section 3.4.2.2.4, item 2 is not applicable to HCGS because HCGS does not have any 

steel, stainless steel, and copper alloy heat exchanger tubes exposed to a lubricating oil 

environment in the steam and power conversion system, and the staff guidance in this 

SRP-LR section is only applicable to BWR steel, stainless steel, and copper alloy heat 

exchanger tubes exposed to a lubricating oil environment in the steam and power 

conversion system. 

Based on the staff’s review and evaluation of the applicant’s programs, the staff concludes that 

the applicant’s programs meet SRP-LR Section 3.4.2.2.4 criteria. For those line items that 

apply to LRA Section 3.4.2.2.4, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.2.5 Loss of Material due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

The staff reviewed LRA Section 3.4.2.2.5 against the criteria in SRP-LR Section 3.4.2.2.5. 

 (1) LRA Section 3.4.2.2.5.1 refers to Table 3.4.1, item 3.4.1-11 and addresses loss of 

material due to general, pitting, crevice, and microbiologically-influenced corrosion in 

steel piping, piping components, and piping elements exposed to soil. The applicant 

stated that loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion in the steel piping, piping components, and piping 

elements exposed to soil in the condensate storage and transfer system will be 

managed by the Buried Piping Inspection Program. The applicant also stated that there 

are no steel tanks exposed to soil in the steam and power conversion system. 

 The staff reviewed LRA Section 3.4.2.2.5.1 against the criteria in SRP-LR 

Section 3.4.2.2.5.1, which states that loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion could occur in steel piping, piping components, 

piping elements, and tanks, with or without coating or wrapping, in a soil environment. 

The SRP-LR also states that the effectiveness of the buried piping and tanks inspection 

program should be verified to evaluate an applicant’s inspection frequency and operating 

experience with buried components, ensuring that loss of material is not occurring. 

 The staff reviewed the applicant’s Buried Piping Inspection Program, which is evaluated 

in SER Section 3.0.3.2.12. The staff finds that the credited program is appropriate 

because the Buried Piping Inspection Program relies on preventive measures such as 

coating and wrapping to mitigate corrosion and periodic visual inspections of external 
Aging Management Review Results 

 3-396 

surfaces to identify coating degradation and, therefore, ensures that the loss of material 

aging effect will be adequately managed. 

 The staff reviewed the LRA AMR items and information in the UFSAR supplement 

associated with Table 3.4.1, item 3.4.1-11 and confirmed that there are no steel tanks 

exposed to soil in the steam and power conversion system. Therefore, the staff finds the 

applicant’s determination acceptable that LRA Table 3.4.1, item 3.4.1-11 is not 

applicable for tanks. 

 Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.4.2.2.5.1 criteria. For those items that apply to LRA 

Section 3.4.2.2.5.1, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that 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). 

 (2) LRA Section 3.4.2.2.5.2 refers to Table 3.4.1, item 3.4.1-12 and addresses loss of 

material due to general, pitting, crevice and microbiologically-influenced corrosion. The 

applicant stated that this aging effect is not applicable because HCGS does not have 

any steel heat exchanger components exposed to a lubricating oil environment in the 

steam and power conversion system. 

 SRP-LR Section 3.4.2.2.5.2 states that loss of material due to general, pitting, crevice 

and microbiologically-influenced corrosion could occur in steel heat exchangers exposed 

to lubricating oil. 

 The staff reviewed the applicant’s UFSAR supplement and finds that SRP-LR 

Section 3.4.2.2.5, item 2 is not applicable to HCGS because HCGS does not have steel 

heat exchanger components exposed to a lubricating oil environment in the steam and 

power conversion system, and the staff guidance in this SRP-LR section is only 

applicable to BWR steel heat exchanger components exposed to a lubricating oil 

environment in the steam and power conversion system. 

Based on the staff’s review and evaluation of the applicant’s program, the staff concludes that 

the applicant’s program meets SRP-LR Section 3.4.2.2.5 criteria. For those line items that 

apply to LRA Section 3.4.2.2.5, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.2.6 Cracking Due to Stress-Corrosion Cracking 

The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6. 

LRA Section 3.4.2.2.6 refers to LRA Table 3.4.1, items 3.4.1-13 and 3.4.1-14 and addresses 

stainless steel piping, piping components, and piping elements exposed to steam and stainless 

steel piping, piping components, piping elements, tanks, and heat exchanger components 

exposed to treated water greater than 60 °C (140 °F), respectively, which are being managed 

for cracking due to SCC by the Water Chemistry Program and One-Time Inspection Program. 

The applicant addressed the further evaluation criteria of the SRP-LR by stating that it will 
Aging Management Review Results 

 3-397 

implement a One-Time Inspection Program for susceptible locations to verify the effectiveness 

of the Water Chemistry Program to manage cracking due to SCC. 

The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR 3.4.2.2.6, which states 

that SCC could occur in stainless steel piping, piping components, piping elements, tanks, and 

heat exchanger components exposed to treated water greater than 60 °C (140 °F) and 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 water chemistry. 

However, the SRP-LR also states that high concentrations of impurities at crevices and 

locations with stagnant flow conditions could cause SCC. The SRP-LR further states that the 

GALL Report recommends that the effectiveness of the water chemistry control program should 

be verified to ensure that SCC does not occur. A one-time inspection of select components at 

susceptible locations is an acceptable method to ensure that SCC does not occur and that the 

component’s intended function will be maintained during the period of extended operation. 

The staff’s evaluation of the applicant’s Water Chemistry Program and One-Time Inspection 

Program is documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. The staff noted 

the applicant’s One-Time Inspection Program includes one-time inspection of more susceptible 

materials in potentially more aggressive environments to manage the effects of aging. In its 

review of components associated with items 3.4.1-13 and 3.4.1-14, the staff finds the applicant’s 

proposal to manage aging using the Water Chemistry Program and One-Time Inspection 

Program acceptable because: (1) the Water Chemistry Program monitors the plant water 

chemistry control parameters against the established parameter limits and, if a parameter 

exceeds the limit, the program performs adequate actions such that the water chemistry control 

continues to mitigate the aging effect; (2) the One-Time Inspection Program includes a one-time 

inspection of select components to verify the effectiveness of the Water Chemistry Program in a 

consistent manner with the recommendation in the GALL Report; and (3) the one-time 

inspection can ensure that significant degradation is not occurring or progressing very slowly so 

that the component’s intended function is maintained during the period of extended operation. 

The staff finds that the applicant’s AMR results are consistent with GALL AMR items VIII.B2-1 

and VIII.E-31 and the recommendations in the SRP-LR. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.6 criteria. For those line items that apply to LRA Section 3.4.2.2.6, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.4.2.2.7 against the criteria in SRP-LR Section 3.4.2.2.7. 

 (1) LRA Section 3.4.2.2.7, item 1 refers to Table 3.4.1, items 3.4.1-6, 3.4.1-15, and 3.4.1-16 

and addresses copper alloy heat exchanger components and stainless steel piping, 

piping components, piping elements, and tanks exposed to treated water which are 

being managed for loss of material due to pitting and crevice corrosion. The applicant 

stated that this aging effect for the related components in the HPCI, RCIC, condensate 

storage and transfer, and main steam systems will be managed by the Water Chemistry 

and One-Time Inspection programs. 
Aging Management Review Results 

 3-398 

 The staff reviewed LRA Section 3.4.2.2.7, item 1 against the criteria described in 

SRP-LR Section 3.4.2.2.7, item 1, which states 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 stainless steel tanks and heat 

exchanger components exposed to treated water. The SRP-LR also states that the 

existing AMP relies on monitoring and controlling water chemistry to mitigate 

degradation and that a one-time inspection of select components at susceptible 

locations is an acceptable method to verify the effectiveness of the chemistry control 

program. 

 The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection 

programs is documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, 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 the proposed programs acceptable because the Water Chemistry Program will 

ensure that contaminants are maintained below applicable limits to minimize loss of 

material due to pitting and crevice corrosion, and the One-Time Inspection Program will 

inspect components in more aggressive environments, such as low or stagnant flow, to 

verify the effectiveness of the Water Chemistry Program. 

 Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.7, item 1 criteria. For those line items that apply to LRA 

Section 3.4.2.2.7, item 1, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that 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). 

 (2) LRA Section 3.4.2.2.7.2, associated with LRA Table 3.4.1, item 3.4.1-17, addresses loss 

of material due to pitting and crevice corrosion in stainless steel piping, piping 

components, and piping elements exposed to soil. The applicant stated that this line 

item is not applicable because, “the AMR methodology for stainless steel piping, piping 

components, and piping elements exposed to soil predicts microbiologically-influenced 

corrosion in addition to pitting, and crevice corrosion. There are no NUREG-1801 AMR 

lines available for stainless steel components exposed to soil that include all of these 

mechanisms.” 

 The staff reviewed LRA Tables 3.4.2-1 and notes that the applicant has included an 

AMR line item, citing generic note H, which will manage loss of material due to pitting, 

crevice, and microbiologically-influenced corrosion for stainless steel piping and fittings 

with the Buried Non-Steel Piping Inspection Program. The staff finds the applicant’s 

proposal to manage these components with the Buried Non-Steel Piping Inspection 

Program acceptable because the visual inspections conducted by this program will 

detect loss of material due to pitting, crevice, and microbiologically-influenced corrosion. 

The staff reviewed LRA Sections 2.3.4 and 3.4 and the UFSAR supplement and 

confirmed that no other in-scope stainless steel piping, piping components, and piping 

elements exposed to soil are present in the steam and power conversion system and, 

therefore, finds the applicant’s determination acceptable. 

 (3) LRA Section 3.4.2.2.7.3 refers to Table 3.4.1, item 3.4.1-18 and addresses loss of 

material due to pitting and crevice corrosion. The applicant stated that this aging effect 

is not applicable because HCGS does not have any copper alloy piping, piping 

components, and piping elements exposed to a lubricating oil environment in the steam 

and power conversion system. 
Aging Management Review Results 

 3-399 

 SRP-LR Section 3.4.2.2.7.3 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 staff reviewed the applicant’s UFSAR supplement and finds that SRP-LR 

Section 3.4.2.2.7, item 3 is not applicable to HCGS because HCGS does not have any 

copper alloy piping, piping components, and piping elements exposed to a lubricating oil 

environment in the steam and power conversion system, and the staff guidance in this 

SRP-LR section is only applicable to BWR copper alloy piping, piping components, and 

piping elements exposed to a lubricating oil environment in the steam and power 

conversion system. 

Based on the staff’s review and evaluation of the applicant’s programs, the staff concludes that 

the applicant’s programs meet SRP-LR Section 3.4.2.2.7 criteria. For those line items that 

apply to LRA Section 3.4.2.2.7, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.2.8 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

LRA Section 3.4.2.2.8 refers to Table 3.4.1, item 3.4.1-19 and addresses loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion. The applicant stated that this aging 

effect is not applicable because HCGS does not have any stainless steel piping, piping 

components, piping elements, or heat exchanger components exposed to a lubricating oil 

environment in the steam and power conversion system. 

SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion could occur in stainless steel piping, piping components, 

piping elements, or heat exchanger components exposed to lubricating oil. 

The staff reviewed the applicant’s UFSAR supplement and finds that SRP-LR Section 3.4.2.2.8 

is not applicable to HCGS because HCGS does not have any stainless steel piping, piping 

components, piping elements, or heat exchanger components exposed to a lubricating oil 

environment in the steam and power conversion system, and the staff guidance in this SRP-LR 

section is only applicable to BWR stainless steel piping, piping components, piping elements, or 

heat exchanger components exposed to a lubricating oil environment in the steam and power 

conversion system. 

3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion 

The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.9. 

LRA Section 3.4.2.2.9 refers to LRA Table 3.4.1, item 3.4.1-5 and addresses steel heat 

exchanger components exposed to treated water which are being managed for loss of material 

due to general, pitting, crevice, and galvanic corrosion by the Water Chemistry and One-Time 

Inspection programs. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the effectiveness of the Water Chemistry Program to manage this aging effect will 

be verified through inspections at susceptible locations through the One-Time Inspection 

Program. 
Aging Management Review Results 

 3-400 

The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.9, which 

states that the existing AMP relies on monitoring and controlling water chemistry to manage the 

effects of loss of material due to general, pitting, and crevice corrosion; however, control of 

water chemistry does not preclude loss of material due to general, pitting, and crevice corrosion 

at locations of stagnant flow conditions. The SRP-LR also states that the effectiveness of water 

chemistry controls should be verified to ensure that corrosion is not occurring and that a 

one-time inspection of select components at susceptible locations is an acceptable method to 

ensure that corrosion does not occur. 

The staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection programs is 

documented in SER Sections 3.0.3.2.1 and 3.0.3.1.11, respectively. In its review of 

components associated with item 3.4.1-5, the staff finds the applicant’s proposal to manage 

aging using the above programs acceptable because: (1) the Water Chemistry Program 

provides for periodic sampling of treated water to maintain contaminants at acceptable limits to 

preclude this aging effect, and (2) the One-Time Inspection Program will inspect select 

components exposed to treated water for loss of material due to pitting and crevice corrosion to 

verify the effectiveness of the Water Chemistry Program. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.9 criteria. For those line items that apply to LRA Section 3.4.2.2.9, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.4.2.2.10 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. 

3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.4.2-1 through 3.4.2-4, 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 3.4.2-1 through 3.4.2-4, the applicant indicated, via Notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to a 

line 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 line 

item component is not evaluated in the GALL Report. Note G indicates that the environment for 

the AMR line item component and material is not evaluated in the GALL Report. Note H 

indicates that the aging effect for the AMR line item component, material, and environment 

combination is not evaluated in the GALL Report. Note I indicate that the aging effect identified 

in the GALL Report for the line item component, material, and environment combination is not 

applicable. Note J indicates that neither the component nor the material and environment 

combination for the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant had 

demonstrated that the aging effects will be adequately managed so that the intended function(s) 
Aging Management Review Results 

 3-401 

will be maintained consistent with the CLB during the period of extended operation. The staff’s 

evaluation is discussed in the following sections. 

3.4.2.3.1 Steam and Power Conversion System – Condensate Storage and Transfer System – 

Summary of Aging Management Evaluation – LRA Table 3.4.2-1 

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMRs for the 

condensate storage and transfer system component groups. 

In LRA Tables 3.4.2-1 and 3.3.2-10, the applicant stated that stainless steel piping and fittings 

exposed externally to soil are being managed for loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion by the Buried Non-Steel Piping Inspection Program. The 

AMR line items cite generic note H, which indicates that the aging effect is not addressed in the 

GALL Report for this component, material, and environment combination. 

The staff reviewed the applicant’s Buried Non-Steel Piping Inspection Program and its 

evaluation is documented in SER Section 3.0.3.3.4. The staff finds the applicant’s proposed 

program acceptable to manage aging for these components because it uses opportunistic and 

focused visual inspections of coatings and the base metal to detect loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.4.2-1, the applicant stated that stainless steel tanks exposed externally to soil 

are being managed for loss of material by the Aboveground Non-Steel Tanks Program. The 

AMR line items cite generic note G, which indicates that the environment is not addressed in the 

GALL Report for the component and material. 

The staff reviewed the applicant’s Aboveground Non-Steel Tanks Program and its evaluation is 

documented in SER Section 3.0.3.3.3. The staff finds the applicant’s proposed program 

acceptable to manage loss of material for these components because it performs visual 

inspections of the exterior surfaces of the tank, as well as thickness measurements of the tank 

bottom to detect loss of material. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.3.2 Steam and Power Conversion System – Feedwater System – Summary of Aging 

Management Evaluation – LRA Table 3.4.2-2 

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the 

feedwater system component groups. 
Aging Management Review Results 

 3-402 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.4.2.1. 

3.4.2.3.3 Steam and Power Conversion System – Main Condenser System – Summary of 

Aging Management Evaluation – LRA Table 3.4.2-3 

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMRs for the main 

condenser system component groups. 

In LRA Table 3.4.2-3, the applicant stated that carbon steel main condenser shells exposed 

externally to indoor air or internally to steam have no AERMs. The AMR line items cite generic 

note J, indicating that neither the component nor the material and environment combination is in 

the GALL Report. The AMR line items also cite plant-specific note 1, which states that the main 

condenser is within the scope of license renewal because it performs the post-accident function 

of providing a holdup volume for activity products and does not need to be leak tight or capable 

of maintaining a vacuum to perform this function. The applicant also stated that its radiological 

analysis assumes condenser vacuum is lost with a 1 percent per day leak rate. The applicant 

further stated that normal plant operation assures adequate condenser pressure boundary 

integrity and, therefore, the post-accident intended function to provide a holdup volume is 

assured. 

The staff reviewed the applicant’s current UFSAR supplement and confirmed that the main 

condenser has no safety-related functions. The staff finds the applicant’s claim that the main 

condenser shells have no AERM acceptable because the main condenser’s integrity is 

continually verified during normal plant operation and, therefore, its post-accident function as a 

holdup volume is continuously assured. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.4.2-3, the applicant stated that aluminum bronze main condenser tubesheets 

exposed internally to raw water or externally to steam have no AERMs. The AMR line items cite 

generic note J, indicating that neither the component nor the material and environment 

combination is in the GALL Report. The AMR line items also cite plant-specific note 1, which 

states that the main condenser is within the scope of license renewal because it performs the 

post-accident function of providing a holdup volume for activity products and does not need to 

be leak tight to perform this function. 

The applicant also stated its radiological analysis assumes the condenser is isolated and 

vacuum is lost with a 1 percent per day leakage, which does not challenge the pressure 

boundary integrity of the condenser. The applicant further stated that since normal plant 

operation assures adequate condenser pressure boundary integrity, the post-accident intended 

function to provide holdup volume is assured. 
Aging Management Review Results 

 3-403 

The staff reviewed the applicant’s UFSAR supplement and confirmed that the main condenser 

has no safety-related functions. The staff finds the applicant’s claim that the main condenser 

tubesheets have no AERM acceptable because the main condenser’s integrity is continually 

verified during normal plant operation and, therefore, its post-accident function as a holdup 

volume is continuously assured. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.4.2-3, the applicant stated that the titanium main condenser tube components 

exposed to raw water (internal) or steam (external) is not addressed by the GALL Report. The 

applicant referenced note J for this item, indicating that neither the component nor the material 

and environment combination is evaluated in the GALL Report. The applicant also stated that 

no AMP is needed for this component, material, and environment combination. The applicant 

further stated in plant-specific footnote 1 that the post-accident intended function of the main 

condenser is to provide a holdup volume which does not require the condenser to be leak-tight 

because the radiological analysis assumes the condenser is isolated and vacuum is lost, with 

1 percent per day leakage, and this function is proven during plant operations on a continuous 

basis by maintaining a vacuum. 

The staff confirmed that the GALL Report does not include an AERM or AMP for titanium alloy 

tube components exposed to raw water (internal) or steam (external) environments. 

The staff notes that based on multiple references (e.g., AZo Journal of Materials Online, 

Britannica Encyclopedia, Key to Metals Database (online) Article 24), titanium is resistant to 

pitting, general, and crevice corrosion and SCC in salt water and turbine exhaust steam 

environments in essence due to its formation of very stable, continuous, highly adherent, and 

protective oxide films on metal surfaces. Based on these references, the staff also notes that 

due to its corrosion resistance capabilities, it is widely used in the refinery industry for 

condenser tubing and the aerospace industry in temperature applications up to 600°C. The 

staff finds the applicant’s proposal that there are no other AERMs, other than the reduction of 

heat transfer, acceptable based on titanium’s resistance to pitting, general, and crevice 

corrosion and SCC in raw water internal and steam external environment. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.2.3.4 Steam and Power Conversion System – Main Steam System – Summary of Aging 

Management Evaluation – LRA Table 3.4.2-4 

The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMRs for the main 

steam system component groups. 
Aging Management Review Results 

 3-404 

The staff’s review did not find any line items indicating plant-specific Notes F through J whereby 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. 

The staff’s evaluation of the line items with Notes A through E is documented in SER 

Section 3.4.2.1. 

3.4.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the steam and power conversion system components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-405 

3.5 Aging Management of Containments, Structures, and Component Supports

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

containments, structures, and component supports groups of: 

● auxiliary boiler building 

● auxiliary building control/diesel generator area 

● auxiliary building service/radwaste area 

● component supports commodity group 

● fire water pump house 

● piping and component insulation commodity group 

● primary containment 

● reactor building 

● service water intake structures 

● shoreline protection and dike 

● switchyard 

● turbine building 

● yard 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 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.5.2 Staff Evaluation 

The staff reviewed LRA Section 3.5 to determine whether the applicant has provided sufficient 

information to demonstrate that the effects of aging for the containment, 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 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. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s evaluation 

are discussed in SER Section 3.5.2.1. 
Aging Management Review Results 

 3-406 

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 3.5.2.2 acceptance criteria. The staff’s evaluations are documented in 

SER Section 3.5.2.2. 

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. 

The review evaluated whether all plausible aging effects were identified and whether the aging 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff’s evaluation are discussed 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 line 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 Containments, Structures, and Component Supports 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 

BWR Concrete and Steel (Mark I, II, and III) 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 

below-grade 

concrete and 

periodic monitoring 

of groundwater if 

environment is 

non-aggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive. 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 
Aging Management Review Results 

 3-407 

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: 

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 licensee is to 

ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation. 

Yes Not applicable 

Structures 

Monitoring 

Program 

Not applicable to 

HCGS (See SER 

Section 3.5.2.2.1) 

Consistent with 

GALL Report 

(See SER 

Section 3.5.2.2.1) 

Concrete elements: 

foundation, 

subfoundation 

(3.5.1-3) 

Reduction in 

foundation 

strength, 

cracking, and 

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 licensee is 

to ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation. 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 

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 Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.2.1) 
Aging Management Review Results 

 3-408 

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 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 ASME Section 

XI, Subsection 

IWE and 

10 CFR Part 50, 

Appendix J 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report 

(See SER 

Sections 3.5.2.1.4 

and 3.5.2.1) 

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 Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 

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 Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 

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 

10 CFR 54.21(c) 

Yes TLAA Fatigue is a TLAA 

(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 

10 CFR 54.21(c) 

Yes TLAA Fatigue is a TLAA 

(See SER 

Section 3.5.2.2.1) 

Stainless steel 

penetration sleeves, 

penetration bellows, 

dissimilar metal 

welds 

(3.5.1-10) 

Cracking due to 

SCC 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J and 

additional 

appropriate 

examinations/ 

evaluations for 

bellows assemblies 

and dissimilar 

metal welds. 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.2.1) 
Aging Management Review Results 

 3-409 

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 vent 

line bellows 

(3.5.1-11) 

Cracking due to 

SCC 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J and 

additional 

appropriate 

examination/ 

evaluation for 

bellows assemblies 

and dissimilar 

metal welds. 

Yes Not applicable Not applicable to 

HCGS (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 and 

supplemented to 

detect fine cracks 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.2.1) 

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 and 

supplemented to 

detect fine cracks 

Yes Not applicable Not applicable to 

HCGS (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 

day-inch/yr) 

(NUREG-1557). 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 

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; 

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 Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 
Aging Management Review Results 

 3-410 

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 

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 ASME 

Section XI, 

Subsection 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 TSs 

No 10 CFR Part 50, 

Appendix J and 

TSs 

Consistent with 

GALL Report 

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 ASME 

Section XI, 

Subsection 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 

HCGS (See SER 

Section 3.5.2.1.1) 

Steel elements: 

suppression 

chamber liner 

(interior 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 

HCGS (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 ASME 

Section XI, 

Subsection IWE 

Consistent with 

GALL Report 

Prestressed 

containment: 

tendons and 

anchorage 

components 

(3.5.1-22) 

Loss of material 

due to corrosion 

ISI (IWL) No Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 
Aging Management Review Results 

 3-411 

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: 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 Structures 

Monitoring 

Program 

Fire Protection 

Program 

Consistent with 

GALL Report 

(See SER 

Sections 3.5.2.1.5, 

3.5.2.2.1, and 

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 Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.2.2) 

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 Structures 

Monitoring 

Program 

Protective 

Coating 

Monitoring and 

Maintenance 

Program 

Consistent with 

GALL Report 

(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 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 Not applicable 

Structures 

Monitoring 

Program 

Not applicable to 

HCGS (See SER 

Section 3.5.2.2.2) 
Aging Management Review Results 

 3-412 

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 licensee is to 

ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation. 

Yes Structures 

Monitoring 

Program 

Fire Protection 

Program 

Consistent with 

GALL Report 

(See SER 

Sections 3.5.2.1.6 

and 3.5.2.2.2) 

Groups 1-3, 5-9: 

foundation 

(3.5.1-29) 

Reduction in 

foundation 

strength, 

cracking, and 

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 licensee is to 

ensure proper 

functioning of the 

dewatering system 

through the period 

of extended 

operation. 

Yes Not applicable Not applicable to 

HCGS (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 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 

below-grade 

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 Structures 

Monitoring 

Program 

Buried Non-Steel 

Piping Inspection 

Consistent with 

GALL Report 

(See SER 

Sections 3.5.2.1.8 

and 3.5.2.2.2) 
Aging Management Review Results 

 3-413 

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 Structures 

Monitoring 

Program 

Consistent with 

GALL Report 

(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 

A plant-specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable to 

HCGS (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 

Water-Control 

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 

below-grade 

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 RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”” 

Buried Non-Steel 

Piping Inspection 

Consistent with 

GALL Report 

(See SER 

Section 3.5.2.1.8) 
Aging Management Review Results 

 3-414 

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 

below-grade 

concrete foundation 

(3.5.1-35) 

Loss of material 

(spalling, scaling) 

and cracking due 

to freeze-thaw 

Inspection of 

Water-Control 

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 RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”” 

Consistent with 

GALL Report 

(See SER 

Section 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 

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 Not applicable 

Structures 

Monitoring 

Program and 

RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”” 

Not applicable to 

HCGS (See SER 

Section 3.5.2.2.2) 

Consistent with 

GALL Report 

(See SER 

Section 3.5.2.2.2) 

Group 6: exterior 

above and 

below-grade 

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 RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”” 

Open-Cycle 

Cooling Water 

Program 

Consistent with 

GALL Report 

(See SER 

Sections 3.5.2.1.8 

and 3.5.2.2.2) 

Groups 7, 8: tank 

liners 

(3.5.1-38) 

Cracking due to 

SCC and loss of 

material due to 

pitting and 

crevice corrosion 

A plant-specific 

AMP is to be 

evaluated. 

Yes Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.2.2) 
Aging Management Review Results 

 3-415 

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 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 Structures 

Monitoring 

Program 

Consistent with 

GALL Report 

(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 Structures 

Monitoring 

Program 

Consistent with 

GALL Report 

(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 Not applicable Not applicable to 

HCGS (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 Structures 

Monitoring 

Program 

Masonry Wall 

Program 

Fire Protection 

Program 

Consistent with 

GALL Report 

(See SER 

Section 3.5.2.1.7) 

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 

 3-416 

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 

below-grade 

concrete foundation; 

interior slab 

(3.5.1-45) 

Loss of material 

due to abrasion 

and cavitation 

Inspection of 

Water-Control 

Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance 

No RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”” 

Open-Cycle 

Cooling Water 

Program 

Consistent with 

GALL Report 

(See SER 

Section 3.5.2.1.8) 

Group 5: fuel pool 

liners 

(3.5.1-46) 

Cracking due to 

SCC and loss of 

material due to 

pitting and 

crevice corrosion 

Water Chemistry 

and monitoring of 

spent fuel pool 

water level in 

accordance with 

TSs and leakage 

from the leak 

chase channels 

No Water Chemistry 

and monitoring of 

spent fuel pool 

water level in 

accordance with 

TSs and leakage 

from the leak 

chase channels 

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 or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance. 

If protective 

coatings are relied 

upon to manage 

aging, protective 

coating monitoring 

and maintenance 

provisions should 

be included. 

No RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants”” 

Structures 

Monitoring 

Program 

Consistent with 

GALL Report 

(See SER 

Section 3.2.2.1.4) 

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, 

and seepage 

Inspection of 

Water-Control 

Structures or 

FERC/U.S. Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs 

No RG 1.127, 

“Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” 

Consistent with 

GALL Report 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-49) 

Loss of material 

due to general, 

pitting, and 

crevice corrosion 

Water Chemistry 

and ISI (IWF) 

No Water Chemistry 

and ASME 

Section XI, 

Subsection IWF 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-417 

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 

Open-Cycle 

Cooling Water 

Program, 

Periodic 

Inspection, 

Aboveground 

Steel Tanks, 

Aboveground 

Non-Steel Tanks, 

and Fire 

Protection 

Program

Consistent with 

GALL Report 

(See SER 

Section 3.5.2.1.4) 

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 No ASME 

Section XI, 

Subsection IWF 

Consistent with 

GALL Report 

(See SER 

Section 3.5.2.1.4)

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, and 

fatigue due to 

vibratory and 

cyclic thermal 

loads 

Structures 

Monitoring 

Program 

No Not applicable Not applicable to 

HCGS (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 

Section XI, 

Subsection IWF 

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 

Section XI, 

Subsection IWF 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-418 

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, 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 Not applicable Not applicable to 

BWRs (See SER 

Section 3.5.2.1.1) 

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 ASME 

Section XI, 

Subsection IWF 

Consistent with 

GALL Report 

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, and 

sustained 

vibratory loading 

ISI (IWF) No Not applicable Not applicable to 

HCGS (See SER 

Section 3.5.2.1.1) 

Galvanized steel and 

aluminum support 

members; welds; 

bolted connections; 

support anchorage to 

building structure 

exposed to air – 

indoor uncontrolled 

(3.5.1-58) 

None None No None Consistent with 

GALL Report 

(See SER 

Section 3.5.2.1.9) 

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 containments, structures, and component supports groups followed 

several approaches. One approach, documented in SER Section 3.5.2.1, discusses the staff’s 

review of AMR results for components the applicant indicated are consistent with the GALL 

Report and require no further evaluation. Another approach, documented in SER 

Section 3.5.2.2, discusses the staff’s review of AMR results for components 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, discusses the staff’s review of AMR 
Aging Management Review Results 

 3-419 

results for components 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 

containments, structures, and component supports is documented in SER Section 3.0.3. 

3.5.2.1 AMR Results That Are 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: 

● 10 CFR Part 50, Appendix J 

● ASME Section XI, Subsection IWE 

● ASME Section XI, Subsection IWF 

● One-Time Inspection 

● Periodic Inspection 

● Protective Coating Monitoring and Maintenance Program 

● RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants” 

● Structures Monitoring Program 

● TLAA 

● Water Chemistry 

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: 

● Aboveground Steel Tanks 

● Aboveground Non-Steel Tanks 

● Buried Non-Steel Piping Inspection 

● Fire Protection Program 

● Masonry Wall Program 

● Open-Cycle Cooling Water Program 

In LRA Tables 3.5.2-1 through 3.5.2-13, the applicant summarized AMRs for structures and 

component supports and indicated AMRs claimed to be consistent with the GALL Report. 

For component groups evaluated in the LRA for which the applicant claimed consistency with 

the GALL Report and for which the GALL Report does not recommend further evaluation, the 

staff’s audit and review determined whether the plant-specific components groups were 

bounded by the GALL Report evaluation. 

For each AMR line item, the applicant noted how the information in the tables aligns with the 

information in the GALL Report. The staff reviewed those AMRs with Notes A through E 

indicating how the AMR is consistent with the GALL Report. 
Aging Management Review Results 

 3-420 

Note A indicates that the AMR line 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 line 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 line 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 line items to verify consistency with the GALL 

Report and verified that the identified exceptions to the GALL Report AMPs have been reviewed 

and accepted. The staff also determined whether the applicant’s AMP was consistent with the 

GALL Report AMP and whether the AMR was valid for the site-specific conditions. 

Note C indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the staff verified 

that 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 a different component with the same material, environment, aging effect, and 

AMP as the component under review. The staff reviewed these line items to verify consistency 

with the GALL Report. The staff also determined whether the AMR line 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 line 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 line items to verify 

consistency with the GALL Report. The staff verified whether the AMR line item of the different 

component was applicable to the component under review and verified 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 line item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff audited these line 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 reviewed the LRA to confirm that the applicant: (a) provided a brief description of the 

system, components, materials, and environments; (b) stated that the applicable aging effects 

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the 

structures and structural components and their commodity groups that are subject to an AMR. 

On the basis of its audit and review, the staff determines that, for AMRs not requiring further 

evaluation, as identified in LRA Table 3.5.1, the applicant’s references to the GALL Report are 

acceptable and no further staff review is required, with the exception of the following AMRs that 

the applicant had identified were consistent with the AMRs of the GALL Report and for which 

the staff determined were in need of additional clarification and assessment. The staff’s 

evaluations of these AMRs are provided in the subsections that follow. 
Aging Management Review Results 

 3-421 

LRA Tables 3.5.2-1, 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-5, 3.5.2-7, 3.5.2-8, 3.5.2-9, 3.5.2-11, 

3.5.2-12, and 3.5.2-13 were revised as a result of the response to RAI B.2.1.12-01, dated 

June 14, 2010. The revision added AMR items in these tables to reference the applicant’s 

Bolting Integrity Program to manage the aging for bolting AMR items. Existing bolting AMR 

items which reference other AMPs are used in conjunction with the added bolting AMR items to 

properly manage aging for bolting components. The staff’s evaluation of the applicant’s Bolting 

Integrity Program is documented in SER Section 3.0.3.2.4. The staff notes that the Bolting 

Integrity Program is supplemented by other AMPs including but not limited to: the Structures 

Monitoring, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems, External Surfaces Monitoring, and Buried Piping Inspection programs. These other 

AMPs supplement the Bolting Integrity Program by implementing the requirements of the Bolting 

Integrity Program for pressure retaining bolted joints, component support bolting, and structural 

bolting within the scope of license renewal. The applicant’s action revised the LRA to add 

bolting component items in the tables mentioned above that are consistent with the GALL 

Report and have designated them as such with generic note B. 

3.5.2.1.1 AMR Results Identified as Not Applicable 

In LRA Table 3.5.1, items 3.5.1-1, 3.5.1-3, 3.5.1-6, 3.5.1-7, 3.5.1-14, 3.5.1-15, 3.5.1-19, 

3.5.1-20, 3.5.1-22, and 3.5.1-55, the applicant stated that the corresponding AMR items in the 

GALL Report are not applicable to HCGS because HCGS is a BWR design that incorporates a 

Mark I steel containment and the AMR items in the GALL Report are only applicable to 

particular components of BWR or PWR designs that use a concrete containment or containment 

designs that use a post-tensioning system. The staff verified that the stated AMR items in the 

GALL Report are only applicable to concrete components of PWR designs or post-tensioned 

concrete containments and are not applicable to HCGS. 

In LRA Table 3.5.1, items 3.5.1-52 and 3.5.1-57, the applicant stated that the corresponding 

AMR items in the GALL Report are not applicable since the component, material, environment, 

and aging effect or mechanism does not apply for HCGS. For each of these line items, the staff 

reviewed the LRA and UFSAR supplement and confirmed the applicant’s claim that the 

component, material, environment, and aging effect or mechanism does not apply for HCGS. 

Since HCGS does not have the component, material, environment, and aging effect or 

mechanism for these Table 1 line items, the staff finds that these AMRs are not applicable to 

HCGS. 

The remaining items identified as not applicable require further evaluation and are discussed in 

the corresponding subsections of SER Section 3.5.2.2. 

3.5.2.1.2 Loss of Preload Due to Self-Loosening 

In the LRA Table 3.5.2-1 through 3.5.2-5, 3.5.2-7, 3.5.2-8, 3.5.2-11, and 3.5.2-12 line items that 

reference Table 3.3-1, item 3.3.1-45, and LRA Table 3.5.2-7 line items that reference 

Table 3.1-1, item 3.1.1-52, the applicant included a reference to Note E and credits the 

Structures Monitoring Program for managing this aging effect or mechanism in an air – indoor 

environment for carbon and low alloy steel bolting, galvanized steel bolting, and stainless steel 

bolting. The applicant also included either plant-specific Notes 1, 2, 3, or 5. Plant-specific 

Note 1 (Tables 3.5.2-1, 3.5.2-2, 3.5.2-3, 3.5.2-5, 3.5.2-8, 3.5.2-11, and 3.5.2-12), plant-specific 

Note 3 (Table 3.5.2-4), and plant-specific Note 2 (Table 3.5.2-7) each state: 
Aging Management Review Results 

 3-422 

Based on industry standards and operating experience[,] age related loss of 

preload/self-loosening of structural bolting could be caused by vibration, flexing 

of the joint or cyclic shear loads that could occur in any environment. However, 

these causes are considered in the design of structural connections and 

eliminated by the initial preload bolt torquing. Thus, loss of 

preload/self-loosening of structural bolting is not significant and will not impact 

structural intended functions. Nevertheless, loss of preload/self-loosening will be 

monitored through the Structures Monitoring Program. 

Plant-specific Note 5 (Table 3.5.2-4) and plant-specific Note 3 (Table 3.5.2-7) each state that, 

“[The] Structures Monitoring Program is [an] applicable aging management program for this 

component.” 

The applicant stated that components have been aligned to this item number based on material, 

environment, and aging effect. 

The staff reviewed the AMR results lines that reference Note E and plant-specific Notes 1, 2, 3, 

or 5. The staff determined, for these items, that the component type, material, environment, and 

aging effect are consistent with the corresponding line of the GALL Report; however, where the 

GALL Report recommends GALL AMP XI.M18, “Bolting Integrity,” the applicant proposed using 

the Structures Monitoring Program. 

The LRA states that these components have the intended function of structural support and are 

examined using the Structures Monitoring Program as the primary AMP. The staff’s review of 

the Structures Monitoring Program is documented in SER Section 3.0.3.2.16. The staff finds 

the applicant’s use of the Structures Monitoring Program acceptable because the program: 

(1) monitors exposed surfaces of bolting for loss of material due to corrosion, loose nuts, 

missing bolts, or other indications of loss of preload; and (2) incorporates procedures based on 

EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide,” to ensure proper 

specification of bolting material, lubricant, and installation torque. The staff finds that the 

applicant addressed the AERM adequately. 

In the LRA Table 3.5.2-4 line items that reference Table 3.3-1, item 3.3.1-45, the applicant 

included a reference to Note E and credits the ASME Section XI, Subsection IWF Program for 

managing this aging effect or mechanism in an air – indoor environment for high-strength low 

alloy steel bolting with yield strength greater than 150 ksi, carbon and low alloy steel bolting, 

and galvanized steel bolting. The applicant also included plant-specific Notes 1, 2, and 3 for the 

high-strength low alloy steel bolting and plant-specific Notes 1 and 3 for the carbon and low 

alloy steel bolting and galvanized steel bolting. Plant-specific Note 1 states, “ASME Section XI, 

Subsection IWF is the applicable aging management program for this component.” 

Plant-specific Note 2 states: 

NSSS Class 1 component supports (reactor pressure vessel support) utilize high 

strength ASTM A490 bolts (actual yield strength could be greater than or equal 

[to] 150 ksi). The bolts are not subject to high-sustained preload stress, 

aggressive environment, and lubricants containing contaminants not approved 

for use. Additionally ASTM A490 bolts have high resistance to stress corrosion 

cracking due to their ductility and industry and plant specific operating experience 

have not identified stress corrosion cracking of ASTM A490 bolts as a concern. 

Therefore cracking due to stress corrosion cracking is not an aging effect 

requiring management. Loss of material is the only aging effect requiring aging 
Aging Management Review Results 

 3-423 

management. They are monitored for loss of material due to corrosion and loss 

of preload by visual inspection using ASME Section XI, Subsection IWF. 

Plant-specific Note 3 states: 

Based on industry standards and operating experience[,] age related loss of 

preload/self-loosening of structural bolting could be caused by vibration, flexing 

of the joint or cyclic shear loads that could occur in any environment. However, 

these causes are considered in the design of structural connections and 

eliminated by the initial preload bolt torquing. Thus, loss of 

preload/self-loosening of structural bolting is not significant and will not impact 

structural intended functions. Nevertheless, loss of preload/self-loosening will be 

monitored through the applicable aging management program. 

The applicant stated that components have been aligned to this item number based on material, 

environment, and aging effect. 

The staff reviewed the AMR results lines that reference Note E and plant-specific Notes 1, 2, 

and 3. The staff determined, for these items, that the component type, material, environment, 

and aging effect are consistent with the corresponding line of the GALL Report; however, where 

the GALL Report recommends GALL AMP XI.M18, “Bolting Integrity,” the applicant proposed 

using the ASME Section XI, Subsection IWF Program. 

The LRA states that these components have the intended function of structural support and are 

examined using the ASME Section XI, Subsection IWF Program as the primary AMP. The 

staff’s review of the ASME Section XI, Subsection IWF Program is documented in SER 

Section 3.0.3.1.15. The staff finds the applicant’s use of the ASME Section XI, Subsection IWF 

Program acceptable because the program: (1) provides periodic visual examinations of ASME 

Code Section XI Class 1, 2, 3, and MC piping and component support members for loss of 

material and loss of mechanical function, including inspection of bolting for supports for loss of 

material and for loss of preload by inspecting for missing, detached, or loosened bolts and nuts; 

and (2) relies on design change procedures that are based on EPRI TR-104213 guidance to 

ensure proper specification of bolting material, lubricant, and installation torque. The staff finds 

that the applicant addressed the AERM adequately. 

In the LRA Table 3.5.2-9 line items that reference Table 3.3-1, item 3.3.1-45, the applicant 

included a reference to Note E and credits the RG 1.127, “Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program” for managing this aging effect or 

mechanism in an air – indoor environment for carbon and low alloy steel bolting and galvanized 

bolting. The applicant also included plant-specific Note 1 which states: 

Based on industry standards and operating experience[,] age related loss of 

preload/self-loosening of structural bolting could be caused by vibration, flexing 

of the joint or cyclic shear loads that could occur in any environment. However, 

these causes are considered in the design of structural connections and 

eliminated by the initial preload bolt torquing. Thus, loss of 

preload/self-loosening of structural bolting is not significant and will not impact 

structural intended functions. Never the less, loss of preload/self-loosening will 

be monitored through the RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” aging management program. 

The applicant stated that components have been aligned to this item number based on material, 

environment, and aging effect. 
Aging Management Review Results 

 3-424 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 1. The 

staff determined, for these items, that the component type, material, environment, and aging 

effect are consistent with the corresponding line of the GALL Report; however, where the GALL 

Report recommends GALL AMP XI.M18, “Bolting Integrity,” the applicant proposed using the 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” 

Program. 

The LRA states that these components have the intended function of structural support and the 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program” has been substituted to manage loss of preload due to self-loosening in steel bolting 

of the service water intake structure exposed to indoor air. The staff’s review of the applicant’s 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program” is documented in SER Section 3.0.3.2.17. The staff finds the applicant’s use of the 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” 

Program acceptable because the program: (1) is based on guidance provided in RG 1.127 and 

ACI 349.3R, (2) is implemented through the Structures Monitoring Program, and (3) addresses 

age-related deterioration of water control structures with respect to loss of material and loss of 

preload for steel and metal components. The staff finds that the applicant addressed the AERM 

adequately. 

In the LRA Table 3.5.2-7 line items that reference Table 3.2-1, item 3.2.1-24, the applicant 

included a reference to Note E and credits the ASME Section XI, Subsection IWE and 

10 CFR Part 50, Appendix J programs for managing this aging effect or mechanism in an air – 

indoor environment for carbon and low alloy steel bolting. The applicant also included 

plant-specific Note 1 which states, “ASME Section XI, Subsection IWE and 10 CFR Part 50, 

Appendix J are the applicable aging management program[s] for this component.” The 

applicant stated that components have been aligned to this item number based on material, 

environment, and aging effect. 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 1. The 

staff determined, for these items, that the component type, material, environment, and aging 

effect are consistent with the corresponding line of the GALL Report; however, where the GALL 

Report recommends GALL AMP XI.M18, “Bolting Integrity,” the applicant proposed using the 

ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs. 

The LRA states that these components have the intended function of pressure boundary or 

structural support and that the 10 CFR Part 50, Appendix J and ASME Section XI, Subsection 

IWE programs have been substituted to manage loss of preload due to self-loosening in steel 

bolting exposed to indoor air. The staff’s reviews of the applicant’s 10 CFR Part 50, Appendix J 

and ASME Section XI, Subsection IWE programs are documented in SER Sections 3.0.3.1.16 

and 3.0.3.2.14, respectively. The staff finds the applicant’s use of the 10 CFR Part 50, 

Appendix J and ASME Section XI, Subsection IWE programs acceptable because: (1) the 

10 CFR Part 50, Appendix J Program provides for detection of age-related degradation of 

components comprising the containment pressure boundary due to aging effects such as loss of 

leak tightness, loss of material, cracking, loss of sealing, or loss of preload in various systems 

penetrating containment; and (2) the ASME Section XI, Subsection IWE Program conducts 

visual examinations (general visual and VT-3) and augmented inspections (VT-1) for evidence 

of aging effects that could affect leak tightness of the primary containment structure and 

includes the pressure-retaining bolting. The staff finds that the applicant addressed the AERM 

adequately. 
Aging Management Review Results 

 3-425 

3.5.2.1.3 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

In the LRA Table 3.5.2-9 and 3.5.2-10 line items that reference Table 3.3-1, item 3.3.1-19, the 

applicant included a reference to Note E and credited the RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants” Program for managing this 

aging effect or mechanism in a groundwater or soil environment for carbon steel piles or sheet 

piles. The applicant also included plant-specific Notes 2 or 4 (depending on the table number) 

which each state, “RG 1.127, ‘Inspection of Water-Control Structures Associated with Nuclear 

Power Plants’ is [the] applicable aging management program for this component.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Notes 2 or 4. 

The staff determined, for these items, that the material and aging effect are consistent with the 

corresponding line of the GALL Report; however, where the GALL Report recommends GALL 

AMP XI.M28, “Buried Piping and Tanks Surveillance,” or GALL AMP XI.M34, “Buried Piping and 

Tanks Inspection,” the applicant proposed using the RG 1.127, “Inspection of Water-Control 

Structures Associated with Nuclear Power Plants” Program. 

The LRA states that these components have the intended functions of structural support or 

shelter and protection in the form of carbon steel piles or carbon steel sheet piles and are 

examined using the RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear 

Power Plants” Program. The staff’s review of the applicant’s RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants” Program is documented in 

SER Section 3.0.3.2.17. GALL AMP XI.M28 applies to buried piping and tanks and includes 

surveillance measures to mitigate corrosion by protecting the external surface of buried carbon 

steel piping and tanks. GALL AMP XI.M34 also applies to buried piping and tanks and includes 

preventive measures to mitigate corrosion and periodic inspection to manage the effects of 

corrosion on the pressure retaining capacity of buried steel piping and tanks. The LRA also 

states that the carbon steel piles are located below foundations possibly making them 

inaccessible. However, the LRA states that degradation of piles will manifest in settlement 

distortion or cracking of concrete, and accessible concrete examinations will detect cracks and 

distortion of the structures. The LRA further states that studies have shown that steel piles 

driven into undisturbed natural soil are not appreciably affected by corrosion due to the oxygen 

deficiency in soil at a few feet below grade, piles driven into disturbed soil have been shown to 

experience only minor to moderate corrosion, and in either case, the observed loss of material 

due to corrosion was not considered significant enough to impact the intended function of the 

piles, which is consistent with NUREG-1557. In the LRA, the applicant further stated that the 

carbon steel sheet piles are one of the components in the shoreline protection and dike 

structures that provide protection against shoreline recession for the service water system SCs 

during and following design seismic and flood events. The staff finds the applicant’s use of RG 

1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” Program 

acceptable because: (1) the program is implemented under the Structures Monitoring Program 

and is based on guidance provided in RG 1.127 and ACI 349.3R; (2) the program includes 

provisions for examination of reinforced concrete members, structural steel, and earthen 

water-control structures of the service water structure and shoreline protection and dike 

structures; and (3) examinations of and accessible concrete will detect cracks and distortion of 

the structures due to settlement distortion or concrete cracking that would result from 

degradation of the piles. The staff finds that the applicant addressed the AERM adequately. 

In the LRA Table 3.5.2-9 line items that reference Table 3.3-1, item 3.3.1-19, the applicant 

included a reference to Note E and credited the RG 1.127, “Inspection of Water-Control 
Aging Management Review Results 

 3-426 

Structures Associated with Nuclear Power Plants” Program for managing this aging effect or 

mechanism in a groundwater or soil environment for carbon steel and galvanized steel 

penetration sleeves in the service water intake structure. The applicant also included 

plant-specific Note 4 which states, RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” is the applicable aging management program for this 

component.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 4. The 

staff determined, for these items, that the material and aging effect are consistent with the 

corresponding line of the GALL Report; however, where the GALL Report recommends GALL 

AMP XI.M28, “Buried Piping and Tanks Surveillance,” or GALL AMP XI.M34, “Buried Piping and 

Tanks Inspection,” the applicant proposed using the RG 1.127, “Inspection of Water-Control 

Structures Associated with Nuclear Power Plants” Program. 

The LRA states that the carbon steel or galvanized steel penetration sleeves have the intended 

function of structural support or flood barrier and are examined using the RG 1.127, “Inspection 

of Water-Control Structures Associated with Nuclear Power Plants” Program. The staff’s review 

of the RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” 

Program is documented in SER Section 3.0.3.2.17. GALL AMP XI.M28 applies to buried piping 

and tanks and includes surveillance measures to mitigate corrosion by protecting the external 

surface of buried carbon steel piping and tanks. GALL AMP XI.M34 also applies to buried 

piping and tanks and includes preventive measures to mitigate corrosion and periodic inspection 

to manage the effects of corrosion on the pressure retaining capacity of buried steel piping and 

tanks. Due to potential accessibility constraints associated with the penetration sleeves being 

located in a groundwater or soil environment, the staff is unclear how the RG 1.127, “Inspection 

of Water-Control Structures Associated with Nuclear Power Plants” Program, which is primarily 

a visual-based program, will be used to address the structure and aging effect combinations 

during the period of extended operation. By letter dated June 7, 2010, the staff issued 

RAI 3.5.2.1-2 to address this issue. 

By letter dated June 29, 2010, the applicant explained that the penetration sleeves discussed 

above were aligned to GALL Report item 3.3.1-19 to show agreement between the LRA and the 

GALL Report with respect to the identified aging effects and mechanisms for the material and 

environment combination; the alignment was not intended to suggest consistency with the AMP 

recommended by the GALL Report. The applicant further explained that the recommended 

GALL Report programs are not applicable for aging management of the penetration sleeves 

because the recommended programs are specifically applicable to buried piping and buried 

tanks. These programs do not include activities that will effectively manage aging effects of 

penetration sleeve components to assure the associated structural intended functions are 

maintained. The applicant explained that the penetration sleeves are installed in concrete walls 

and the majority of the sleeve is located within the wall, while a small portion may protrude past 

the wall surface and into a soil environment. The applicant also explained that most of the 

sleeve is protected on both the outer and inner surface by concrete, grout, or elastomer seal 

material. The applicant explained the RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” Program, implemented under the Structures Monitoring 

Program, is the appropriate program to manage these components, and it includes inspections 

of the penetration seals and the associated sleeves on a 5-year interval. These inspections will 

detect material degradation or indications of seal leakage prior to loss of intended function. 

The staff reviewed the applicant’s response and noted that the penetration sleeves are 

structural components embedded in concrete. Visual inspections from the indoor side of the 
Aging Management Review Results 

 3-427 

wall, on a 5-year frequency, should be able to detect degradation prior to a loss of intended 

function. Based on its review, the staff finds the applicant’s aging management approach 

acceptable because the RG 1.127, “Inspection of Water-Control Structures Program includes 

appropriate inspections to detect degradation of the penetration sleeves prior to loss of intended 

function. The staff finds that the applicant addressed the AERM adequately and the staff’s 

concern in RAI 3.5.2.1-2 is resolved. 

In the LRA Table 3.5.2-4, 3.5.2-7, and 3.5.2-8 line items that reference Table 3.5-1, 

item 3.5.1-47, the applicant included a reference to Note E and credited the Structures 

Monitoring Program for managing this aging effect or mechanism for carbon steel in a raw water 

or flowing water environment. The applicant also included either plant-specific Notes 2, 3, or 5 

(depending on the table number) which each state, “[The] Structures Monitoring Program is the 

applicable aging management program for this component.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Notes 2, 3, 

and 5. The staff determined, for these items, that the material, aging effect, and environment 

are consistent with the corresponding line of the GALL Report; however, where the GALL 

Report recommends GALL AMP XI.S7, RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” or the FERC/U.S. Army Corps of Engineers dam 

inspections and maintenance program, the applicant proposed using the Structures Monitoring 

Program. 

The LRA states that the carbon steel supports for cable trays, conduit, HVAC ducts, tube track, 

instrument tubing, and non-ASME piping and components (support members, welds, bolted 

connections, support anchorages to building structure) and the sump liners have intended 

functions of either structural support or water retaining boundary and are examined using the 

Structures Monitoring Program. The staff’s review of the Structures Monitoring Program is 

documented in SER Section 3.0.3.2.16. The staff finds the applicant’s use of the Structures 

Monitoring Program acceptable because the program: (1) performs visual inspections to monitor 

for indications of degradation such as loss of material, (2) includes water-control structures 

within its scope, (3) implements the guidance of GALL AMP XI.S7, and (4) has been enhanced 

to conduct the visual inspections on a frequency not to exceed 5 years. The staff finds that the 

applicant addressed the AERM adequately. 

In the LRA Table 3.5.2-7 line items that reference Table 3.5-1, item 3.5.1-5, the applicant 

included a reference to Note E and credited the Structures Monitoring Program for managing 

this aging effect or mechanism for miscellaneous carbon steel components (catwalks, stairs, 

handrails, ladders, platforms, etc.) in a treated water environment. The applicant also included 

plant-specific Note 3 which states, “[The] Structures Monitoring Program is the applicable aging 

management program for this component.” 

The staff reviewed the AMR lines that reference Note E and plant-specific Note 3. The staff 

determined, for these items, that the material, aging effect, and environment are consistent with 

the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.S1, “ASME Section XI, Subsection IWE,” the applicant proposed using the 

Structures Monitoring Program. 

The LRA states that the carbon steel components have an intended function of structural 

support and are examined using the Structures Monitoring Program. The staff’s review of the 

Structures Monitoring Program is documented in SER Section 3.0.3.2.16. GALL AMP XI.S1 is 

intended to address Class MC pressure retaining components of steel containments and their 
Aging Management Review Results 

 3-428 

integral attachments; metallic shell and penetration liners of Class CC (concrete containment) 

and their integral attachments; containment seals and gaskets; containment pressure retaining 

bolting; and metal containment surface areas, including welds and base metal. The staff finds 

the applicant’s use of the Structures Monitoring Program acceptable because: (1) the carbon 

steel components are not part of the pressure retaining boundary, (2) the program performs 

visual inspections to monitor for indications of degradation such as loss of material, and (3) the 

program has been enhanced to conduct the visual inspections on a frequency not to exceed 

5 years. The staff finds that the applicant addressed the AERM adequately. 

In several LRA line items that reference Table 3.5-1, item 3.5.1-50, the applicant included a 

reference to Note E and credited the Periodic Inspection Program for managing loss of material 

due to general, pitting, and crevice corrosion in an air – outdoor environment for aluminum and 

stainless steel components. 

The staff reviewed the AMR results lines that reference Note E. The staff determined, for these 

items, that the material, aging effect, and environment are consistent with the corresponding line 

of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, 

“Structures Monitoring,” the applicant proposed using the Periodic Inspection Program. 

The LRA states that the Periodic Inspection Program is a condition monitoring program that 

manages aging of piping, piping components, piping elements, ducting components, tanks, and 

heat exchanger components, and includes provisions for periodic visual inspections of 

aluminum components to detect loss of material aging effects. The staff’s review of the 

applicant’s Periodic Inspection Program is documented in SER Section 3.0.3.3.2. The LRA also 

states that the visual inspections are conducted on a 10-year inspection frequency that has 

been established based on plant and industry operating experience. It is not clear to the staff 

that the scope of the applicant’s Periodic Inspection Program includes all the components which 

credit it for management in the LRA. In addition, for components located in an air – outdoor 

environment, the program does not meet guidance such as provided in ACI 349.3R as 

referenced by GALL AMP XI.S6, which recommends an inspection frequency of 5 years. By 

letter dated June 7, 2010, the staff issued RAI 3.5.2.1-3 to address these issues. 

By letter dated June 29, 2010, the applicant explained that the components referenced in 

RAI 3.5.2.1-3 were aligned to GALL Report item 3.5.1-50 to show agreement between the LRA 

and the GALL Report with respect to the identified aging effects and mechanisms for the 

material and environment combination; the alignment was not intended to suggest consistency 

with the AMP recommended by the GALL Report. The applicant explained that the 

recommended GALL Report program is not applicable for aging management of the mechanical 

piping system components. The program does not include appropriate activities for effectively 

managing the aging effects of mechanical piping system components. The applicant further 

explained that the Periodic Inspection Program is the appropriate program to manage aging of 

these components, and the program includes all the referenced items within its scope. The 

applicant further explained that the 10-year inspection frequency is appropriate for stainless 

steel and aluminum components exposed to outdoor air due to the corrosion resistance of the 

materials. The applicant explained that this conclusion was supported by plant-specific 

operating experience, including inspections of outdoor stainless steel piping in 2005 and 2007 

which showed no signs of age-related degradation. These inspections suggest little to no 

age-related degradation after 20 years in service. 

The staff reviewed the applicant’s response and noted that all of the AMR line items in question 

are included within the scope of the applicant’s Periodic Inspection Program. The staff also 
Aging Management Review Results 

 3-429 

noted that the applicant provided justification for the 10-year inspection interval, based on 

plant-specific operating experience. Based on its review, the staff finds the applicant’s use of 

the Periodic Inspection Program acceptable because it includes appropriate visual inspections 

at an appropriate frequency to detect degradation of aluminum and stainless steel components 

prior to a loss of intended function. The staff finds that the applicant addressed the AERM 

adequately and the staff’s concern in RAI 3.5.2.1-3 is resolved. 

In the LRA Table 3.3.2-10 line items that reference Table 3.5-1, item 3.5.1-50, the applicant 

included a reference to Note E and credited the Aboveground Steel Tanks Program for 

managing loss of material due to general, pitting, and crevice corrosion in an air – outdoor 

environment for stainless steel fire water storage tank heaters. 

The staff reviewed the AMR results lines that reference Note E. The staff determined, for these 

items, that the material, aging effect, and environment are consistent with the corresponding line 

of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, 

“Structures Monitoring,” the applicant proposed using the Aboveground Steel Tanks Program. 

The staff’s review of the applicant’s Aboveground Steel Tanks Program is documented in SER 

Section 3.0.3.2.9. It is unclear to the staff how the Aboveground Steel Tanks Program meets or 

exceeds the inspection requirements discussed in the GALL Report recommended program and 

how the applicant’s credited program will be used to manage loss of material of the stainless 

steel fire water storage tank heaters. By letter dated June 7, 2010, the staff issued 

RAI 3.5.2.1-4 to address these issues. 

The applicant responded by letter dated June 29, 2010, and explained that the fire water 

storage tank stainless steel electric heaters are active components and do not serve a passive 

intended function such as a pressure boundary. The applicant further explained that since the 

components are considered active, they are not subject to an AMR and they should not have 

been included in LRA Table 3.3.2-10. The applicant revised the LRA accordingly. 

The staff reviewed the applicant’s response and found it acceptable because the applicant 

considers the electric heaters active components without a passive intended function. 

Therefore, the components should have been “screened out” and should not have been subject 

to an AMR or included in LRA Table 3.3.2-10. The staff’s concern in RAI 3.5.2.1-4 is resolved. 

In the LRA Table 3.3.2-10 line items that reference Table 3.5-1, item 3.5.1-50, the applicant 

included a reference to Note E and credited the Fire Protection Program for managing loss of 

material due to general, pitting, and crevice corrosion in an air – outdoor environment for 

aluminum bird screens on the fire water tank vents. 

The staff reviewed the AMR lines that reference Note E. The staff determined, for these items, 

that the material, aging effect, and environment are consistent with the corresponding line of the 

GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, “Structures 

Monitoring,” the applicant proposed using the Fire Protection Program. 

The staff’s review of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.7. It is unclear to the staff how the Fire Protection Program meets or exceeds 

the inspection requirements discussed in the GALL Report recommended program and how the 

applicant’s credited program will be used to manage loss of material of the aluminum bird 

screens on the fire water tank vents. By letter dated June 7, 2010, the staff issued 

RAI 3.5.2.1-5 to address these issues. 
Aging Management Review Results 

 3-430 

The applicant responded by letter dated June 29, 2010, and explained that the aluminum bird 

screens in question are located on the roof vent pipe of the fire water storage tanks. The 

applicant further explained that the fire water storage tanks are within the scope of license 

renewal because they are relied upon to perform a function that demonstrates compliance with 

the NRC Fire Protection regulations; however, the aluminum bird screens are not relied upon to 

perform an intended function to demonstrate compliance with the regulations. Age-related 

degradation of the screens cannot prevent air flow through the vent pipe and will not impact the 

intended function of the fire water storage tank. Since the components do not have intended 

functions for license renewal, the applicant explained that they are not within the scope of 

license renewal and should not have been included in LRA Table 3.3.2-10. The applicant 

revised the LRA accordingly. 

The staff reviewed the applicant’s response and found it acceptable because it explained that 

degradation of the bird screens would not impact the intended function of the fire water storage 

tanks. The staff notes that loss of material due to corrosion of the bird screens would not impact 

the function of the vent pipe or the fire water storage tanks. Therefore, the staff finds that the 

components should not have been within the scope of license renewal and should not have 

been subject to an AMR or included in LRA Table 3.3.2-10. The staff’s concern in RAI 3.5.2.1-5 

is resolved. 

In the LRA Table 3.4.2-1 line items that reference Table 3.5-1, item 3.5.1-50, the applicant 

included a reference to Note E and credited the Aboveground Non-Steel Tanks Program for 

managing loss of material due to general, pitting, and crevice corrosion in an air – outdoor 

environment for stainless steel components. 

The staff reviewed the AMR lines that reference Note E. The staff determined, for these items, 

that the material, aging effect, and environment are consistent with the corresponding line of the 

GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, “Structures 

Monitoring,” the applicant proposed using the Aboveground Non-Steel Tanks Program. 

The staff’s review of the applicant’s Aboveground Non-Steel Tanks Program is documented in 

SER Section 3.0.3.3.3. The staff noted that the Aboveground Non-Steel Tanks Program 

performs visual inspections to monitor for indications of degradation at a frequency of five 

5 years or less. The GALL Report program recommends visual inspections at a frequency of 

5 years or less for components exposed to an exterior environment. Since the applicant’s 

credited program performs inspections which are equivalent to the GALL Report recommended 

program, the staff finds the applicant’s use of the Aboveground Non-Steel Tanks Program 

acceptable. The staff finds that the applicant addressed the AERM adequately. 

In the LRA Table 3.3.2-27 line items that reference Table 3.5-1, item 3.5.1-50, the applicant 

included a reference to Note E and credited the Open-Cycle Cooling Water System Program for 

managing loss of material due to general, pitting, and crevice corrosion in an air – outdoor 

environment for stainless steel components. 

The staff reviewed the AMR results lines that reference Note E. The staff determined, for these 

items, that the material, aging effect, and environment are consistent with the corresponding line 

of the GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, 

“Structures Monitoring,” the applicant has proposed using the Open-Cycle Cooling Water 

System Program. 
Aging Management Review Results 

 3-431 

The staff’s review of the applicant’s Open-Cycle Cooling Water System Program is documented 

in SER Section 3.0.3.1.9. The Open-Cycle Cooling Water System Program is an existing 

program that manages the internal corrosion of piping. It is unclear to the staff how the 

Open-Cycle Cooling Water System Program meets or exceeds the inspection requirements 

discussed in the GALL Report recommended program and how the applicant’s credited program 

will be used to manage loss of material of the external surfaces of the stainless steel 

components. By letter dated June 25, 2010, the staff issued RAI 3.5.2.1-7 to address these 

issues. 

The applicant responded by letter dated July 20, 2010, and explained that the components 

referenced in RAI 3.5.2.1-7 were aligned to GALL Report item 3.5.1-50 to show agreement 

between the LRA and the GALL Report with respect to the identified aging effects and 

mechanisms for the material and environment combination; the alignment was not intended to 

suggest consistency with the AMP recommended by the GALL Report. The applicant explained 

that the recommended GALL Report program is not applicable for aging management of 

stainless steel pump casings or rupture disks. The program does not include appropriate 

activities for effectively managing the aging effects of the components. The applicant further 

explained that the Open-Cycle Cooling Water System Program includes component preventive 

maintenance activities which include condition monitoring that would detect loss of material on 

both internal and external surfaces. The applicant stated that these periodic maintenance 

activities will detect possible degradation prior to a loss of intended function. 

The staff reviewed the applicant’s response and found it acceptable because the applicant 

explained how preventive maintenance activities credited by the program can detect 

degradation due to loss of material. The preventive maintenance activities include visual 

inspections of the components for indications of loss of material. These inspections are 

equivalent to the guidance provided in the GALL Report recommended program. Since the 

applicant is inspecting the internal and external surfaces of the components for loss of material, 

the staff finds the applicant’s aging management approach acceptable, and the staff’s concern 

in RAI 3.5.2.1-7 is resolved. 

In the LRA Table 3.5.2-7 line items that reference Table 3.2-1, item 3.2.1-23, the applicant 

included a reference to Note E and credited the ASME Section XI, Subsection IWE Program for 

managing this aging effect or mechanism for carbon and low alloy steel containment closure 

bolting in an air – indoor environment. The applicant also included plant-specific Note 1 which 

states, “ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J are the applicable 

aging management program for this component.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 1. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.M18, “Bolting Integrity,” the applicant proposed using the ASME Section XI, 

Subsection IWE Program. 

The LRA states that these components have the intended function either of pressure boundary 

or structural support and are examined using the ASME Section XI, Subsection IWE Program 

as the primary AMP. In the LRA, the plant-specific note also states that the 10 CFR Part 50, 

Appendix J Program is also applicable to this component. The staff’s reviews of the ASME 

Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs are documented in SER 

Sections 3.0.3.2.14 and 3.0.3.1.16, respectively. The staff finds the applicant’s use of the 

ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs acceptable 
Aging Management Review Results 

 3-432 

because: (1) the ASME Section XI, Subsection IWE Program conducts general and detailed 

visual examinations and augmented inspections for evidence of aging effects that could affect 

leak tightness of the containment structure, including the pressure retaining components 

(includes bolting) and their integral attachments; and (2) the 10 CFR Part 50, Appendix J 

Program provides for detection of age-related degradation of components comprising the 

containment pressure boundary. The staff finds that the applicant addressed the AERM 

adequately. 

In the LRA Table 3.5.2-4 line items that reference Table 3.5-1, item 3.5.1-51, the applicant 

included a reference to Note E and credited the ASME Section XI, Subsection IWF Program for 

managing this aging effect or mechanism in an air – indoor environment for high-strength low 

alloy steel bolting with a yield strength greater than 150 ksi and having an intended function of 

structural support for Class 1 piping and components (high-strength bolting for NSSS 

component supports). The applicant also included plant-specific Notes 1 and 2. Plant-specific 

Note 1 states, “ASME Section XI, Subsection IWF is the applicable aging management program 

for this component.” 

Plant-specific Note 2 states: 

NSSS Class 1 component supports (reactor pressure vessel support) utilize high 

strength ASTM A490 bolts (actual yield strength could be greater than or equal to 

150 ksi). The bolts are not subject to high-sustained preload stress, aggressive 

environment, and lubricants containing contaminants not approved for use. 

Additionally ASTM A490 bolts have high resistance to stress corrosion cracking 

due to their ductility and industry and plant specific operating experience have 

not identified stress corrosion cracking of ASTM A490 bolts as a concern. 

Therefore cracking due to stress corrosion cracking is not an aging effect 

requiring aging management. Loss of material is the only aging effect requiring 

aging management. They are monitored for loss of material due to corrosion and 

loss of preload by visual inspection using the ASME Section XI, Subsection IWF. 

The staff reviewed the AMR results lines that reference Note E and plant-specific Notes 1 and 2. 

The staff determined, for these items, that the material, aging effect, and environment are 

consistent with the corresponding line of the GALL Report; however, where the GALL Report 

recommends GALL AMP XI.M18, “Bolting Integrity,” the applicant proposed using the ASME 

Section XI, Subsection IWF Program. 

The LRA states that these components have the intended function of structural support and are 

examined using the ASME Section XI, Subsection IWF Program as the primary AMP. The 

staff’s review of the ASME Section XI, Subsection IWF Program is documented in SER 

Section 3.0.3.1.15. The staff finds the applicant’s use of the ASME Section XI, Subsection IWF 

Program acceptable because: (1) the program performs periodic visual examinations of 

exposed surfaces of bolting used in supports for loss of material and for loss of preload by 

inspecting for missing, detached, or loosened bolts and nuts, including monitoring for loss of 

material due to general corrosion of high-strength bolts (actual yield strength greater than 

150 ksi); (2) the bolts are in an air – indoor noncorrosive environment; (3) the bolts are not 

preloaded to a high stress level; and (4) the program incorporates procedures based on EPRI 

TR-104213, “Bolted Joint Maintenance and Applications Guide,” to ensure proper specification 

of bolting material, lubricant, and installation torque. The staff finds that the applicant addressed 

the AERM adequately. 
Aging Management Review Results 

 3-433 

In the LRA Table 3.5.2-7 line items that reference Table 3.3-1, item 3.3.1-58, the applicant 

included a reference to Note E and credited the Structures Monitoring Program for managing 

this aging effect or mechanism in an air – indoor environment. The applicant also included 

plant-specific Note 3 which states, “[The] Structures Monitoring Program is the applicable aging 

management program for this component.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 1. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.M36, “External Surfaces Monitoring,” the applicant proposed using the Structures 

Monitoring Program. 

The LRA states that these components have the intended function of structural support and are 

examined using the Structures Monitoring Program as the primary AMP. The staff’s review of 

the Structures Monitoring Program is documented in SER Section 3.0.3.2.16. GALL 

AMP XI.M36 is based on system visual inspections and walkdowns that are conducted 

periodically to identify loss of material due to general corrosion on the external surfaces of 

accessible steel components. The staff finds the applicant’s use of the Structures Monitoring 

Program acceptable because the program: (1) performs visual inspections to monitor for 

indications of degradation such as loss of material and (2) has been enhanced to conduct the 

visual inspections on a frequency not to exceed 5 years. The staff finds that the applicant 

addressed the AERM adequately. 

3.5.2.1.4 Cracking, Loss of Bond, and Loss of Material (Spalling, Scaling) Due to Corrosion of 

Embedded Steel 

In the LRA Table 3.3.2-10 line items that reference Table 3.5-1, item 3.5.1-23, the applicant 

included a reference to Note E and credited the Fire Protection Program for managing this aging 

effect or mechanism in an air – outdoor environment. The applicant also included plant-specific 

Note 6 which states, “The Fire Protection aging management program will be used in addition to 

the Structures Monitoring Program.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 6. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.S6, “Structures Monitoring,” the applicant proposed using the Fire Protection 

Program in addition to the Structures Monitoring Program. 

The LRA states that these components have the intended function of fire barriers (masonry 

walls; interior) and are examined using the Structures Monitoring Program in addition to the Fire 

Protection Program as the AMPs. The staff’s reviews of the Structures Monitoring and Fire 

Protection programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.7, respectively. 

The staff finds the applicant’s use of the Fire Protection and Structures Monitoring programs 

acceptable because: (1) the Fire Protection Program has been enhanced to identify degradation 

of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, and loss of 

material; (2) the masonry walls are also inspected under the Structures Monitoring Program that 

implements the Masonry Wall Program, which has been enhanced to add an examination 

checklist for masonry wall inspection requirements; and (3) the masonry wall inspections are 

conducted at a frequency of 5 years. The staff finds that the applicant addressed the AERM 

adequately. 
Aging Management Review Results 

 3-434 

In its response to RAI 3.3.1.65-01 dated July 19, 2010, the applicant stated that it identified a 

line item crediting the Fire Protection Program for the fire barriers (walls, ceilings, and floors) 

component type, which was inadvertently omitted from Table 3.3.2-10 for the fire protection 

system. The addition of the Fire Protection Program to manage the effects of aging for this 

component type in an air – indoor environment meets the GALL Report recommended 

inspection frequency for reinforced concrete fire barriers. LRA Table 3.3.2-10 was revised by 

the applicant to add the Fire Protection Program and align the line item to reference Table 3.5-1, 

item 3.5.1-23. The applicant also included plant-specific Note 6 which states, “The Fire 

Protection aging management program will be used in addition to the Structures Monitoring 

Program.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 6. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.S6, “Structures Monitoring,” the applicant proposed using the Fire Protection 

Program in addition to the Structures Monitoring Program. 

The LRA states that these components have the intended function of fire barriers (masonry 

walls; interior) and are examined using the Structures Monitoring Program in addition to the Fire 

Protection Program as the AMPs. The staff’s reviews of the Structures Monitoring and Fire 

Protection programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.7, respectively. 

The staff finds the applicant’s use of the Fire Protection and Structures Monitoring programs 

acceptable because: (1) the Fire Protection Program has been enhanced to identify degradation 

of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, and loss of 

material; (2) the masonry walls are also inspected under the Structures Monitoring Program that 

implements the Masonry Wall Program, which has been enhanced to add an examination 

checklist for masonry wall inspection requirements; and (3) the masonry wall inspections are 

conducted at a frequency of 5 years. The staff finds that the applicant addressed the AERM 

adequately. 

3.5.2.1.5 Cracks and Distortion Due to Increased Stress Levels from Settlement 

In the LRA Table 3.3.2-10 line items that reference Table 3.5-1 item 3.5.1-28, the applicant 

included a reference to Note E and credited the Fire Protection Program for managing this aging 

effect or mechanism in an air – outdoor environment. The applicant also included plant-specific 

Note 6 which states, “The Fire Protection aging management program will be used in addition to 

the Structures Monitoring Program.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 6. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.S6, “Structures Monitoring,” the applicant has proposed using the Fire Protection 

Program in addition to the Structures Monitoring Program. 

The LRA states that these components have the intended function of fire barriers (masonry 

walls; interior) and are examined using the Structures Monitoring Program in addition to the Fire 

Protection Program as the AMPs. The staff’s reviews of the Structures Monitoring and Fire 

Protection programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.7, respectively. 

The staff finds the applicant’s use of the Fire Protection and Structures Monitoring programs 

acceptable because: (1) the Fire Protection Program has been enhanced to identify degradation 

of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, and loss of 
Aging Management Review Results 

 3-435 

material; (2) the masonry walls are also inspected under the Structures Monitoring Program that 

implements the Masonry Wall Program, which has been enhanced to add an examination 

checklist for masonry wall inspection requirements; and (3) the masonry wall inspections are 

conducted at a frequency of 5 years. The staff finds that the applicant addressed the AERM 

adequately. 

3.5.2.1.6 Cracking Due to Restraint, Shrinkage, Creep, and Aggressive Environment 

In the LRA Table 3.3.2-10 line items that reference Table 3.5.1, item 3.5.1-43, the applicant 

included a reference to Note E and credited the Fire Protection Program for managing this aging 

effect or mechanism in an air – indoor environment. The applicant also included plant-specific 

Note 6 which states, “The Fire Protection aging management program will be used in addition to 

the Structures Monitoring Program.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 6. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.S5, “Masonry Wall,” the applicant proposed using the Fire Protection Program in 

addition to the Structures Monitoring Program. 

The LRA states that these components have the intended function of fire barriers (concrete 

block) and are examined using the Structures Monitoring Program in addition to the Fire 

Protection Program as the AMPs. The staff’s reviews of the Structures Monitoring and Fire 

Protection programs are documented in SER Sections 3.0.3.2.16 and 3.0.3.2.7, respectively. 

The staff finds the applicant’s use of the Fire Protection and Structures Monitoring programs 

acceptable because: (1) the Fire Protection Program has been enhanced to identify degradation 

of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling, and loss of 

material; (2) the masonry walls are also inspected under the Structures Monitoring Program that 

implements the Masonry Wall Program, which has been enhanced to add an examination 

checklist for masonry wall inspection requirements; and (3) the masonry wall inspections are 

conducted at a frequency of 5 years. The staff finds that the applicant addressed the AERM 

adequately. 

3.5.2.1.7 Cracking Due to Loss of Bond, Loss of Material (Spalling, Scaling)/Corrosion of 

Embedded Steel, Increase in Porosity and Permeability, Aggressive Chemical Attack, and Loss 

of Material Due to Abrasion and Cavitation 

In the LRA Table 3.3.2-27 line items that reference Table 3.5-1 items 3.5.1-31 and 3.5.1-34, the 

applicant included a reference to Note E and credited the Buried Non-Steel Piping Inspection 

Program for managing these aging effects or mechanisms in a groundwater or soil (external) 

environment. The applicant also included plant-specific Note 7 which states, “The Open-Cycle 

Cooling Water System aging management program activities are adequate for managing the 

aging effects of the internal surfaces of reinforced concrete service water piping. The Buried 

Non-Steel Piping Inspection aging management program activities are adequate for managing 

the aging effects of the external surfaces of reinforced concrete service water piping.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 7. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.S6, “Structures Monitoring,” and GALL AMP XI.S7, RG 1.127, “Inspection of 
Aging Management Review Results 

 3-436 

Water-Control Structures Associated with Nuclear Power Plants,” the applicant proposed using 

the Buried Non-Steel Piping Program. 

The LRA states that these reinforced concrete piping and fitting components have the intended 

function of pressure boundary and are examined using the Buried Non-Steel Piping Program. 

The staff’s review of the Buried Non-Steel Piping Program is documented in SER 

Section 3.0.3.3.4. Given that there have been a number of recent industry events involving 

leakage from buried or underground piping, the staff needs further information to evaluate the 

impact that these recent industry events might have on the applicant’s Buried Non-Steel Piping 

Program. By letter dated August 6, 2010, the staff issued RAI B.2.1.24 requesting that the 

applicant provide information regarding how HCGS will incorporate the recent industry operating 

experience into its AMRs and AMPs. Pending the applicant’s response to, and staff’s review of, 

the aforementioned RAI, the staff is not able to confirm that the Buried Piping Inspection 

Program is suitably informed by the recent relevant operating experience. 

In the LRA Table 3.3.2-27 line items that reference Table 3.5-1, items 3.5.1-37 and 3.5.1-45, the 

applicant included a reference to Note E and credited the Open-Cycle Cooling Water System 

Program for managing these aging effects or mechanisms in a raw water (internal) environment. 

The applicant also included plant-specific Note 7 which states, “The Open-Cycle Cooling Water 

System aging management program activities are adequate for managing the aging effects of 

the internal surfaces of reinforced concrete service water piping. The Buried Non-Steel Piping 

Inspection aging management program activities are adequate for managing the aging effects of 

the external surfaces of reinforced concrete service water piping.” 

The staff reviewed the AMR results lines that reference Note E and plant-specific Note 7. The 

staff determined, for these items, that the material, aging effect, and environment are consistent 

with the corresponding line of the GALL Report; however, where the GALL Report recommends 

GALL AMP XI.S7, RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear 

Power Plants,” the applicant proposed using the Open-Cycle Cooling Water System Program. 

The LRA states that these reinforced concrete piping and fitting components have the intended 

function of pressure boundary and are examined using the Open-Cycle Cooling Water System 

Program. The staff’s review of the Open-Cycle Cooling Water System Program is documented 

in SER Section 3.0.3.1.9. Since the Open-Cycle Cooling Water System Program includes 

mitigative, performance-monitoring, and condition monitoring activities to manage aging effects 

caused by biofouling, corrosion, erosion, protective coating failures, and silting in the open-cycle 

cooling water system, it is unclear to the staff that this is an adequate approach to managing 

aging of reinforced concrete piping and fitting components subjected to a raw water (internal) 

environment. By letter dated June 7, 2010, the staff issued RAI 3.5.2.1-6 requesting that the 

applicant discuss how the Open-Cycle Cooling Water System Program will adequately address 

the AERMs. 

By letter dated June 29, 2010, the applicant responded and explained that the Open-Cycle 

Cooling Water Program is the appropriate program to manage aging of the internal surfaces of 

the concrete piping because it implements inspections of the internal surfaces. The applicant 

explained that the concrete piping has a polymer coating applied to the interior surface of the 

pipe and that the interior of each piping header is visually inspected every other refueling outage 

(approximately every 3 years) for signs of coating and concrete degradation. 

The staff reviewed the applicant’s response and found it acceptable because it explained that 

visual inspections are conducted on the internal surfaces of the concrete piping every other 
Aging Management Review Results 

 3-437 

refueling outage. Visual inspections of the piping header will detect indications of age-related 

degradation in the piping and the header should be representative of the main piping. The type 

and frequency of the inspections are appropriate based on guidance provided by other GALL 

Report programs which manage aging of concrete, such as the Structures Monitoring Program. 

These programs suggest visual inspections with a frequency of at least every 5 years to detect 

degradation of concrete exposed to raw water. Based on its review of the applicant’s response, 

the staff finds that the applicant addressed the AERM adequately and the staff’s concern in 

RAI 3.5.2.1-6 is resolved. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.5.2.1.8 No Aging Effects That Requires Aging Management 

In LRA Table 3.5-1, item 3.5.1-58, the applicant stated that the galvanized steel and aluminum 

support members, welds, bolted connections, and support anchorages to building structures 

exposed to indoor air for the material and environment combination do not have AERMs. The 

applicant also stated that no AMPs are applicable to the aluminum items exposed to indoor air 

for the electrical commodities system associated with this item number. The GALL Report, 

item III.B5-2 which corresponds to Table 3.5.1, item 3.5.1-58 recommends no AMP for this 

component group and, therefore, the staff finds the applicant’s determination acceptable. 

3.5.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further 

Evaluation Is Recommended 

In LRA Section 3.5.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the containments, structures, and component supports components and 

provides information concerning how it will manage aging effects in the following three areas: 

 (1) PWR and BWR containments: 

● aging of inaccessible concrete areas 

● cracks and distortion 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 
Aging Management Review Results 

 3-438 

● 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 

 (2) 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) 

● 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 

Groups 7 and 8 stainless steel tank liners 

● aging of supports not covered by the Structures Monitoring Program 

● cumulative fatigue damage due to cyclic loading 

 (3) QA for aging management of nonsafety-related components 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

reviewed the applicant’s evaluation to determine whether it adequately addressed the issues 

further evaluated. In addition, the staff reviewed the applicant’s further evaluations against the 

criteria contained in SRP-LR Section 3.5.2.2. The staff’s review of the applicant’s further 

evaluation follows. 

3.5.2.2.1 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: 

Aging of Inaccessible Concrete Areas. LRA Section 3.5.2.2.1.1 addresses aging of inaccessible 

concrete areas. In the LRA, the applicant stated that this item is not applicable to the HCGS 

Mark I steel containment. The containment is located in a reactor building and is subject to an 

indoor, non-aggressive environment. The containment is supported by foundation concrete of 

the reactor building, but the reactor building foundation concrete does not perform a pressure 

retaining function and, therefore, is not subject to ASME Code Section XI, Subsection IWL 

inspections. 

The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria in SRP-LR Section 3.5.2.2.1.1, 

which 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 
Aging Management Review Results 

 3-439 

(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 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 staff confirmed that HCGS uses a Mark I steel containment and is located in the reactor 

building. The steel containment is supported by the concrete foundation of the reactor building. 

The concrete foundation of the reactor building does not perform a pressure retaining function 

and settlement of the reactor building foundation is managed by the Structures Monitoring 

Program. The staff’s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff finds the applicant’s evaluation of this AERM acceptable. SER 

Section 3.5.2.2.2, “Aging Management of Inaccessible Areas,” documents the staff’s review of 

the applicant’s evaluation of aging management of inaccessible areas, including the reactor 

building. 

LRA Section 3.5.2.2.1.1 addresses aging of inaccessible concrete areas in PWR and BWR 

containments. The applicant stated that its primary containment is a Mark I steel containment 

and that item 3.5.1-1 in LRA Table 3.5.1 is not applicable to the Mark I steel containment 

design. In item 3.5.1-1, the applicant also stated that inaccessible concrete areas of the reactor 

building are addressed by items 3.5.1-31 and 3.5.1-23 which credit the Structures Monitoring 

Program for aging management. 

The staff confirmed that no AMR results lines in LRA Tables 3.5.2-1 through 3.5.2-13, which 

include both the primary containment and the reactor building (secondary containment), are 

referenced to LRA Table 3.5.1, item 3.5.1-1. The staff also confirmed that the UFSAR 

supplement describes the applicant’s primary containment as a Mark I steel containment design 

and that concrete is not applicable for this containment design. On the basis that the applicant 

has a steel containment design for which concrete is not applicable and other concrete 

elements associated with item 3.5.1-1 are included in items 3.5.1-31 and 3.5.1-23, the staff finds 

the applicant’s determination that item 3.5.1-1 is not applicable to be acceptable. 

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. LRA Section 3.5.2.2.1.2 

refers to Table 3.5.1, items 3.5.1-2 and 3.5.1-3 and addresses 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, if not covered by the 

Structures Monitoring Program. In the LRA, the applicant stated that the Mark I steel 

containment is supported by the reactor building foundation concrete and the foundation 

concrete does not incorporate either a porous concrete subfoundation or a dewatering system. 

The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2, 

which 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 staff confirmed that HCGS uses a Mark I steel containment and is located in the reactor 

building and is supported by the concrete foundation of the reactor building. The LRA states 
Aging Management Review Results 

 3-440 

that cracks and distortion due to increased stress levels from settlement of the reactor building 

foundation are managed by the Structures Monitoring Program. The staff’s review of the 

Structures Monitoring Program is documented in SER Section 3.0.3.2.16. The staff also 

confirmed that the HCGS reactor building foundation does not have either a porous concrete 

subfoundation or a dewatering system. The staff finds acceptable the applicant’s evaluation of 

this AERM in that the criteria in SRP-LR Section 3.5.2.2.1.2 are met. 

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. LRA 

Section 3.5.2.2.1.3 refers to Table 3.5.1, item 3.5.1-4 and addresses reduction of strength and 

modulus of concrete structures due to elevated temperature. In the LRA, the applicant stated 

that item 3.5.1-4 is not applicable at HCGS. The LRA states that air is circulated by the drywell 

air cooling system that limits the bulk air temperature inside the drywell during normal plant 

operation to 135 °F, with a maximum local air temperature of 194 °F above elevation 162 feet. 

Concrete structural components in the drywell are not subject to general area temperatures 

greater than 150 °F or local area temperatures greater than 200 °F. The LRA further states that 

process piping penetrations having temperatures greater than 200 °F are insulated through the 

penetrations and when combined with compartment air circulation, the concrete local area 

temperatures are reduced to less than 200 °F. 

The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3, 

which recommends further evaluation of the plant-specific AMP if any portion of the concrete 

containment components exceeds the specified temperature limits of 66 C (150 °F) general and 

93 °C (200 °F) local. 

The staff finds acceptable the applicant’s evaluation that this aging effect is not applicable 

because HCGS uses a Mark I steel containment and no concrete performs a pressure retaining 

function. SER Section 3.5.2.2.2, “Reduction of Strength and Modulus of Concrete Structures 

Due to Elevated Temperature,” documents the staff’s review of the applicant’s evaluation of 

aging management of reduction of strength and modulus of other in-scope concrete structures 

due to elevated temperature. 

Loss of Material Due to General, Pitting, and Crevice Corrosion. LRA Section 3.5.2.2.1.4 refers 

to Table 3.5.1, item 3.5.1-5 and addresses loss of material due to general, pitting, and crevice 

corrosion for steel elements of accessible and inaccessible areas of containments. In the LRA, 

the applicant stated that the ASME 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 

BWR Mark I primary containment pressure retaining components due to general, pitting, and 

crevice corrosion. In the LRA, the applicant further stated that accessible areas are subject to 

periodic examinations to detect loss of material due to general, pitting, and crevice corrosion. 

Inaccessible areas are examined when they become accessible, or if they are suspected of 

degradation based on examination of the corresponding accessible area. The concrete in 

contact with the embedded drywell shell and the drywell support skirts meets the specifications 

of ACI 318-71 and the guidance of ACI 201.2R. 

The applicant also stated that accessible portions of the drywell floor concrete are monitored 

under the Structures Monitoring Program to ensure that it is free of penetrating cracks that 

provide a path for water seepage to the surface of the embedded drywell shell. Water ponding 

on the containment drywell concrete floor is not common and when detected, is cleaned up in a 

timely manner. The applicant also stated that the current HCGS design does not require 

installation of a moisture barrier at the junction where the inner drywell shell becomes 

embedded in concrete. Visual inspection of this interface did not identify gaps, cracks, or 
Aging Management Review Results 

 3-441 

separation of concrete from the drywell shell that would be a path for potential water leakage 

intrusion into the embedded shell. Visual examination conducted in accordance with ASME 

Code Section XI, Subsection IWE did not identify significant corrosion at the interface. The 

examiners noted only local surface rust in areas where the drywell shell coating is chipped or 

damaged as a result of maintenance activities. There were no indications that corrosion is 

occurring in the drywell shell below the concrete floor. 

The applicant further explained that in 2007 and 2009, HCGS conducted UT measurements of 

the drywell shell thickness at sample locations above the junction of where the shell becomes 

embedded in concrete. This area was reported in IN 2004-01 as susceptible to loss of material 

due to corrosion. Also, measurements in this area would detect significant loss of material that 

could be occurring in inaccessible exterior surfaces of the drywell shell, specifically in the 

“sand-pocket region.” There is no “sand-pocket region” or sand in the concrete foundation 

transition zone of the drywell shell and the air gap at HCGS. UT measurement results showed 

that, in each case, the measured thickness was greater than the specified nominal drywell shell 

thickness. The minimum measured thickness was 1.51 inches as compared to the nominal 

design thickness of 1.5 inches. However, the applicant explained that during the 2009 refueling 

outage, water was found trickling out of a reactor building concrete wall penetration sleeve from 

the drywell air gap region and ponded on the torus room floor. Analysis of the ponded water 

identified it as reactor water and refueling water. A review of past UT readings on the upper 

region, taken in 2007, of the drywell shell in areas of reported water leakage indicates no loss of 

material of the drywell shell. The water leakage stopped after the refueling cavity was drained 

at the end of the refueling outage. The suspected source of the water was the refuel bellow or 

liner. The air gap drains were inspected and there was no blockage or standing water in the air 

gap region, and the drywell shell showed no signs of corrosion. The water leakage issue was 

entered into the corrective action program to determine the cause of the leakage and corrective 

actions to prevent reoccurrence. In 2007, HCGS also conducted UT measurements of the 

drywell shell thickness at sample locations in the upper region of the drywell. Areas subject to 

UT examination include locations where two plates of different thicknesses are welded together 

to form the drywell shell. The condition of the drywell shell at the interface of the two plates has 

been of interest to the staff because of the likelihood of moisture collection at the ledge that may 

be formed by the thicker of the two plates. UT measurement results showed that, in each case, 

the measured thickness was greater than the specified nominal drywell shell thickness. 

By letter dated May 14, 2010, the staff issued RAI B.2.1.28-01 requesting that the applicant 

discuss: (1) plans for determining the root cause of the water leak, (2) why the water did not exit 

through the drywell lower air gap drains, (3) plans for performing NDE of the drywell area 

potentially affected to demonstrate that water is not trapped in the annular space between the 

concrete shield wall and drywell, and (4) plans to quantify the effects of water leakage on the 

drywell including volumetric examination and a detailed engineering analysis. This issue, 

including the RAI response and the staff’s review, is discussed in detail in the ASME Section XI, 

Subsection IWE Program write-up in SER Section 3.0.3.2.14. 

During the October 2010 outage, the applicant again observed leakage from the same 

penetration sleeve J13, as well as from penetration sleeve J14. By letter dated January 3, 

2011, the staff issued RAI B.2.1.28-3 requesting additional information regarding how the 

applicant will address this new plant-specific operating experience. 

By letter dated January 19, 2011, the applicant responded and explained that during the 

October 2010 outage, additional boroscope inspections had been conducted on the air gap 

drains which revealed covers on the drains. These covers prevented the boroscope from 
Aging Management Review Results 

 3-442 

accessing the air gap and may prevent proper drainage of the drywell air gap. The applicant 

further explained that this condition has been entered into the corrective action program, with 

actions to restore drain line functionality prior to flood-up of the reactor cavity during the next 

refueling outage. The applicant also stated in the response, that during the October 2010 

outage, boroscope inspections of the drywell air gap were conducted through the penetration 

sleeves at the J13, J14, J19, J24, and J37 penetrations, which are all in close proximity to the 

J13 penetration. The applicant stated that these inspections confirmed that there are no 

obstructions in the air gap around the penetrations that could retain water against the drywell 

shell and that there are no visible signs of corrosion in this area. 

In addition to the boroscope inspections, the applicant took UT thickness measurements of the 

drywell between the leaking penetrations and the floor. The measurements were all above 

nominal plate thickness except the area under the J13 penetration sleeve. This area had 

readings below the nominal plate thickness of 1.5 inch; however, the average reading was 

above the miniminum allowable manufacturing tolerance of 1.49 inches, and the individual 

readings were all above the 1.4375-inch thickness used in the design analysis. To address this 

area of possible degredation, the applicant will take UT measurements at the same locations 

during the next three refueling outages. The applicant stated that if the future measurements 

indicate ongoing corrosion, a corrosion rate will be determined and the issue will be entered into 

the corrective action program. 

Subsequently, during a May 9, 2011, telephone conference call, the applicant informed the staff 

that its further investigation of one of the drywell air gap drain lines indicated that the location of 

the blockage (where covers was installed) did not coincide with the drain line’s entrance into the 

air gap. The applicant was unable to identify through boroscope inspection from the air gap 

side, and opening that coincide with the drain line. Due to the level of exposure involved in 

performing such inspections, the applicant was not able to perform the same investigation for 

the remaining three drain lines for the air gap. 

The staff was concerned about this new finding and requested the applicant to to describe in 

detail the existing configuarion of the air gap blocked drains, its impact on the applicant’s plans 

to clear these drain by the spring of 2012, and any revisions to the the enhancements and 

commitment 28 for the ASME Section XI, Subsection IWE Program. The applicant responded 

to this request by letter dated May 19, 2011, and provided information about the drywell air gap 

drain line configuaration, revised enhancements and commitment. Detailed information about 

this issue, including the staff’s review and acceptance of the enhancements, can be found in the 

ASME Section XI, Subsection IWE Program evaluation in SER Section 3.0.3.2.14. 

Furthermore, the applicant stated that implementation of the ASME Section XI, Subsection IWE 

and 10 CFR Part 50, Appendix J programs, supplemented by the plant-specific activities 

described in SER Section 3.0.3.2.14, provide reasonable assurance that loss of material due to 

corrosion of the drywell shell will be adequately managed during the period of extended 

operation such that the intended functions of the Mark I containment drywell are maintained 

consistent with the CLB. Miscellaneous steel components (catwalks, stairs, handrails, ladders, 

platforms, etc.) inside the primary containment suppression chamber aligned to this line item 

based on material, environment, and aging effect, do not perform a primary containment 

intended function. The components are, therefore, not within the scope of the ASME Section 

XI, Subsection IWE and 10 CFR Part 50, Appendix J programs. The Structures Monitoring 

Program will be substituted to manage loss of material due to general, pitting, and crevice 

corrosion of these components. 
Aging Management Review Results 

 3-443 

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 Section XI, Subsection IWE and 

10 CFR Part 50, Appendix J 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.B1.1-2 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. 

The staff’s reviews of the applicant’s Structures Monitoring; ASME Section XI, Subsection IWE; 

and 10 CFR Part 50, Appendix J programs are documented in SER Sections 3.0.3.2.16, 

3.0.3.2.14, and 3.0.3.1.16, respectively. The staff reviewed the programs and verified that the 

above criteria were adequately addressed by the applicant and that plant-specific operating 

experience (i.e., leakage from the penetrations) is being addressed appropriately. 

Based on the staff’s review, including resolution to RAI B.2.1.28-1 and RAI B.2.1.28-3 as 

discussed above and in SER Section 3.0.3.2.14, the staff finds the applicant’s evaluation 

acceptable because it addresses the guidance in LR-ISG-2006-01, the guidance in the SRP-LR, 

and the plant-specific water leakage detected during the 2009 and 2010 refueling outage. 

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA 

Section 3.5.2.2.1.5 refers to Table 3.5.1, item 3.5.1-7 and addresses loss of prestress due to 

relaxation, shrinkage, creep, and elevated temperature. In the LRA, the applicant stated that 

loss of prestress forces due to relaxation, shrinkage, creep, and elevated temperature for the 

HCGS containment structure is not applicable since the HCGS containment structure does not 

use a prestressed concrete containment design. 

The staff finds acceptable the applicant’s evaluation that this aging effect is not applicable on 

the basis that the HCGS containment is a Mark I steel containment with no post-tensioned 

concrete. 

Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 refers to Table 3.5.1, items 3.5.1-8 and 

3.5.1-9 and addresses cumulative fatigue damage. In the LRA, the applicant stated that at 

HCGS, cumulative fatigue damage of the suppression chamber (torus) shell (including welded 

joints), and penetrations (including penetration sleeves, dissimilar metal welds, and penetration 
Aging Management Review Results 

 3-444 

bellows), vent header, vent line bellows, and downcomers is a TLAA as defined in 10 CFR 54.3. 

The TLAA is evaluated in accordance with 10 CFR 54.21(c). 

The staff reviewed LRA Section 3.5.2.2.1.6 against the criteria in SRP-LR Section 3.5.2.2.1.6, 

which states that fatigue analyses of penetrations are TLAAs as defined in 10 CFR 54.3. The 

evaluation of this TLAA is addressed separately in Section 4.6. 

Cracking Due to Stress-Corrosion Cracking. LRA Section 3.5.2.2.1.7 refers to Table 3.5.1, 

items 3.5.1-10 and 3.5.1-11 and addresses cracking due to SCC. In the LRA, the applicant 

stated that SCC is not an applicable aging mechanism for stainless steel penetration sleeves, 

penetration bellows, dissimilar metal welds, and stainless steel vent line bellows. The LRA 

states that these components are located in an air – indoor environment and not subject to 

conditions that promote SCC (i.e., lack of chloride or sulfate contaminants). 

The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7, 

which states that cracking due to SCC of stainless steel penetration sleeves, penetration 

bellows, and dissimilar metal welds could occur in all types of PWR and BWR containments. 

Cracking could also occur in stainless steel vent line bellows for BWR containments. The 

existing program relies on ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J 

to manage this aging effect. The GALL Report recommends further evaluation of additional 

appropriate examinations and evaluations implemented to detect these aging effects for 

stainless steel penetration sleeves, penetration bellows, and dissimilar metal welds and 

stainless steel vent line bellows. 

Since the containment environment at HCGS does not contain a significant presence of 

contaminants, the staff determines that additional inspections are not necessary. The existing 

programs will adequately manage aging during the period of extended operation, and the staff 

finds the applicant’s evaluation of this aging effect acceptable. 

Cracking Due to Cyclic Loading. LRA Section 3.5.2.2.1.8 refers to Table 3.5.1, items 3.5.1-12 

and 3.5.1-13 and addresses cracking due to cyclic loading. In the LRA, the applicant stated that 

items 3.5.1-12 and 3.5.1-13 are not applicable to HCGS containment components: steel, 

stainless steel elements, dissimilar metal welds; penetration sleeves, penetration bellows; 

suppression pool shell and unbraced downcomers; torus; vent line; vent header; vent line 

bellows; and downcomers. The applicant also stated that a fatigue analysis exists in the CLB 

for the following containment components: steel, stainless steel elements, dissimilar metal 

welds; penetration sleeves, penetration bellows; suppression pool shell and unbraced 

downcomers; torus; vent line; vent header; vent line bellows; and downcomers. The LRA 

further states that expansion bellows not associated with the containment are located in the 

reactor building and yard structures and have a design specification requirement of 2,000 

normal cycles. Evaluation of fatigue due to cyclic loading of these components shows that the 

projected number of cycles for 60 years is approximately 600 cycles, thus significant cracking of 

the bellows due to cyclic loading is not expected to occur during the period of extended 

operation. The LRA also states that plant operating experience has not identified cracking of 

bellows as a concern. 

The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria in SRP-LR Section 3.5.2.2.1.8, 

which states that cracking due to cyclic loading of suppression pool steel and stainless steel 

shells (including welded joints) and penetrations (including penetration sleeves, dissimilar metal 

welds, and penetration bellows) could occur for all types of PWR and BWR containments and 

BWR vent header, vent line bellows, and downcomers. The existing program relies on ASME 
Aging Management Review Results 

 3-445 

Section XI, Subsection IWE and 10 CFR Part 50, Appendix J to manage this aging effect. 

However, VT-3 visual inspection may not detect fine cracks. The GALL Report recommends 

further evaluation for detection of this aging effect. 

On the basis of its review, the staff finds the applicant’s evaluation of the aging effect “cracking 

due to cyclic loading” acceptable. The staff finds acceptable the applicant’s evaluation that this 

aging effect is not applicable because HCGS uses a Mark I steel containment component and a 

fatigue analysis exists in the CLB for these components, thus cracking due to cyclic loading is a 

TLAA that has been addressed in SER Sections 3.5.2.2.1 and 4.6 and are being addressed by 

items 3.5.1-8 and 3.5.1-9. 

Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze-Thaw. LRA 

Section 3.5.2.2.1.9 refers to Table 3.5.1, item 3.5.1-14 and addresses loss of material (scaling, 

cracking, and spalling) due to freeze-thaw. In the LRA, the applicant stated that this item is not 

applicable because HCGS has a BWR Mark I steel containment that is located in the reactor 

building. Repeated freeze-thaw is not applicable and, therefore, loss of concrete material and 

cracking will not occur. 

The staff reviewed LRA Section 3.5.2.2.1.9 against the criteria in SRP-LR Section 3.5.2.2.1.9, 

which recommends further evaluation of loss of material due to freeze-thaw for plants with 

concrete containments located in moderate to severe weathering conditions. 

The staff finds the applicant’s evaluation acceptable that this aging effect is not applicable 

because HCGS has a Mark I steel containment and there is no ASME Code Section III, 

Division 2 Class CC concrete. Concrete that supports the Mark I steel containment is located in 

the reactor building and since it is not exposed to outdoor air, it will not be subjected to 

freeze-thaw cycles. 

Cracking Due to Expansion and Reaction with Aggregate and Increase in Porosity and 

Permeability Due to Leaching of Calcium Hydroxide. LRA Section 3.5.2.2.1.10 refers to 

Table 3.5.1, item 3.5.1-15 and addresses cracking due to expansion and reaction with 

aggregate and increase in porosity and permeability due to leaching of calcium hydroxide. In 

the LRA, the applicant stated that this item is not applicable because HCGS has a BWR Mark I 

steel containment. The LRA also states that the HCGS containment-related reinforced concrete 

is designed and constructed to ACI and ASTM specifications that meet the intent of ACI 201.2R, 

and the containment-related concrete is not subjected to flowing water. Therefore, managing 

the effects of cracking due to expansion and reaction with aggregates, and increase in porosity 

and permeability due to leaching of calcium hydroxide is not required. 

The staff reviewed LRA Section 3.5.2.2.1.10 against the criteria in SRP-LR Section 3.5.2.2.1.10, 

which 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. The GALL Report recommends further evaluation if the 

aggregate was not evaluated for potential expansion or reaction due to reactivity with the 

cementitious materials and suggests ASME Section XI, Subsection IWL as the AMP. 

The staff confirmed that no HCGS containment concrete serves a pressure retaining function. 

Therefore, the concrete does not need to be evaluated in this section. SER Section 3.5.2.2.2, 

“Aging Management of Inaccessible Areas,” documents the staff’s review of the applicant’s 

evaluation of cracking due to expansion and reaction with aggregate and increase in porosity 

and permeability due to leaching of calcium hydroxide. The staff confirmed that aggregate 
Aging Management Review Results 

 3-446 

reaction aging effects for the concrete are managed by the Structures Monitoring Program, 

which conducts inspections by qualified personnel for indications of distress as defined by 

ACI 201.1R, and through enhancement, implements acceptance criteria specified in 

ACI 349.3R-96. The staff’s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1 criteria. For those line items that apply to LRA Section 3.5.2.2.1, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

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 the Structures Monitoring Program. In the LRA, the 

applicant stated that the Structures Monitoring Program is used to manage aging effects 

applicable to Groups 1, 3, and 4 structures, with Group 5, “Fuel Storage Facility,” included with 

Group 1 structures. The applicant also stated that Groups 2, 7, 8, and 9 structures do not exist 

at HCGS and certain aging mechanisms identified in the GALL Report are not applicable to 

some Group 1, 3, and 4 structures. However, the applicant stated that accessible structures will 

be monitored for loss of material, cracking, increase in porosity and permeability, and loss of 

bond through the Structures Monitoring Program. 

The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1, 

which states that the GALL Report recommends further evaluation of certain structure and aging 

effect combinations if they are not covered by the Structures Monitoring Program, including: 

(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; (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; (3) loss of material due to corrosion for Groups 1-5, 7, and 8 structures; (4) loss of 

material (spalling, scaling) and cracking due to freeze-thaw for Groups 1-3, 5, and 7-9 

structures; (5) cracking due to expansion and reaction with aggregates for Groups 1-5 and 7-9 

structures; (6) cracks and distortion due to increased stress levels from settlement for 

Groups 1-3 and 5-9 structures; and (7) reduction in foundation strength, cracking, differential 

settlement due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9 structures. 

In addition, lock-up due to wear may occur for Lubrite® radial beam seats in BWR drywells, RPV 

support shoes for PWRs with nozzle supports, steam generator supports, and other sliding 

support bearings and sliding support surfaces. The existing program relies on the structures 

monitoring program or ASME Section XI, Subsection IWF to manage this aging effect. The 

GALL Report recommends further evaluation only for structure-aging effect combinations not 

within the ASME Section XI, Subsection IWF or Structures Monitoring Programs. 

 (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 3.5.2.2.2.1.1 refers to Table 3.5.1, item 3.5.1-23. In the LRA, the applicant 

stated that cracking, loss of bond, and loss of material (spalling, scaling) due to 
Aging Management Review Results 

 3-447 

corrosion of embedded steel for Groups 1 (includes Group 5 structures), 3, and 4 

structures are monitored by the Structures Monitoring Program and thus further 

evaluation is not necessary. 

 The staff noted that Groups 1 (includes Group 5), 3, and 4 structures subject to this 

AERM are all in-scope of the Structures Monitoring Program. Therefore, the staff finds 

that the criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation 

is required. 

 (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 3.5.2.2.2.1.2 refers to Table 3.5.1, item 3.5.1-24. In the LRA, the applicant 

stated that increase in porosity and permeability, cracking, and loss of material (spalling, 

scaling) due to aggressive chemical attack of Groups 1 (includes Group 5 structures), 3, 

and 4 structures are not applicable to HCGS interior and above-grade exterior concrete 

because the structures are not exposed to aggressive chemical attack. The LRA also 

states that aging management of the Groups 1 (including Group 5 structures), 3, and 4 

structures is done under the Structures Monitoring Program. 

 The staff noted that Groups 1 (includes Group 5), 3, and 4 structures subject to this AMR 

are all in-scope of the Structures Monitoring Program. Therefore, the staff finds that the 

criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is 

required. 

 (3) Loss of Material Due to Corrosion for Groups 1-5, 7, and 8 Structures 

 LRA Section 3.5.2.2.2.1.3 refers to Table 3.5.1, item 3.5.1-25. In the LRA, the applicant 

stated that loss of material due to corrosion for Groups 1 (includes Group 5 structures), 

3, and 4 structures and component supports is monitored through the Structures 

Monitoring Program, and thus a further evaluation is not necessary. 

 The staff noted that Groups 1 (includes Group 5), 3, and 4 structures subject to this AMR 

are all in-scope of the Structures Monitoring Program. Therefore, the staff finds that the 

criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is 

required. 

 (4) Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw for Groups 1-5 

and 7-9 Structures 

 LRA Section 3.5.2.2.2.1.4 refers to Table 3.5.1, item 3.5.1-26. In the LRA, the applicant 

stated that loss of material (spalling, scaling) and cracking due to freeze-thaw for 

Groups 1 (includes Group 5 structures), 3, and 4 structures are monitored through the 

Structures Monitoring Program and thus further evaluation is not necessary. 

 The staff noted that Groups 1 (including Group 5), 3, and 4 structures subject to this 

AMR are all in-scope of the Structures Monitoring Program. Therefore, the staff finds 

that the criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation 

is required. 

 (5) Cracking Due to Expansion and Reaction with Aggregates for Groups 1-5 and 7-9 

Structures 
Aging Management Review Results 

 3-448 

 LRA Section 3.5.2.2.2.1.5 refers to Table 3.5.1, item 3.5.1-27. In the LRA, the applicant 

stated that cracking due to reaction with aggregates for Groups 1 (includes Group 5 

structures), 3, and 4 structures is not applicable as concrete specifications require the 

use of Type II, low-alkali cement. The LRA also stated that the aggregates were tested 

in conformance with ASTM C289 and C295 to demonstrate that the aggregate was not 

reactive. The LRA further states that the Structures Monitoring Program will be used to 

manage cracking of reinforced concrete in accessible areas of structures. 

 The staff noted that Groups 1 (includes Group 5), 3, and 4 structures subject to this AMR 

are all in-scope of the Structures Monitoring Program. Therefore, the staff finds that the 

criteria of SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is 

required. 

 (6) Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3 

and 5-9 Structures 

 LRA Section 3.5.2.2.2.1.6 refers to Table 3.5.1, item 3.5.1-28. In the LRA, the applicant 

stated that the Structures Monitoring Program will be used to manage cracks and 

distortion due to increased stress levels from settlement of Groups 1 and 3 structures, 

however, this aging mechanism is insignificant at HCGS because the structures are 

founded on dense soil or the Vincentown Formation. The LRA also states that 

evaluation of pre-construction and post-construction soil explorations predicted the 

settlement to be no more than 1.5 inches for the safety-related structures and settlement 

leveled off soon after construction. The building foundations for the safety-related 

structures consist of reinforced concrete mats that bear on dense soil or the Vincentown 

Formation. Nonsafety-related building foundations consist of reinforced concrete slabs 

supported on piles. The LRA further states that a dewatering system and porous 

concrete subfoundations are not used at HCGS, and the structures are monitored under 

the Structures Monitoring Program. 

 The staff confirmed that Groups 1 and 3 structures subject to this AMR are all in-scope 

of the Structures Monitoring Program. Therefore, the staff finds that the criteria of 

SRP-LR Section 3.5.2.2.2.1 have been met and no further evaluation is required. The 

staff’s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. 

 (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 3.5.2.2.2.1.7 refers to Table 3.5.1, item 3.5.1-29. In the LRA, the applicant 

stated that Groups 1 and 3 structures are not subject to reduction in foundation strength, 

cracking, and differential settlement due to erosion of porous concrete subfoundation 

because porous concrete subfoundations were not used at HCGS. 

 Based on the review of documents supporting the LRA, the staff agrees this aging affect 

is not applicable because HCGS has no porous concrete subfoundations. 

 (8) Lock-Up Due to Wear for Lubrite® Radial Beam Seats in BWR Drywell and Other Sliding 

Support Surfaces 

 LRA Section 3.5.2.2.2.1.8 refers to Table 3.5.1, item 3.5.1-30. In the LRA, the applicant 

stated that sliding surfaces are provided for supports for radial beam seats in the drywell, 
Aging Management Review Results 

 3-449 

and the Structures Monitoring Program will be used to manage lock-up due to wear of 

these sliding surfaces. 

 The staff agrees that the Structures Monitoring Program is an appropriate AMP to 

manage lock-up due to wear of the sliding surfaces, however, during its review of this 

item, the staff was unable to verify that these sliding support surfaces were being 

inspected for loss of function due to corrosion, distortion, dirt, overload, or fatigue under 

either the Structures Monitoring or ASME Section XI, Subsection IWF programs. To 

address this, the staff issued RAI 3.5.2.2.2-1 by letter dated June 7, 2010, asking the 

applicant to explain if the inspections were being performed. 

 By letter dated June 29, 2010, the applicant responded and explained that the Lubrite®

sliding surfaces are within the scope of the Structures Monitoring Program and they are 

visually inspected on a frequency of 5 years. The inspections look for evidence of 

corrosion, distortion, dirt, member misalignment, or other degraded conditions which 

would indicate loss of mechanical function. 

 The staff reviewed the applicant’s response and found it acceptable because it verifies 

that the Lubrite® sliding supports are within the scope of the applicant’s Structures 

Monitoring Program and they are subject to the appropriate visual inspections. The 

staff’s concern in RAI 3.5.2.2.2-1 is resolved. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2.1 criteria. For those line items that apply to LRA Section 3.5.2.2.2.1, 

the staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 against 

the criteria in SRP-LR Section 3.5.2.2.2.2, which states that the GALL Report recommends 

further evaluation of certain structure and aging effect combinations: (1) loss of material 

(spalling, scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete areas 

of Groups 1-3, 5, and 7-9 structures for plants located in moderate to severe weathering 

conditions; (2) cracking due to expansion and reaction with aggregates in below-grade 

inaccessible concrete areas of Groups 1-5 and 7-9 structures if concrete was not constructed in 

accordance with recommendations in ACI 201.2R-77; (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 in below-grade inaccessible 

concrete areas of Groups 1-3, 5, and 7-9 structures for plants whose structures are not included 

within the scope of the applicant’s Structures Monitoring Program; (4) 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 in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures if the 

environment is aggressive; and (5) increase in porosity and permeability, and loss of strength 

due to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Groups 1-3, 

5, and 7-9 structures if the concrete was not constructed in accordance with the 

recommendations in ACI 201.2R-77. 

 (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. 
Aging Management Review Results 

 3-450 

 In the LRA, the applicant stated that Groups 1 and 3 structures are located in a region 

where weathering conditions are considered severe as shown in ASTM C33-90, 

Figure 1. GALL Report Groups 2, 7, 8, and 9 structures do not exist at HCGS. Concrete 

for Groups 1 and 3 structures is designed in accordance with ACI 318-71 and 

constructed in accordance with ACI 301-72. The HCGS concrete mixes were designed 

to provide for low permeability and adequate air entrainment (3 to 6 percent). The LRA 

also states that a review of operating experience did not identify significant loss of 

material and cracking due to freeze-thaw of reinforced concrete structures. The LRA 

further states that inaccessible reinforced concrete will be inspected, if excavated for any 

reason, as required by the Structures Monitoring Program. 

 The staff reviewed LRA Section 3.5.2.2.2.2.1 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.1, which states that further evaluation is required for loss of material 

(spalling, scaling) and cracking due to freeze-thaw in below-grade inaccessible concrete 

areas of Groups 1-3, 5, and 7-9 structures for plants subjected to moderate to severe 

weathering conditions. 

 The staff noted that the GALL Report suggests existing concrete exposed to freeze-thaw 

have an air content of 3 to 6 percent. The air content recommended for concrete 

resistance to freezing and thawing by ACI 201.2R is 4.5 to 7.5 percent for severe 

exposure with a ±1.5 percent tolerance. The GALL Report also suggests a 

water-to-cement ratio between 0.35 and 0.45 for concrete exposed to potential 

freeze-thaw conditions. The staff noted that although an air content was specified for 

the concrete, 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 June 7, 2010, the staff issued RAI 3.5.2.2.2-2 to address compliance of 

the HCGS concrete to recommendations provided in the GALL Report. 

 By letter dated June 29, 2010, the applicant responded and stated that the structural 

concrete mixes at HCGS included fly ash and had a water-to-cement ratio between 0.45 

and 0.51. The applicant explained that although this ratio is outside the GALL Report 

recommended range, concrete inspections during the plant’s operating history have not 

revealed degradation attributed to freeze-thaw. The applicant further explained that 

freeze-thaw damage generally occurs in areas accessible for inspection and any 

freeze-thaw degradation that may occur in the future will be detected in a timely manner 

by the 5-year frequency Structures Monitoring Program inspections. 

 The staff reviewed the applicant’s response and noted that the applicant has no 

site-specific operating experience with concrete freeze-thaw degradation. In addition, 

the credited Structures Monitoring Program visual inspections provide assurance that 

any future degradation will be detected prior to a loss of intended function. Since the 

applicant does not have operating experience related to freeze-thaw degradation, the 

staff finds that the credited AMP is adequate to manage aging during the period of 

extended operation. The staff’s concern in RAI 3.5.2.2.2-2 is resolved. 

 (2) Cracking due to expansion and reaction with aggregates could occur in below-grade 

inaccessible concrete areas for Groups 1-5 and 7-9 structures. 

 In the LRA, the applicant stated that at HCGS, the concrete portions of Groups 1 and 3 

structures is not applicable as concrete specifications required the use of Type II, 

low-alkali cement conforming to ASTM C150, and the structures were designed in 

accordance with ACI 318-71 and constructed in accordance with ACI 301-72. The LRA 
Aging Management Review Results 

 3-451 

also states that the aggregate was tested in accordance with ASTM C289 and 

ASTM C295 to demonstrate that the aggregate was not reactive as noted in ACI 201.2R. 

The LRA further states that inaccessible concrete, if excavated for any reason, will be 

inspected for cracking under the Structures Monitoring Program. 

 The staff reviewed LRA Section 3.5.2.2.2.2.2 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.2, which states that the GALL Report recommends further evaluation 

of inaccessible areas of these groups of structures if the concrete was not constructed in 

accordance with the recommendations in ACI 201.2R-77. GALL Report item III.A1-2 

states that investigations, tests, and petrographic examinations of aggregates performed 

in accordance with ASTM C295-54 or ASTM C227-50 can demonstrate that the 

aggregate is not reactive within the reinforced concrete. If either of these conditions is 

met, the GALL Report notes that aging management is not necessary. 

 The staff found that the HCGS concrete mix design adequately addressed cracking due 

to expansion and reaction with aggregates. Concrete work was designed in accordance 

with ACI 318-713 and constructed in accordance with ACI 301-72. Type II, low-alkali 

content cement was used in the concrete mixes and aggregate materials were evaluated 

in accordance with ASTM C289 and ASTM C295 and found to be nonreactive. 

Therefore, cracking due to expansion and reaction with aggregate in below-grade 

inaccessible concrete areas for Groups 1 and 3 structures are not aging effects for 

concrete elements and no additional plant-specific program is required. 

Recommendations in the GALL Report and criteria in SRP-LR Section 3.5.2.2.2.2.2 

have been met. 

 (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. 

 In the LRA, the applicant stated that the Structures Monitoring Program will be used to 

manage cracks and distortion due to increased stress levels from settlement of Groups 1 

and 3 structures, however, this aging mechanism is insignificant at HCGS. The building 

foundations for the safety-related structures consist of reinforced concrete mats that 

bear on dense soil or the Vincentown Formation. The LRA also states a review of 

operating experience has not identified significant signs of distress due to settlement and 

that since the magnitude of total settlement is small, the differential settlements are 

expected to be smaller. The LRA further states that the condition of accessible and 

above-grade concrete will be used as an indicator for the condition of the inaccessible 

and below-grade structural components and provides reasonable assurance that 

degradation will be detected before a loss of intended function. A dewatering system 

and porous concrete subfoundations are not used at HCGS. 

 The staff reviewed LRA Section 3.5.2.2.2.2.3 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.3, which states that the GALL Report recommends verification of the 

continued functionality of the dewatering system during the period of extended operation 

if the plant’s CLB credits a dewatering system. The GALL Report recommends no 

further evaluation if this activity and these aging effects are included within the scope of 

the applicant’s Structures Monitoring Program. 

 On the basis of its review, the staff determined that cracks and distortion due to 

increased stress levels from settlement and reduction of foundation strength, cracking, 
Aging Management Review Results 

 3-452 

and differential settlement due to erosion of porous concrete subfoundations in 

below-grade inaccessible concrete areas of Groups 1 and 3 structures are not plausible 

aging effects due to the absence of these aging mechanisms. HCGS does not use a 

dewatering system, and there are no porous subfoundations on the site. In addition, the 

applicant monitors the above-grade exposed concrete for the aging effect of cracking or 

distortion due to settlement under the Structures Monitoring Program. The staff’s review 

of the Structures Monitoring Program is documented in SER Section 3.0.3.2.16. The 

staff finds that this program is consistent with the recommendations in the GALL Report 

and is adequate to manage cracks and distortion due to increased stress levels from 

settlement and reduction of foundation strength, cracking, and differential settlement. 

 (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 refers to Table 3.5.1, item 3.5.1-31. In the LRA, the applicant 

stated that for Groups 1 and 3 structures at HCGS, the inaccessible below-grade 

reinforced concrete is subject to an aggressive environment. Groundwater and river 

water were sampled and tested in 2008 and 2009 and the test results revealed that 

although the pH and sulfate values meet the limits considered to be a non-aggressive 

environment according to the GALL Report, the test results for chlorides indicated an 

aggressive environment. The LRA also states that exposed portions of below-grade 

concrete will be examined by the Structures Monitoring Program when excavated for any 

reason, and groundwater chemistry will also be monitored periodically in accordance 

with the enhanced Structures Monitoring Program. Also, the periodic inspections of the 

submerged portions of the service water intake structure will be used as indicators for 

the condition of below-grade structures. The applicant further stated that due to 

groundwater chemistry being bounded by river water chemistry, the use of submerged 

structures as a leading indicator for the potential degradation of below-grade structures 

provides reasonable assurance that degradation of inaccessible structures will be 

detected before a loss of an intended function. In the event inspection of submerged 

structures identifies significant concrete degradations at the service water intake 

structure, corrective actions will be initiated to evaluate the condition of inaccessible 

portions of the Groups 1 and 3 structures and determine if excavation of concrete for 

inspection is warranted. The LRA also states that a review of operating experience has 

not identified significant signs of distress due to aggressive chemical attack or corrosion 

of embedded steel of submerged concrete components. 

 The staff reviewed LRA Section 3.5.2.2.2.2.4 against the criteria in SRP-LR 

Section 3.5.2.2.2.4, which states that the GALL Report recommends further evaluation 

of plant-specific programs to manage these aging effects or mechanisms in inaccessible 

areas of these groups of structures 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), as a minimum the following should be considered: (1) examinations of the 

exposed portions of the below-grade concrete, when excavated for any reason; and 

(2) periodic monitoring of below-grade water chemistry, including consideration of 

potential seasonal variations. Since the applicant does not have definite plans for 

inspections of inaccessible areas and the groundwater is aggressive based on chloride 

values above the GALL Report limit, it is unclear to the staff that this is an adequate 

approach to managing aging of inaccessible concrete structures subjected to aggressive 
Aging Management Review Results 

 3-453 

groundwater. In SER Section 3.0.3.2.16, “Structures Monitoring Program,” the staff 

issued RAI B.2.1.32-1 requesting that the applicant provide additional information to 

demonstrate that the current level of chlorides in the groundwater is not causing 

structural degradation of embedded walls or foundations. A more detailed discussion of 

the issue can be found in that section. 

 (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 refers to Table 3.5.1, item 3.5.1-32. In the LRA, the applicant 

stated that leaching of calcium hydroxide is applicable for a flowing water environment 

that may occur to a limited extent in accessible or inaccessible portions of Groups 1 and 

3 structures. The LRA also states that: (1) the HCGS concrete was designed and 

constructed to ACI and ASTM specifications that meet the intent of ACI 201.2R, 

(2) pozzolans were included in the concrete mixes to reduce its porosity and 

permeability, and (3) operating experience has found that increase in porosity and 

permeability and loss of strength due to leaching of calcium hydroxide is not significant 

and is adequately managed by the Structures Monitoring Program. The LRA further 

states that exposed portions of the below-grade concrete will be examined when 

excavated for any purpose in accordance with the Structures Monitoring Program. 

 The staff reviewed LRA Section 3.5.2.2.2.2.5 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.5, which states that the GALL Report recommends further evaluation 

of this aging effect for inaccessible areas of Groups 1-3, 5 and 7-9 structures if concrete 

was not constructed in accordance with the recommendations in ACI 201.2R-77. 

 On the basis of its review, the staff finds that increase in porosity and permeability, and 

loss of strength due to leaching of calcium hydroxide in below-grade inaccessible 

concrete areas of Groups 1 and 3 structures is not a plausible AERM because the 

concrete structures were designed and constructed in accordance with ACI codes that 

enhance concrete’s resistance to leaching. In addition, exposed portions of the 

below-grade concrete will be examined when excavated for any purpose. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2.2 criteria. For those line items that apply to LRA Section 3.5.2.2.2.2, 

the staff determines that the LRA is consistent with the GALL Report and the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-454 

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. LRA 

Section 3.5.2.2.2.3 refers to Table 3.5.1, item 3.5.1-33. In the LRA, the applicant stated that this 

item is not applicable at HCGS. Groups 1 and 3 concrete structures are not subject to general 

area temperatures greater than 150 °F. Group 1 structures (reactor building) are subject to 

normal indoor temperatures not greater than 120 C and outdoor design temperatures of 94 °F. 

Group 3 structures are exposed to normal indoor air temperatures not greater than 115 °F. 

Group 4 structures are exposed to normal indoor temperatures inside the drywell with the bulk 

air temperature inside the drywell limited by the TS and UFSAR supplement to 135 °F during 

normal plant operation with a maximum local air temperature of 194 °F above elevation 

162 feet. Group 5 structures (refuel floor and spent fuel storage pool) are part of the reactor 

building and are exposed to normal indoor air temperatures not greater than 104 °F. The LRA 

further states that the spent fuel pool temperature is maintained at a maximum of 135 °F under 

normal operating conditions. Groups 1, 3, and 4 concrete structural components are not 

subjected to temperatures greater than 200 °F with process piping operating at temperatures 

greater than 200 °F insulated where it passes through penetrations to reduce the concrete 

temperature to less than 200 °F. Plant operating experience has not identified general and local 

elevated temperature as a concern. 

The staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.2.3, 

which states that reduction of strength and modulus of concrete due to elevated temperatures 

may occur in PWR and BWR Groups 1-5 concrete structures. ACI 349-85 specifies the 

concrete temperature limits for normal operation or any other long-term period and states that 

general area temperatures shall not exceed 65 C (150 °F) except for local areas that are 

permitted to have temperatures not to exceed 93 C (200 °F). The GALL Report recommends 

further evaluation of a plant-specific program if any portion of the safety-related and other 

concrete structures exceed these limits. 

The staff noted that the LRA states that Groups 1, 3, 4, and 5 concrete elements do not exceed 

temperature limits associated with aging degradation due to elevated temperature (i.e., concrete 

general area temperatures are less than 150 °F and local area temperatures are less 

than 200 °F) and Group 2 structures do not exist at HCGS. On the basis of its review, the staff 

finds that reduction in strength and modulus of elasticity due to elevated temperatures in 

concrete areas of Groups 1, 3, 4, and 5 is not a plausible AERM because concrete 

temperatures are below limits specified in ACI 349-85. Therefore, the staff agrees that this is 

not an AERM for these components because the necessary condition does not exist; however, 

these areas will be inspected as noted in the Structures Monitoring Program. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2.3 criteria. For those line items that apply to LRA Section 3.5.2.2.2.3, 

the staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

Aging Management of Inaccessible Areas for Group 6 Structures. The staff reviewed LRA 

Section 3.5.2.2.2.4 against the criteria in SRP-LR Section 3.5.2.2.2.4. 

 (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. 
Aging Management Review Results 

 3-455 

 In the LRA, the applicant stated that the RG 1.127, “Inspection of Water-Control 

Structures Associated with Nuclear Power Plants” Program, as implemented through the 

Structures Monitoring Program, will be used to manage cracking, loss of bond, and loss 

of material due to corrosion of embedded steel in accessible above-grade and 

submerged areas of water-control structures (Group 6 structures). Inaccessible areas of 

Group 6 structures that are below-grade are subject to an aggressive groundwater 

environment. Exposed portions of below-grade concrete will be examined when 

excavated for any reason and groundwater chemistry will be monitored periodically in 

accordance with the Structures Monitoring Program. Also, the enhanced 5-year periodic 

inspections of the submerged portion of the service water intake structure will be used 

as indicators for the condition of below-grade portions of the structures. In the event 

inspection of submerged structures identifies significant concrete degradation at the 

service water intake structure, corrective actions will be initiated to evaluate the condition 

of inaccessible below-grade portions of the Group 6 structures and determine if 

excavation of concrete for inspection is warranted. The LRA further states that the 

Buried Non-Steel Piping Inspection Program will be substituted to manage this AERM for 

reinforced concrete piping and fittings of the service water intake structure. 

 The staff reviewed LRA Section 3.5.2.2.2.4.1 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.1, which states that the GALL Report recommends further evaluation 

of plant-specific programs to manage these aging effects in inaccessible areas if the 

environment is aggressive. 

 The staff’s review of these aging effects for inaccessible concrete elements of Groups 1 

and 3 structures is documented in SER Section 3.5.2.2.2, “Aging Management of 

Inaccessible Areas.” The staff noted that inspections of Group 6 structures are 

performed under the Structures Monitoring Program which is consistent with and 

integrates the elements of the RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” Program. The staff’s reviews of the Structures 

Monitoring and RG 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants” programs are documented in SER Sections 3.0.3.2.16 and 

3.0.3.2.17, respectively. The staff confirmed that Group 6 structures subject to this AMR 

are within the scope of the Structures Monitoring and RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants” programs. Since the 

applicant does not have definite plans for inspections of inaccessible areas and the 

groundwater or river water is aggressive, it is unclear to the staff that this is an adequate 

approach to managing aging of inaccessible concrete structures subjected to aggressive 

groundwater or river water. In SER Section 3.0.3.2.16, “Structures Monitoring Program,” 

the staff issued RAI B.2.1.32-1 requesting that the applicant provide additional 

information to demonstrate that the current level of chlorides in the groundwater is not 

causing structural degradation of embedded walls or foundations. A more detailed 

discussion of the issue can be found in that section. 

 Furthermore, the applicant stated that the Buried Non-Steel Piping Inspection Program 

will be substituted to manage this AERM for reinforced concrete piping and fittings 

through inspections of external surfaces. The staff’s review of the Buried Non-Steel 

Piping Inspection Program is documented in SER Section 3.0.3.3.4. Since this program 

uses opportunistic and focused inspections and at least one opportunistic inspection will 

be performed within 10 years prior to entering the period of extended operation and at 

least one focused inspection will be performed within the first 10 years of extended 

operation, the staff finds that the applicant addressed the AERM adequately for the 

reinforced concrete piping and fittings of the service water intake structure. 
Aging Management Review Results 

 3-456 

 (2) Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

below-grade inaccessible concrete areas of Group 6 structures. 

 LRA Section 3.5.2.2.2.4.2 refers to Table 3.5-1, item 3.5.1-35, and the applicant stated 

that the RG 1.127, Inspections of Water-Control Structures Associated with Nuclear 

Power Plants” Program, as implemented by the Structures Monitoring Program, will be 

used to manage loss of material (spalling, scaling) and cracking due to freeze-thaw in 

accessible areas of water-control structures (Group 6 structures). Group 6 structures 

are located in a region where weathering conditions are considered severe as shown in 

ASTM C33-90, Figure 1. The LRA also states that the concrete for Group 6 structures is 

designed in accordance with ACI 318-71 and constructed in accordance with ACI 

301-72, and the concrete mixes were designed to provide for low permeability and 

adequate air entrainment (3 to 6 percent). The LRA further states that a review of 

operating experience did not identify significant loss of material and cracking due to 

freeze-thaw of reinforced concrete in Group 6 structures and that inaccessible reinforced 

concrete will be inspected, if excavated for any reason, as required by the Structures 

Monitoring Program. 

 The staff reviewed LRA Section 3.5.2.2.2.4.2 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.2, which states that the GALL Report recommends further evaluation 

of this aging effect for inaccessible areas for plants located in moderate to severe 

weathering conditions. 

 The staff’s review for these aging effects for inaccessible concrete elements of Groups 1 

and 3 structures is documented in SER Section 3.5.2.2.2.2.1. The staff noted that 

inspections of accessible Group 6 structures are performed under the Structures 

Monitoring Program which is consistent with and integrates the elements of the RG 

1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” 

Program. The staff’s reviews of the Structures Monitoring and RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants” programs are 

documented in SER Sections 3.0.3.2.16 and 3.0.3.2.17, respectively. GALL Report 

item III.A6-5 suggests that aging management is not necessary if the existing concrete 

has an air content of 3 to 6 percent and a water-to-cement ratio between 0.35 and 0.45 

for concrete exposed to potential freeze-thaw conditions. The staff noted that although 

an air content was specified for the concrete, a water-to-cement ratio was not provided 

for the HCGS concrete as specified in GALL Report item III.A6-5 for concrete located in 

moderate to severe weathering conditions. In SER Section 3.5.2.2.2, “Aging 

Management of Inaccessible Areas,” the staff issued RAI 3.5.2.2.2-2 to address 

compliance of the HCGS concrete to recommendations provided in the GALL Report. A 

more detailed discussion of the staff’s review of this issue can be found in that section. 

 (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 structures. 

 In the LRA, the applicant stated that cracking due to expansion or reaction with 

aggregates is not applicable for inaccessible areas of reinforced concrete of Group 6 

structures because the aggregate materials were tested in accordance with ASTM C289 

and C295 for potential reactivity and refers to Table 3.5.1, item 3.5.1-36. 

 The staff reviewed LRA Section 3.5.2.2.2.4.3 against the criteria in GALL Report 

item III.A6-2 which notes that, according to NUREG-1557, investigations, tests, and 
Aging Management Review Results 

 3-457 

petrographic examinations of aggregates performed in accordance with ASTM C295-54 

can demonstrate that these aggregates do not react within reinforced concrete. The 

staff’s review for cracking due to expansion and reaction with aggregates for 

inaccessible concrete elements of Groups 1 and 3 structures is documented in SER 

Section 3.5.2.2.2.2.2. The staff noted that inspections of Group 6 structures are 

performed under the Structures Monitoring Program which is consistent with and 

integrates the elements of the RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” Program. The staff’s review of the Structures 

Monitoring Program is documented in SER Section 3.0.3.2.16. Since the Group 6 

structures subject to this AERM are within the scope of the RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants” Program and the 

aggregate materials have been tested to demonstrate that they are not reactive, the 

criteria of GALL Report item III.A6-2 have been met. 

 In the LRA, the applicant stated that the reinforced concrete for HCGS Group 6 

structures was designed in accordance with ACI 318-71 and constructed in accordance 

with ACI 301-72 to meet the intent of ACI 201.2R and refers to Table 3.5.1, item 

3.5.1-37. The LRA also states that increase in porosity and permeability and loss of 

strength due to leaching of calcium hydroxide of reinforced concrete in accessible and 

inaccessible areas of water-control structures (Group 6 structures) subject to a flowing 

water environment will be managed by the RG 1.127, “Inspection of Water-Control 

Structures Associated with Nuclear Power Plants” Program, as implemented by the 

Structures Monitoring Program. Leaching is a potential aging mechanism applicable to 

submerged portions of Group 6 structures exposed to flowing water. However, these 

areas are accessible for inspections when dewatered and periodic inspections of the 

submerged reinforced concrete components will be used as a leading indicator for 

inaccessible concrete. Inaccessible concrete will be inspected when excavated for any 

reason, as required under the Structures Monitoring Program. 

 The staff reviewed LRA Section 3.5.2.2.2.4.3 against criteria in SRP-LR 

Section 3.5.2.2.2.4.3, which states that the GALL Report recommends further evaluation 

of inaccessible areas of Group 6 structures for increase in porosity and permeability and 

loss of strength due to leaching of calcium hydroxide if concrete was not constructed in 

accordance with the recommendations in ACI 201.2R-77. The staff’s review for increase 

in porosity and permeability and loss of strength due to leaching of calcium hydroxide for 

inaccessible concrete elements of Groups 1 and 3 structures is documented in SER 

Section 3.5.2.2.2, “Aging Management of Inaccessible Areas.” The staff noted that 

inspections of Group 6 structures are performed under the Structures Monitoring 

Program which is consistent with and integrates the elements of the RG 1.127, 

“Inspection of Water-Control Structures Associated with Nuclear Power Plants” Program. 

The staff’s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. Since the Group 6 structures subject to this AERM are within the 

scope of the RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear 

Power Plants” Program and the concrete was designed and constructed in accordance 

with requirements that meet the intent of ACI 201.2R, the criteria of GALL Report 

item III.A6-6 have been met. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2.4 criteria. For those line items that apply to LRA Section 3.5.2.2.2.4, 

the staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
Aging Management Review Results 

 3-458 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

Cracking Due to Stress-Corrosion Cracking and Loss of Material Due to Pitting and Crevice 

Corrosion. LRA Section 3.5.2.2.2.5 refers to Table 3.5.1, item 3.5.1-38. In the LRA, the 

applicant stated that HCGS does not have Group 7 and 8 stainless steel tank liners and further 

evaluation for the effects of cracking due to SCC and loss of material due to pitting and crevice 

corrosion is not applicable. 

The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR Section 3.5.2.2.2.5, 

which states that cracking due to SCC and loss of material due to pitting and crevice corrosion 

could occur for Groups 7 and 8 stainless steel tank liners exposed to standing water. The GALL 

Report recommends further evaluation of plant-specific programs to manage these aging 

effects. 

The staff noted that LRA Sections 3.5.2.2.2.1 and 3.5.2.2.2.5 state that Groups 7 and 8 

structures, which refer to concrete tanks and missile barriers, and steel tanks and missile 

barriers, respectively, do not exist at HCGS. However, there are several tanks within the scope 

of license renewal so the staff does not understand how the statements in the LRA are 

accurate. To address this issue, the staff issued RAI 3.5.2.2.2-3 by letter dated June 25, 2010. 

The applicant responded by letter dated July 20, 2010, and explained that no tanks with 

stainless steel liners exposed to standing water are within the scope of license renewal. 

Stainless steel and steel tanks that are within the scope of license renewal are addressed as 

components of the applicable mechanical system, not as Groups 7 or 8 structures. The 

applicant revised LRA Sections 3.5.2.2.2.1 and 3.5.2.2.2.5 and Table 3.5.1 to clarify this point. 

The applicant also explained that the skimmer surge tanks were aligned with item 3.3.1-24 

which discusses loss of material of stainless steel components exposed to treated water. The 

GALL Report recommended programs for these components are water chemistry and one-time 

inspection. The applicant has credited both of these programs for aging management of the 

skimmer surge tanks. The applicant further explained that cracking due to SCC is not an 

applicable aging effect for the skimmer surge tanks because the fuel pool water temperature is 

below 140 °F. 

The staff reviewed the applicant’s response and finds it acceptable because it explained that the 

tanks within the scope of license renewal either are not exposed to standing water or aging is 

being managed as part of the applicable mechanical system. For the skimmer surge tank 

components, the staff finds the applicant’s response acceptable because the water temperature 

remains below the threshold for SCC and the GALL Report recommended AMPs are being 

credited to manage loss of material due to pitting and crevice corrosion. The staff’s concern in 

RAI 3.5.2.2.2-3 is resolved. 

Aging of Supports not Covered by the Structures Monitoring Program. The staff reviewed LRA 

Section 3.5.2.2.2.6 against the criteria in SRP-LR Section 3.5.2.2.2.6. 

 (1) Loss of Material Due to General and Pitting Corrosion, for Groups B2-B5 Supports 

 LRA Section 3.5.2.2.2.6.1 refers to Table 3.5.1, item 3.5.1-39. In the LRA, the applicant 

stated that loss of material due to general and pitting corrosion for Groups B2-B5 

supports is covered under the Structures Monitoring Program. 
Aging Management Review Results 

 3-459 

 The staff reviewed LRA Section 3.5.2.2.2.6.1 against the criteria in SRP-LR 

Section 3.5.2.2.2.6, which states that further evaluation is necessary only for structure 

and aging effect combinations not covered by the structures monitoring program. 

 The staff noted that the component support and aging effect combination of loss of 

material due to general and pitting corrosion for Groups B2-B5 supports is managed by 

the Structures Monitoring Program. The staff’s review of the Structures Monitoring 

Program is documented in SER Section 3.0.3.2.16. 

 (2) Reduction in Concrete Anchor Capacity Due to Degradation of the Surrounding 

Concrete for Groups B1-B5 Supports 

 LRA Section 3.5.2.2.2.6.2 refers to Table 3.5.1, item 3.5.1-40. In the LRA, the applicant 

stated that reduction in anchor capacity due to degradation of the surrounding concrete 

for Groups 1-5 supports is covered under the Structures Monitoring Program. 

 The staff reviewed LRA Section 3.5.2.2.2.6.2 against the criteria in SRP-LR 

Section 3.5.2.2.2.6.2, which states that further evaluation is necessary only for structure 

and aging effect combinations not covered by the structures monitoring program. 

 The staff noted that the component support and aging effect combination of reduction in 

anchor capacity due to degradation of surrounding concrete for Groups 1-5 supports is 

managed by the Structures Monitoring Program. The staff’s review of the Structures 

Monitoring Program is documented in SER Section 3.0.3.2.16. 

 (3) Reduction Due to Loss of Isolation Function Due to Degradation of Vibration Isolation 

Elements for Group B4 Supports 

 LRA Section 3.5.2.2.2.6.3 refers to Table 3.5.1, item 3.5.1-41. In the LRA, the applicant 

stated that reduction due to loss of isolation function due to degradation of vibration 

isolation elements for Group B4 supports is covered under the Structures Monitoring 

Program. 

 The staff reviewed LRA Section 3.5.2.2.2.6.3 against the criteria in SRP-LR 

Section 3.5.2.2.2.6.3, which states that further evaluation is necessary only for structure 

and aging effect combinations not covered by the structures monitoring program. 

 The staff noted that the reduction due to loss of isolation function due to degradation of 

vibration isolation elements for Group B4 supports is managed by the Structures 

Monitoring Program. The staff’s review of the Structures Monitoring Program is 

documented in SER Section 3.0.3.2.16. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2.6 criteria. For those line items that apply to LRA Section 3.5.2.2.2.6, 

the staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

Cumulative Fatigue Damage Due to Cyclic Loading. LRA Section 3.5.2.2.2.7 refers to 

Table 3.5.1, item 3.5.1-42. In the LRA, the applicant stated that the CLB contains no fatigue 

analysis for component support members, anchor bolts, and welds of Groups B1.1, B1.2, and 

B1.3 component supports. Therefore, a TLAA is not evaluated in accordance with 

10 CFR 54.21(c) for these components. 
Aging Management Review Results 

 3-460 

The staff reviewed LRA Section 3.5.2.2.2.7 against the criteria in SRP-LR Section 3.5.2.2.2.7, 

which states that fatigue of component support members, anchor bolts, and welds for 

Groups B1.1, B1.2, and B1.3 component supports is a TLAA as defined in 10 CFR 54.3 only if a 

CLB fatigue analysis exists. TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c). The evaluation of this TLAA is addressed separately in Section 4.3, “Metal 

Fatigue Analysis,” of this SER. 

The staff verified that at HCGS, the CLB contains no fatigue analysis for component support 

members, anchor bolts, and welds of Groups B1.1, B1.2, and B1.3 component supports. The 

staff’s evaluation of metal fatigue TLAA is documented in SER Section 4.0. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.2 criteria. For those line items that apply to LRA Section 3.5.2.2.2, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

3.5.2.2.3 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. 

3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.5.2-1 through 3.5.2-13, 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 3.5.2-13, the applicant indicated, via Notes F through J that the 

combination of component type, material, environment, and AERM does not correspond to a 

line 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 line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line 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 line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections. 

LRA Tables 3.5.2-1, 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-8, 3.5.2-9, and 3.5.2-12 were revised as a 

result of the response to RAI B.2.1.12-01, dated June 14, 2010. The revision added AMR items 

in these tables to reference the applicant’s Bolting Integrity Program to manage the aging for 

bolting AMR items. Existing bolting AMR items which reference other AMPs are used in 

conjunction with the added bolting AMR items to properly manage aging for bolting components. 
Aging Management Review Results 

 3-461 

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.4. The staff notes that the Bolting Integrity Program is supplemented by other 

AMPs including but not limited to: the Structures Monitoring, Inspection of Overhead Heavy 

Load and Light Load (Related to Refueling) Handling Systems, External Surfaces Monitoring, 

and Buried Piping Inspection programs. These other AMPs supplement the Bolting Integrity 

Program by implementing the requirements of the Bolting Integrity Program for pressure 

retaining bolted joints, component support bolting, and structural bolting within the scope of 

license renewal. The applicant’s action accurately adds the related line items to reference the 

Bolting Integrity Program, however, the technical evaluations documented in the SER do not 

change since the management of the aging effect will still be implemented by the AMP identified 

in conjunction with the Bolting Integrity Program. 

3.5.2.3.1 Containment, Structures, and Component Supports – Auxiliary Boiler Building – 

Summary of Aging Management Evaluation – LRA Table 3.5.2-1 

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the 

auxiliary boiler building component groups. 

In LRA Table 3.5.2-1, the applicant stated that aluminum bolting exposed to indoor air are being 

managed for loss of preload due to self-loosening by the Structures Monitoring Program. The 

AMR line items cite generic note H for this item, indicating that this aging effect is not in the 

GALL Report for this component, material, and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because aluminum bolting has similar aging effects as other structural bolting materials. The 

staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff finds that the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because the program conducts visual inspections of 

exposed bolting surfaces for loss of material due to corrosion, loose nuts, missing bolts, or other 

indications of loss of preload and relies on plant procedures that are based on the guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” 

For component type “Piles,” the applicant stated that concrete encased in steel does not have 

AERMs and does not require an AMP. This item references Note G and plant-specific Note 4 

which states, “Concrete encased in steel is protected from environments that promote age 

related degradations.” The applicant stated that these components have the intended function 

of structural support. The LRA states that degradation of piles or foundation mats will manifest 

in settlement distortion or cracking, and accessible concrete examinations will detect cracks and 

distortion of the structures. The LRA further states that studies have shown that steel piles 

driven into undisturbed natural soil are not appreciably affected by corrosion due to the oxygen 

deficiency in soil at a few feet below grade. Piles driven into disturbed soil have been shown to 

experience only minor to moderate corrosion. In either case, the observed loss of material due 

to corrosion was not considered significant enough to impact the intended function of the piles, 

which is consistent with NUREG-1557. The staff reviewed the GALL Report and verified that it 

includes no AMR item for this component, material, and environment combination. Since the 

concrete is encased in steel and, therefore, in a protected environment, and auxiliary boiler 

building concrete foundation structures are monitored under the Structures Monitoring Program 

for cracks and distortion due to increased stress levels from settlement, the staff finds that a 

separate AMP for concrete piles encased in steel is not required. The staff’s review of the 

Structures Monitoring Program is documented in SER Section 3.0.3.2.16. 
Aging Management Review Results 

 3-462 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.2 Containment, Structures, and Component Supports – Auxiliary Building Control and 

Diesel Generator Area – Summary of Aging Management Evaluation – LRA Table 3.5.2-2 

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the 

auxiliary building control and diesel generator area component groups. 

In LRA Table 3.5.2-2, the applicant stated that aluminum bolting exposed to indoor air are being 

managed for loss of preload due to self-loosening by the Structures Monitoring Program. The 

AMR line items cite generic note H, indicating that this aging effect is not in the GALL Report for 

this component, material, and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because aluminum bolting has similar aging effects as other structural bolting materials. The 

staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff finds that the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because the program conducts visual inspections of 

exposed bolting surfaces for loss of material due to corrosion, loose nuts, missing bolts, or other 

indications of loss of preload and relies on plant procedures that are based on the guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-2, the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 
Aging Management Review Results 

 3-463 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

For one component type, “Penetration Seals,” the applicant proposed to assign grout to the 

Structures Monitoring Program to manage the aging effect of cracking or shrinkage in an air – 

indoor, air – outdoor, or groundwater or soil environment. This item references Note F and 

plant-specific Note 3 which states, “Based on industry standards and guidelines, grout is 

susceptible to cracking due to shrinkage in this environment. However, shrinkage cracking 

occurs early in plant life and is not expected to be significant for the extended period of 

operation. Never the less, the aging effect will be monitored through the Structures Monitoring 

Program.” The applicant stated that these components have the intended functions of flood 

barrier or shelter or protection. The staff’s review of the Structures Monitoring Program is 

documented in SER Section 3.0.3.2.16. The staff finds the applicant’s use of the Structures 

Monitoring Program appropriate because: (1) the program has been enhanced to include 

building penetrations; (2) the program requires visual inspection of penetration seals for 

indications of shrinkage and cracking that will lead to loss of sealing; and (3) concrete is 

inspected for indications of deterioration or distress including evidence of leaching, loss of 

material, cracking, and loss of bond as defined in ACI 201.1R at a frequency of 5 years. The 

staff finds that the applicant addressed the AERM adequately. 

For one component type, “Penetration Seals,” the applicant proposed to assign grout to the 

Structures Monitoring Program to manage the aging effect of loss of material (spalling, scaling), 

cracking or freeze-thaw, and increase in porosity and permeability or aggressive chemical 

attack in an air – outdoor or groundwater or soil environment. This item references Note F and 

plant-specific Note 4 which states, “The aging effects and Aging Management Program 

identified for this material and environment combination are consistent with industry guidance.” 

The applicant stated that these components have the intended functions of either flood barrier 

or shelter or protection. The staff’s review of the Structures Monitoring Program is documented 

in SER Section 3.0.3.2.16. The staff finds the applicant’s use of the Structures Monitoring 

Program appropriate because: (1) the program has been enhanced to include building 

penetrations; (2) the program requires visual inspection of penetration seals for indications of 

shrinkage and cracking that will lead to loss of sealing; and (3) concrete is inspected for 

indications of deterioration or distress including evidence of leaching, loss of material, cracking, 

and loss of bond as defined in ACI 201.1R at a frequency of 5 years. The staff finds that the 

applicant addressed the AERM adequately. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-464 

3.5.2.3.3 Containment, Structures, and Component Supports – Auxiliary Building Service and 

Radwaste Area – 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 

auxiliary building service and radwaste area component groups. 

In LRA Table 3.5.2-3, the applicant stated that aluminum bolting exposed to indoor air is being 

managed for loss of preload due to self-loosening by the Structures Monitoring Program. The 

AMR line items cite generic note H for this item, indicating that this aging effect is not in the 

GALL Report for this component, material, and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because aluminum bolting has similar aging effects as other structural bolting materials. The 

staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff finds that the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because the program conducts visual inspections of 

exposed bolting surfaces for loss of material due to corrosion, loose nuts, missing bolts, or other 

indications of loss of preload and relies on plant procedures that are based on the guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-3, the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 
Aging Management Review Results 

 3-465 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-3, the applicant stated that lead hatches and plugs exposed to indoor air 

have no AERM. The AMR item cites generic note F, indicating that the material is not evaluated 

in the GALL Report for this component, and plant-specific note 3 stating, “Based on plant 

operating experience, there are no aging effects requiring management for this material and 

environment combination.” 

The staff notes that available technical information revealed no AERMs for lead shielding 

materials exposed to indoor air environments (e.g., “Corrosion Basics, An Introduction,” NACE 

Press Book, Second Edition 2006). Therefore, the staff finds the applicant’s determination that 

there are no AERMs for the lead hatches and plugs exposed to indoor air acceptable. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment which are being managed for cracking due to shrinkage by the 

Structures Monitoring Program with generic note F is documented in SER Section 3.5.2.3.2. 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment and being managed for loss of material (spalling, scaling), 

cracking due to freeze-thaw, and increase in porosity and permeability due to aggressive 

chemical attack by the Structures Monitoring Program with generic note F, is documented in 

SER Section 3.5.2.3.2. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.4 Containments, Structures, and Component Supports – Summary of Aging 

Management Evaluation – Component Supports Commodity Group– LRA Table 3.5.2-4 

In LRA Table 3.5.2-4, the applicant stated that the nickel-alloy bolting supports for ASME 

Class 2 and 3 piping and components exposed to flowing water are being managed for loss of 

material due to galvanic corrosion by the ASME Section XI, Subsection IWF Program. The 

AMR line item cites generic note J, indicating that neither the component nor the material and 

environment combination are evaluated in the GALL Report. 

The staff reviewed the associated line item in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because loss of material due to localized corrosion like galvanic corrosion may occur for nickel 

alloys exposed to flowing water such as rainwater. 
Aging Management Review Results 

 3-466 

The staff noted that the nickel-alloy bolting components are made from corrosion resistant base 

metal and are generally not susceptible to loss of material due to most forms of corrosion, but 

galvanic corrosion is a special case. The staff noted that galvanic corrosion is also called 

“two-metal” corrosion because it occurs due to the corrosion potential difference between 

dissimilar metals that are in contact. The staff noted that the flowing water environment can 

provide contact between two metals that are not in physical contact. The GALL Report does 

describe the flowing water environment as “water that is refreshed, and thus having a larger 

impact on leaching; this can be rainwater, raw water, groundwater, or flowing water under a 

foundation.” Therefore, the staff must consider the possibility of loss of material due to galvanic 

corrosion because rainwater can provide electrical connection between different metals. 

The staff’s evaluation of the applicant’s ASME Section XI, Subsection IWF Program is 

documented in SER Section 3.0.3.1.15. The staff noted that the evidence for galvanic corrosion 

of the nickel-alloy bolting components in flowing water would be surface damage similar to that 

which could be found in steel components in other environments. The staff noted that periodic 

visual inspections like those included in the ASME Section XI, Subsection IWF Program are 

capable of detecting signs of corrosion, corrosion byproducts, discoloration on the surface, 

scale or deposits, and pits and surface discontinuities that are indicative of loss of material. The 

staff finds the applicant’s proposal to manage aging using the ASME Section XI, Subsection 

IWF Program acceptable because the program includes periodic visual inspections which are 

proven capable of detecting loss of material. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-2, the applicant stated that the nickel-alloy bolting supports for ASME 

Class 2 and 3 piping and components exposed to flowing water are being managed for loss of 

material due to pitting and crevice corrosion by the ASME Section XI, Subsection IWF Program. 

The AMR line item cites generic note F, indicating that the material for the AMR line item 

component is not evaluated in the GALL Report. 

The staff reviewed the associated line item in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because loss of material due to localized corrosion like pitting and crevice corrosion may occur 

for nickel alloys exposed to flowing water. 

The staff noted that the nickel-alloy bolting components are made from corrosion resistant base 

metal and are generally not susceptible to loss of material due to pitting and crevice corrosion in 

a flowing water environment; however, if the water contains impurities, pitting and/or crevice 

corrosion can occur. The GALL Report describes the flowing water environment as “water that 

is refreshed, and thus having a larger impact on leaching; this can be rainwater, raw water, 

groundwater, or flowing water under a foundation.” Therefore, the staff must consider the 

possibility of loss of material due to pitting and crevice corrosion because rainwater often 

contains impurities. 

The GALL Report does not list nickel-alloy bolting components (supports for ASME Class 2 and 

3 piping and components including spring hangers, guides, and stops) exposed to flowing water 

as susceptible to loss of material due to pitting and crevice corrosion. However, the staff noted 
Aging Management Review Results 

 3-467 

that for carbon and low alloy steel bolting components (GALL AMR item III.B1.2-10), the GALL 

Report recommends managing the loss of material due to general, pitting, and crevice corrosion 

with the ASME Section XI, Subsection IWF Program. The staff noted that the GALL Report for 

the loss of material due to general, pitting, and crevice corrosion of the carbon steel 

components in indoor air would be similar to that which could occur in the nickel-alloy bolting in 

flowing water. 

The staff’s evaluation of the applicant’s ASME Section XI, Subsection IWF Program is 

documented in SER Section 3.0.3.1.15. The staff noted that periodic visual inspections like 

those included in the ASME Section XI, Subsection IWF Program are capable of detecting signs 

of corrosion, corrosion byproducts, discoloration on the surface, scale or deposits, and pits and 

surface discontinuities that are indicative of loss of material. The staff finds the applicant’s 

proposal to manage aging using the ASME Section XI, Subsection IWF Program acceptable 

because the program includes periodic visual inspections which are proven capable of detecting 

loss of material. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-4, the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-4, the applicant stated that carbon steel supports for ASME Class 2 and 3 

piping and components exposed to treated water are being managed for loss of mechanical 

function due to corrosion, distortion, dirt and overload, and fatigue due to vibratory and cyclic 
Aging Management Review Results 

 3-468 

thermal loads by both the ASME Section XI Subsection IWF Program and the Water Chemistry 

Program. The AMR line items cite generic note G, indicating that the environment is not in the 

GALL Report for this component and material. 

The staff’s evaluation of the ASME Section XI, Subsection IWF and Water Chemistry programs 

are documented in SER Sections 3.0.3.1.15 and 3.0.3.2.1, respectively. The staff noted that the 

applicant’s Water Chemistry Program manages loss of mechanical function and fatigue by 

controlling the concentration of contaminants in the water, and the ASME Section XI, 

Subsection IWF Program conducts visual inspections to detect degradation before loss of 

intended functions may occur. The staff finds the applicant’s proposed programs acceptable to 

manage loss of mechanical function and fatigue for ASME Class 2 and 3 piping and component 

carbon steel supports exposed to treated water because control of water chemistry will mitigate 

corrosion while visual inspections will be able to detect loss of any mechanical functions or 

fatigue. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-4, the applicant stated that carbon and low alloy steel supports for ASME 

Class 2 and 3 piping and components exposed to outdoor air and treated water are being 

managed for loss of preload due to self-loosening by the ASME Section XI, Subsection IWF 

Program. The AMR line items for the components exposed to outdoor air cite generic note H, 

indicating that the aging effect is not in the GALL Report for this component, material, and 

environment combination. The AMR line items for the components exposed to treated water 

cite generic note G, indicating that the environment is not in the GALL Report for this 

component and material. 

The staff’s evaluation of the ASME Section XI, Subsection IWF Program is documented in SER 

Section 3.0.3.1.15. The staff noted that the applicant’s ASME Section XI, Subsection IWF 

Program manages loss of preload by conducting visual inspections for missing, detached, or 

loosened bolts and nuts and its design change procedures are based on the guidance in EPRI 

TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff also noted that GALL 

AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and structural bolting be 

managed in accordance with the guidance in EPRI TR-104213. The staff finds the applicant’s 

ASME Section XI, Subsection IWF Program acceptable to manage loss of preload for carbon 

and low alloy steel supports for ASME Class 2 and 3 piping and components because the 

applicant plans to monitor these components using visual inspections and plant procedures for 

bolting installation and selection of materials are based on the guidance in EPRI TR-104213, 

which is consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-4, the applicant stated that carbon steel supports for ASME Class MC 

components exposed to indoor air are being managed for loss of mechanical function due to 
Aging Management Review Results 

 3-469 

corrosion, distortion, dirt and overload, and fatigue due to vibratory and cyclic thermal loads by 

the ASME Section XI, Subsection IWF Program. The AMR line items cite generic note F, 

indicating that the material is not in the GALL Report for this component. 

The staff’s evaluation of the ASME Section XI, Subsection IWF Program is documented in SER 

Section 3.0.3.1.15. The staff noted that the applicant’s ASME Section XI, Subsection IWF 

Program manages loss of mechanical function and fatigue by conducting visual inspections for 

missing, detached, or loosened bolts and nuts; and its design change procedures are based on 

the guidance in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s ASME Section XI, Subsection IWF Program acceptable to manage loss of 

mechanical function due to corrosion, distortion, dirt and overload, and fatigue due to vibratory 

and cyclic thermal loads because the applicant plans to monitor these components using visual 

inspections and plant procedures for bolting installation and selection of materials are based on 

the guidance in EPRI TR-104213, which is consistent with the GALL Report recommendations 

for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-4, the applicant stated that carbon and low alloy steel bolting supports for 

ASME Class MC components exposed to treated water are being managed for loss of preload 

due to self-loosening by the ASME Section XI, Subsection IWF Program. The AMR line items 

cite generic note G, indicating that the environment is not in the GALL Report for this 

component and material. 

The staff’s evaluation of the ASME Section XI, Subsection IWF Program is documented in SER 

Section 3.0.3.1.15. The staff noted that the applicant’s ASME Section XI, Subsection IWF 

Program manages loss of preload by conducting visual inspections for missing, detached, or 

loosened bolts and nuts; and its design change procedures are based on the guidance in the 

EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff also noted that 

GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and structural 

bolting be managed in accordance with the guidance in EPRI TR-104213. The staff finds the 

applicant’s ASME Section XI, Subsection IWF Program acceptable to manage loss of preload 

because the applicant plans to monitor these components using visual inspections and plant 

procedures for bolting installation and selection of materials are based on the guidance in EPRI 

TR-104213, which is consistent with the GALL Report recommendations for management of 

bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-4, the applicant stated that stainless steel bolting for supports for ASME 

Class MC components exposed to treated water are being managed for loss of preload due to 
Aging Management Review Results 

 3-470 

self-loosening by the ASME Section XI, Subsection IWF Program. The AMR line items cite 

generic note G, which indicate that the environment is not addressed in the GALL Report for the 

component and material. 

The staff reviewed the applicant’s ASME Section XI, Subsection IWF Program and its 

evaluation is documented in SER Section 3.0.3.1.15. The staff finds the applicant’s program 

acceptable to manage aging for these components because it performs visual inspections for 

missing, detached, or loosened bolts to detect loss of preload, and it has incorporated industry 

guidance on good bolting practices into its installation procedures. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-4, the applicant stated that stainless steel bolting for supports for ASME 

Class 1, 2 and 3 piping are being managed for loss of preload due to self-loosening by the 

ASME Section XI, Subsection IWF Program. The applicant also stated that stainless steel 

bolting for supports for cable trays, conduit, HVAC ducts, tube track, instrument tubing, and 

non-ASME piping and components exposed to indoor air are being managed for loss of preload 

due to self-loosening by the Structures Monitoring Program. The AMR line items cite generic 

note H, which indicates that the aging effect is not addressed in the GALL Report for the 

component, material, and environment combination. 

The staff reviewed the applicant’s ASME Section XI, Subsection IWF and Structures Monitoring 

programs and its evaluations are documented in SER Sections 3.0.3.1.15 and 3.0.3.2.16, 

respectively. The staff finds the applicant’s proposed programs acceptable to manage loss of 

preload for these components because both programs include visual inspections for missing or 

loosened bolts to detect loss of preload, and they have incorporated industry guidance on good 

bolting practices into the installation procedures. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-471 

3.5.2.3.5 Containment, Structures, and Component Supports – Fire Water Pump House – 

Summary of Aging Management Evaluation – LRA Table 3.5.2-5 

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the 

fire water pump house component groups. 

In LRA Table 3.5.2-5, the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Tables 3.5.2-5 and 3.5.2-6, the applicant stated that fiberglass doors and insulation 

exposed to indoor or outdoor air and fiberglass insulation jacketing (includes wire mesh, tie 

wires, straps and clips) exposed to indoor air have no AERM. For the AMR items in 

Table 3.5.2-5, the applicant cited generic note F, indicating that the material is not addressed in 

the GALL Report for the component and for the AMR items in Table 3.5.2-6 the applicant cited 

generic note J, indicating that neither the component nor the material and environment 

combination is evaluated in the GALL Report. The applicant further cited a plant-specific note 

for these items stating, “Based on plant operating experience, there are no aging effects 

requiring management for this material and environment combination.” 

The staff finds the applicant’s proposal acceptable for the fiber glass insulation and fiberglass 

insulation jacketing (includes wire mesh, tie wires, straps and clips) components exposed to 

indoor or outdoor air because, based on a review of industry operating experience, these 

components in these environments have exhibited no age-related degradation when covered by 

aluminum insulation jacketing (see aluminum insulation jacketing line items in Table 3.5.2-6). 

The staff did not have sufficient information to evaluate the aging effects for the fiberglass doors 

exposed to indoor or outdoor air. By letter dated June 29, 2010, the staff issued 

RAI 3.5.2.3.5-01 requesting that the applicant state whether or not the fiberglass doors are 
Aging Management Review Results 

 3-472 

exposed to direct ultraviolet (UV) lighting or ozone for the indoor application and for the outdoor 

air application, state how the doors are protected from environmental effects such as rain and 

sunlight, or propose how the aging effects of loss of material and change in material properties 

will be managed. 

In its response dated July 16, 2010, the applicant stated that it had inadvertently omitted the 

aging effects of loss of material and change in material properties due to exposure to UV or 

ozone. The applicant also stated that it revised Table 3.5.2-5 to include this aging effect for 

these doors and indicate that the Structures Monitoring Program would be used to manage the 

aging effect. The applicant further stated that its Structures Monitoring Program would be 

revised to require a 5-year inspection of the doors. 

The staff finds the applicant’s response acceptable because the LRA has been corrected to 

reflect that an aging effect would occur due to exposure to UV and ozone and a 5-year visual 

inspection conducted as part of the Structures Monitoring Program would reveal degradation of 

the doors prior to their CLB basis function being affected because the environmental effects 

would not progress at a rapid rate given the relatively low levels of UV and ozone exposure at 

the door locations. The staff’s concern described in RAI 3.5.2.3.5-01 is resolved. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff’s evaluation for grout penetration seals exposed to an air – indoor or air – outdoor 

environment which are being managed for cracking due to shrinkage by the Structures 

Monitoring Program with generic note F is documented in SER Section 3.5.2.3.2. 

The staff’s evaluation for concrete filled steel piles, with no aging effect and no credited AMP 

and referencing generic note F, is documented in SER Section 3.5.2.3.1. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.6 Containment, Structures, and Component Supports – Piping and Component 

Insulation Commodity Group – Summary of Aging Management Evaluation – LRA Table 3.5.2-6 

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the 

piping and component insulation commodity group component groups. 

In LRA Table 3.5.2-6, the staff’s evaluation for fiberglass insulation exposed to outdoor or indoor 

air having no aging effect and no AMP with generic note J, indicating that neither the component 

nor the material and environment combination is evaluated in the GALL Report, is documented 

in SER Section 3.5.2.3.5 

For component type “Insulation,” the applicant stated that “Min-K,” calcium silicate, cellular 

glass, ceramic fiber, fiberglass (molded), and NUKON in an air – indoor or air – outdoor 
Aging Management Review Results 

 3-473 

environment having an intended function of insulation does not have AERMs and does not 

require an AMP. The applicant also stated for component type, insulation jacketing (includes 

wire mesh, tie wires, straps, clips), the fiberglass cloth in an air – indoor environment having an 

intended function of either shelter or protection or structural support also does not have AERMs. 

Both of these items reference Note J and plant-specific Note 1 which states, “Based on plant 

operating experience, there are no aging effects requiring management for this material and 

environment combination.” The LRA also states that the purpose of piping and component 

insulation is to improve thermal efficiency, minimize heat loads on the HVAC systems, provide 

for personnel protection, prevent freezing of heat traced piping, or protect against sweating of 

cold piping and components. Insulation located in areas with safety-related equipment is 

designed to protect nearby safety-related SSC equipment from overheating and maintain its 

structural integrity during postulated design-basis seismic events. Insulation within primary 

containment has been evaluated to ensure that it will not affect the ECCS suction strainers. The 

insulation and insulation jacketing (includes wire mesh, straps, clips) perform an intended 

function and are within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The 

staff reviewed the GALL Report and verified that it includes no AMR item for this component, 

material, and environment combination. Since the piping and component insulation commodity 

group is not classified as a safety-related commodity and the thermal insulation is typically 

passive and long-lived, the staff concludes there are no applicable AERMs for the materials or 

environments identified in the table and that the applicant need not credit an AMP. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.7 Containment, Structures, and Component Supports – Primary Containment – 

Summary of Aging Management Evaluation – LRA Table 3.5.2-7 

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the 

primary containment component groups. 

For one component type “Coating,” in either an air – indoor or air with treated water 

environment, the applicant stated that the paint material is managed for cracking, blistering, 

flaking, peeling, and delamination. This item references Note J. The applicant stated that this 

component has an intended function to maintain adhesion and is examined using the Protective 

Coating Monitoring and Maintenance Program as the primary AMP. The staff’s review of the 

applicant’s Protective Coating Monitoring and Maintenance Program is documented in SER 

Section 3.0.3.1.17. The Protective Coating Monitoring and Maintenance Program manages 

cracking, blistering, flaking, peeling, and delamination of Service Level I coatings in accessible 

areas of the containment structure subjected to an indoor air environment during refueling 

outages through visual inspections performed by qualified individuals knowledgeable in nuclear 

coatings. The applicant also stated that more thorough inspections of suspect areas are 

conducted and, when appropriate, additional testing may be done to characterize the severity of 

observed deficiencies. The Protective Coating Monitoring and Maintenance Program is 

consistent with coating monitoring requirements in RG 1.54 (Revision 1) and GL 98-04 and 

follows guidelines in ASTM D 5163-05(a). Since the Protective Coating Monitoring and 

Maintenance Program is used to verify coating adhesion and thus prevent blockage of the 

suction strainers, the staff finds that the applicant has committed to an appropriate AMP for the 
Aging Management Review Results 

 3-474 

period of extended operation. The staff finds that the applicant addressed the AERM 

adequately. 

For one component type, concrete (interior biological shield), having either a shielding or a 

structural support function, the applicant stated that concrete, concrete (high density), and grout 

(high density) encased in steel has no AERMs and does not require an AMP. The applicant 

also stated for component type “Doors,” the boron concrete in an encased in steel environment 

having an intended function of shielding also does not have AERMs and an AMP is not 

required. These items references either Note F or Note G and plant-specific Note 4 which 

states, “Concrete or Concrete (High Density) or Grout (High Density) or Boron Concrete 

encased in steel is protected from environments that promote age related degradation.” The 

staff reviewed the GALL Report and verified that it includes no AMR item for this component, 

material, and environment combination. Since the concrete is encased in steel and, therefore, 

in a protected environment and the LRA states that concrete structural components are not 

subject to general area temperatures greater than 150 °F or local area temperatures greater 

than 200 °F, the staff finds that the concrete is not subjected to AERMs that would diminish its 

capacity to meet its intended function of shielding or structural support and that the applicant 

need not credit an AMP. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.8 Containment, Structures, and Component Supports – Reactor Building – Summary of 

Aging Management Evaluation – LRA Table 3.5.2-8 

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the 

intake screen and pump house component groups. 

In LRA Table 3.5.2-8, the applicant stated that aluminum bolting exposed to indoor air is being 

managed for loss of preload due to self-loosening by the Structures Monitoring Program. The 

AMR line items cite generic note H for this item, indicating that this aging effect is not in the 

GALL Report for this component, material, and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because, aluminum bolting has similar aging effects as other structural bolting materials. The 

staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff finds that the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because the program conducts visual inspections of 

exposed bolting surfaces for loss of material due to corrosion, loose nuts, missing bolts, or other 

indications of loss of preload and relies on plant procedures that are based on the guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-475 

In LRA Table 3.5.2-8, the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

For component types “Concrete (interior) and Hatches or Plugs,” the applicant stated that 

reinforced concrete encased in steel having a shielding or structural support function has no 

AERMs and does not require an AMP. This item references Note G and plant-specific Note 3 

which states, “Concrete encased in steel is protected from environments that promote age 

related degradations.” The staff reviewed the GALL Report and verified that it includes no AMR 

item for this component, material, and environment combination. Since the concrete is encased 

in steel and, therefore, in a protected environment in the reactor building and the LRA states 

that concrete structural components are not subject to general area temperatures greater than 

150 °F or local area temperatures greater than 200 °F, the staff finds that the concrete is not 

subjected to AERMs that would diminish its capacity to meet its intended function of structural 

support and that the applicant need not credit an AMP. 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment which are being managed for loss of material (spalling, 

scaling), cracking due to freeze-thaw, and increase in porosity and permeability due to 

aggressive chemical attack by the Structures Monitoring Program with generic note F is 

documented in SER Section 3.5.2.3.2. 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment which are being managed for cracking due to shrinkage by the 

Structures Monitoring Program with generic note F is documented in SER Section 3.5.2.3.2. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 
Aging Management Review Results 

 3-476 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.9 Containment, Structures, and Component Supports – Service Water Intake Structure 

– Summary of Aging Management Evaluation – LRA Table 3.5.2-9 

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the 

service water intake structure component groups. 

For component type “Bolting (Structural)” in an air – indoor, air – outdoor, or water flowing 

environment, the applicant stated that aluminum bolting, carbon and low alloy steel bolting, and 

galvanized steel bolting having an intended function of structural support is being managed for 

loss of preload due to self-loosening by the RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” Program. This item references Note H and 

plant-specific Note 1 which states: 

Based on industry standards and operating experience age related loss of 

preload due to self-loosening of structural bolting could be caused by vibration, 

flexing of the joint or cyclic shear loads that could occur in any environment. 

However, these causes are considered in the design of structural connections 

and eliminated by the initial preload bolt torquing. Thus, loss of preload due to 

self-loosening of structural bolting is not significant and will not impact structural 

intended functions. Never the less, loss of preload due to self-loosening will be 

monitored through the Structures Monitoring Program. 

The staff’s review of the RG 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants” Program is documented in SER Section 3.0.3.2.17. The staff finds the 

applicant’s use of the RG 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants” Program appropriate because the program: (1) manages loss of material 

and loss of preload for steel and metal components; (2) monitors accessible surfaces on a 

frequency of 5 years; (3) has been enhanced to include inspection of SCs submerged in water 

at a frequency of 5 years; (4) is implemented through the Structures Monitoring Program which 

monitors exposed surfaces of bolting for loss of material due to corrosion, loose nuts, missing 

bolts, or other indications of loss of preload; and (5) the program incorporates procedures based 

on EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide,” to ensure proper 

specification of bolting material, lubricant, and installation torque. The staff finds that the 

applicant addressed the AERM adequately. 

For component types “Concrete (above- and below-grade exterior), Concrete Foundation, and 

Concrete (interior)” in a water-flowing or groundwater or soil environment the applicant stated 

that the reinforced concrete having an intended function of either flood barrier, missile barrier, 

shelter or protection, structural support, or direct flow is managed for: (1) cracking, loss of bond, 

and loss of material (spalling and scaling) due to corrosion of embedded steel; and (2) increase 

in porosity and permeability, cracking, loss of material (spalling or scaling) due to aggressive 

chemical attack, by the RG 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants” Program. This item references Note H and plant-specific Note 2 which 

states, “The aging effects and Aging Management Program identified for this material and 

environments combination are consistent with industry guidance.” The LRA states that the 

Structures Monitoring Program is used to implement the RG 1.127, “Inspection of Water-Control 

Structures Associated with Nuclear Power Plants” Program. The staff’s review of the applicant’s 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” 

Program is documented in SER Section 3.0.3.2.17. The staff finds the applicant’s use of the 
Aging Management Review Results 

 3-477 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” 

Program appropriate because the program: (1) manages reinforced concrete members for loss 

of material, cracking, and change in material properties; (2) has been enhanced to visually 

inspect water-control structures, including SCs submerged in water, on a frequency of 5 years; 

and (3) is based on guidance provided in RG 1.127 and ACI 349.3R. The staff finds that the 

applicant addressed the AERM adequately. 

For component type “Ice Barrier,” in either an air – outdoor or water flowing environment the 

applicant stated that the treated wood is managed for change in material properties, loss of 

material due to moisture damage, and insect damage by the Structures Monitoring. This item 

references Note J. The LRA states that these components have the intended function of shelter 

or protection and are in the form of treated wood that is designed to prevent ice blockage of the 

service water intake structure. The design of the ice barriers incorporates marine dock bumpers 

to reduce impact load on the structure in the event barges or ships drift into the vicinity of the 

intake structure. The staff’s review of the applicant’s Structures Monitoring Program is 

documented in SER Section 3.0.3.2.16. Since the Structures Monitoring Program has been 

enhanced to monitor wooden components for change in material properties and loss of material 

due to insect damage and moisture damage, and visual inspections are conducted on a 

frequency not to exceed 5 years, the staff finds that the applicant has committed to an 

appropriate AMP for the period of extended operation. The staff finds that the applicant 

addressed the AERM adequately. 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment which are being managed for loss of material (spalling, 

scaling), cracking due to freeze-thaw, and increase in porosity and permeability due to 

aggressive chemical attack by the Structures Monitoring Program with generic note F is 

documented in SER Section 3.5.2.3.2. 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment which are being managed for cracking due to shrinkage by the 

Structures Monitoring Program with generic note F is documented in SER Section 3.5.2.3.2. 

The staff’s evaluation for concrete filled steel piles, with no aging effect and no credited AMP 

and referencing generic note G, is documented in SER Section 3.5.2.3.1. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.10 Containment, Structures, and Component Supports –Shoreline Protection and Dike– 

Summary of Aging Management Evaluation – LRA Table 3.5.2-10 

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for 

the shoreline protection and dike component groups. 

For component type “Earthen Water-Control Structures or Embankments (dikes)” in an air – 

outdoor environment, the applicant stated that soil, rip-rap, sand, and gravel having an intended 

function of shelter or protection are managed for loss of material, loss of form due to erosion, 

settlement, sedimentation, frost action, waves, currents, surface runoff, and seepage by the RG 
Aging Management Review Results 

 3-478 

1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” Program. 

This item references Note G and plant-specific Notes 1 and 2. Plant-specific Note 1 states, 

“Based on industry standards and guidelines, earthen water-control structures are susceptible to 

loss of material and loss of form in Air-Outdoor environment.” Plant-specific Note 2 states, RG 

1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” is the 

applicable aging management program for this component.” The LRA states that the RG 1.127, 

“Inspection of Water-Control Structures Associated with Nuclear Power Plants” Program is 

implemented through the Structures Monitoring Program. The staff’s review of the applicant’s 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants” and 

the Structures Monitoring programs and is documented in SER Section 3.0.3.2.17 and 

3.0.3.2.16, respectively. Since the RG 1.127, “Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” Program is based on guidance provided in RG 1.127 

that addresses aging effects noted above, and is implemented through the Structures 

Monitoring Program that conducts visual inspections on a frequency not to exceed 5 years of 

the earthen structures associated with water-control structures for loss of material and loss of 

form, the staff agrees that the applicant has committed to an appropriate AMP for the period of 

extended operation. The staff finds that the applicant addressed the AERM adequately. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.2.3.11 Containment, Structures, and Component Supports – Switchyard – Summary of 

Aging Management Evaluation – LRA Table 3.5.2-11 

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the switchyard component groups. 

In LRA 3.5.2-11 the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 
Aging Management Review Results 

 3-479 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff’s evaluation for concrete filled steel piles, with no aging effect and no credited AMP 

and referencing generic note G, is documented in SER Section 3.5.2.3.1. 

In LRA Table 3.5.2-11, the applicant stated that polyvinyl chloride (PVC) conduit exposed to 

concrete has no AERM and that for this component, material, environment combination, no 

AMP is needed. The AMR line items cite generic note J, indicating that neither the component 

nor the material and environment combination is evaluated in the GALL Report. The staff 

reviewed the GALL Report and confirmed that neither the conduit nor PVC is included therein. 

For these AMR results, the applicant also cited plant-specific note 2 stating that the PVC is 

encased in concrete and has no aging effects for the identified environment. The staff notes 

that given the component’s switchyard location with potential proximity to high-voltage 

equipment or exposure to sunlight, PVC components could be susceptible to known stressors 

such as UV light or ozone. The staff finds the applicant’s determination that no AMP is needed 

acceptable because given that the PVC pipe is encased in concrete and the material will not be 

exposed to significant UV light or ozone. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment AERM and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging 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). 

3.5.2.3.12 Containment, Structures, and Component Supports – Turbine Building – Summary 

of Aging Management Evaluation – LRA Table 3.5.2-12 

The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for 

the turbine building component groups. 

In LRA Table 3.5.2-12, the applicant stated that aluminum bolting exposed to indoor air is being 

managed for loss of preload due to self-loosening by the Structures Monitoring Program. The 

AMR line items cite generic note H for this item, indicating that this aging effect is not in the 

GALL Report for this component, material, and environment combination. 

The staff reviewed the associated line items in the LRA and confirmed that the applicant has 

identified the correct aging effects for this component, material, and environment combination 

because, aluminum bolting has similar aging effects as other structural bolting materials. The 

staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff finds that the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because the program conducts visual inspections of 

exposed bolting surfaces for loss of material due to corrosion, loose nuts, missing bolts, or other 

indications of loss of preload and relies on plant procedures that are based on the guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” 
Aging Management Review Results 

 3-480 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

In LRA Table 3.5.2-12, the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment which are being managed for loss of material (spalling, 

scaling), cracking due to freeze-thaw, and increase in porosity and permeability due to 

aggressive chemical attack by the Structures Monitoring Program with generic note F is 

documented in SER Section 3.5.2.3.2. 

The staff’s evaluation for grout penetration seals exposed to an air – indoor, air – outdoor, or 

groundwater or soil environment which are being managed for cracking due to shrinkage by the 

Structures Monitoring Program with generic note F is documented in SER Section 3.5.2.3.2. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-481 

3.5.2.3.13 Containment, Structures, and Component Supports – Yard Structures – Summary of 

Aging Management Evaluation – LRA Table 3.5.2-13 

The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations for 

the yard structures component groups. 

In LRA Table 3.5.2-13, the applicant stated that galvanized, carbon, and low alloy steel bolting 

exposed to outdoor air is being managed for loss of preload due to self-loosening by the 

Structures Monitoring Program. The AMR line items cite generic note H, indicating that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination. 

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.16. The staff noted that the applicant’s Structures Monitoring Program manages 

loss of preload by conducting visual inspections of exposed bolting surfaces to determine if 

there is loss of material, loose nuts, missing bolts, or other indications of loss of preload; and 

that the procedures for installation and selection of materials are based on industry guidance 

contained in EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide.” The staff 

also noted that GALL AMP XI.M18, “Bolting Integrity,” recommends that pressure retaining and 

structural bolting be managed in accordance with the guidance in EPRI TR-104213. The staff 

finds the applicant’s Structures Monitoring Program acceptable to manage loss of preload for 

galvanized, carbon, and low alloy steel bolting exposed to indoor air because the applicant 

plans to monitor these components using visual inspections and plant procedures for bolting 

installation and selection of materials are based on guidance in EPRI TR-104213, which is 

consistent with the GALL Report recommendations for management of bolting. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff’s evaluation for polyvinyl chloride conduit embedded in concrete with no aging effect 

and no credited AMP and referencing generic note J, is documented in SER Section 3.5.2.3.11. 

The staff’s evaluation for concrete filled steel piles, with no aging effect and no credited AMP 

and referencing generic note G, is documented in SER Section 3.5.2.3.1. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that, 

the effects of aging for the structures and component supports within the scope of license 

renewal and subject to an AMR will be adequately managed so that the intended function(s) will 
Aging Management Review Results 

 3-482 

be maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
Aging Management Review Results 

 3-483 

3.6 Aging Management of Electrical and Instrumentation and Control

The following information documents the staff’s review of the applicant’s AMR results for the 

electrical and instrumentation and control (I&C) components and component groups of: 

● cable connections (metallic parts) 

● fuse holders – metallic clamp 

● high-voltage insulators 

● insulated cables and connections 

● metal enclosed bus 

● switchyard bus and connections, transmission conductors and connections 

3.6.1 Summary of Technical Information in the Application 

LRA Section 3.6 provides a summary comparison of the applicant’s AMRs with those evaluated 

in the GALL Report for the electrical components, I&C components and component groups. 

The applicant stated that electrical penetrations are not subject to their own AMR in this section 

in that they are addressed: (1) as a TLAA in the EQ program, (2) as part of the insulated cables 

and connections commodity group, and (3) in the primary containment AMR (Table 3.5.2-7). 

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 discussion 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 since the issuance of the GALL Report. 

3.6.2 Staff Evaluation 

The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the electrical 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). 

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 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. 
Aging Management Review Results 

 3-484 

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 

environmental 

qualification (EQ) 

requirements 

(3.6.1-1) 

Degradation due 

to various aging 

mechanisms 

Environmental 

Qualification of 

Electric 

Components 

Yes TLAA Environmental 

Qualification 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 Report 

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 

Used In 

Instrumentation 

Circuits Not 

Subject to 

10 CFR 50.49 

EQ Requirements 

No Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

EQ Requirements 

Used In 

Instrumentation 

Circuits 

Consistent with 

GALL Report 

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, water 

trees 

Inaccessible 

Medium Voltage 

Cables Not 

Subject to 

10 CFR 50.49 

EQ Requirements 

No Inaccessible 

Medium Voltage 

Cables Not Subject 

to 10 CFR 50.49 

EQ Requirements 

Consistent with 

GALL Report 
Aging Management Review Results 

 3-485 

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

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 Not applicable Not applicable to 

BWRs 

Fuse Holders (Not 

Part of a Larger 

Assembly): 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 No Not applicable Not applicable to 

HCGS 

Metal enclosed bus - 

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 Report 

Metal enclosed bus - 

insulation, insulators 

(3.6.1-8) 

Reduced 

insulation 

resistance and 

electrical failure 

due to various 

physical, 

thermal, 

radiolytic, 

photolytic, and 

chemical 

mechanisms 

Metal Enclosed 

Bus 

No Metal Enclosed Bus Consistent with 

GALL Report 

Metal enclosed bus - 

enclosure assemblies 

(3.6.1-9) 

Loss of Material/ 

General 

Corrosion 

Structures 

Monitoring 

Program 

No Not applicable Not applicable to 

HCGS (See SER 

Section 3.6.2.1.1)

Metal enclosed bus - 

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 Report 
Aging Management Review Results 

 3-486 

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-voltage 

insulators 

(3.6.1-11) 

Degradation of 

insulation quality 

due to presence 

of any salt 

deposits and 

surface 

contamination; 

loss of material 

caused by 

mechanical wear 

due to wind 

blowing on 

transmission 

conductors 

A plant-specific 

AMP is to be 

evaluated. 

Yes High Voltage 

Insulators 

Consistent with 

GALL Report 

(See SER 

Section 3.6.2.2) 

Transmission 

conductors and 

connections; 

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 

HCGS (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 

Environmental 

Qualification 

Requirements 

No Electrical Cable 

Connections Not 

Subject To 

10 CFR 50.49 

Environmental 

Qualification 

Requirements 

Consistent with 

GALL Report 

Fuse Holders (Not 

Part of a Larger 

Assembly) - 

insulation material 

(3.6.1-14) 

None None No None Consistent with 

GALL Report 

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 
Aging Management Review Results 

 3-487 

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 AMR Results That Are 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 Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements 

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements 

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used 

in Instrumentation Circuits 

• Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 EQ Requirements 

• Metal Enclosed Bus 

• Structures Monitoring Program 

In LRA Table 3.6.1, the applicant summarizes AMRs for the electrical and instrumentation and 

controls 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 the GALL Report does not recommend further 

evaluation, the staff’s review determined whether the plant-specific components of these GALL 

Report component groups were bounded by the GALL Report evaluation. 

The applicant noted for each AMR line item how the information in the tables aligns with the 

information in the GALL Report. The staff reviewed those AMRs with notes A through E 

indicating how the AMR is consistent with the GALL Report. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, the staff did verify that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. 

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the 

system, components, materials, and environments; (b) stated that the applicable aging effects 

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the 

electrical and I&C components that are subject to an AMR. On the basis of its review, the staff 

determines that, for AMRs not requiring further evaluation, as identified in LRA Table 3.6.1, the 

applicant’s references to the GALL Report are acceptable, and no further staff review is 

required. 
Aging Management Review Results 

 3-488 

The staff evaluated the applicant’s claim of consistency with the GALL Report. The staff also 

reviewed information pertaining to the applicant 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 has demonstrated that the effects of aging for these components 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.6.2.1.1 AMR Results Identified as Not Applicable 

LRA Table 3.6-1, item 3.6.1-9 addresses aging effect of loss of material caused by the 

mechanisms of pitting and crevice corrosion for aluminum metal enclosed bus enclosure 

assemblies exposed to indoor air and stated that there is no AERM and no AMP is 

recommended. In LRA Table 3.5-1, item 3.5.1-58, the applicant stated that the galvanized steel 

and aluminum support members, welds, bolted connections, and support anchorages to building 

structure exposed to indoor air for the material and environment combination do not have 

AERMs. The applicant also stated that no AMPs are applicable to the aluminum items exposed 

to indoor air for the electrical commodities system associated with this item number. The GALL 

Report item III.B5-2, which corresponding to Table 3.5.1, item 3.5.1-58, recommends no AMP 

for this component group and, therefore, the staff finds the applicant’s determination acceptable. 

3.6.2.2 AMR Results That Are 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 and provides information concerning 

how it will manage the following aging effects: 

● electrical equipment subject to EQ 

● 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, and increased resistance of connection due to oxidation or loss of preload 

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 LRA Table 3.6.1. The 

staff also reviewed applicant’s evaluation to determine whether it adequately addressed the 

issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.6.2.2. The staff’s review of the applicant’s 

further evaluation follows. 

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification 

LRA Section 3.6.2.2.1 refers to Table 3.6.1, item 3.6.1-1 and the applicant provides an 

evaluation of EQ TLAAs. SER Section 4.4 documents the staff’s review of the applicant’s 

evaluation of this TLAA. 
Aging Management Review Results 

 3-489 

3.6.2.2.2 Degradation of Insulator Quality Due to Presence of Any Salt Deposits and Surface 

Contamination, and Loss of Material Due to Mechanical Wear 

LRA Section 3.6.2.2.2 refers to Table 3.6.1, item 3.6.1-11. LRA Section 3.6.2.2.2 addresses 

degradation of insulator quality due to salt deposits or surface contamination and loss of 

material due to mechanical wear. The applicant stated that the high-voltage insulators 

evaluated for HCGS are those used to support in-scope, uninsulated, high-voltage electrical 

commodities such as transmission conductors and switchyard bus. The supported commodities 

are those credited for supplying power to in-scope components for recovery of offsite power 

following an SBO. The majority of insulators within the scope of license renewal at HCGS is 

configured vertically and is designed with an increased creepage distance that is able to 

withstand “heavy to very heavy” pollution severity levels. Vertical insulators with increased 

creepage distance are less susceptible to flashover due to surface contamination. Horizontal 

overhead transmission line insulators are angled to form various “string” configurations, making 

them susceptible to surface contamination. 

The applicant also stated that HCGS is located in a rural area, not near heavy industry that 

would provide a source for contaminants, and is not in close proximity to the Atlantic Ocean. 

The station is located at the end of the Delaware River (at the head of Delaware Bay), 50 miles 

from the Atlantic Ocean. Therefore, HCGS is not considered to be a seacoast plant, where salt 

spray is prevalent. The applicant stated that site-specific operating experience has shown that 

flashover of insulators due to contamination from salt spray is an applicable aging mechanism 

that requires management. One plant-specific event occurred at HCGS in September 2003, 

when Hurricane Isabel passed a considerable distance to the south and west of the site. Strong 

winds with gusts in excess of 60 mph caused switchyard insulators to become coated with salt. 

The applicant stated that it will implement a plant-specific High Voltage Insulators Program to 

detect the buildup of surface contamination on high-voltage insulators in the HCGS Switchyard 

and the Salem-HCGS 500-kV cross-connection (the 5037 line). 

The applicant stated that mechanical wear is an aging effect for strain and suspension 

insulators in that they are subject to movement. Movement of the insulator can be caused by 

wind blowing the supported transmission conductor, causing it to swing from side to side. The 

applicant also stated that if this swing is frequent enough, it could cause wear in the metal 

contact points of the insulator string and between an insulator and the supporting hardware. 

Although this mechanism is possible, the applicant stated that experience has shown that the 

transmission conductors do not normally swing and that when they do, due to substantial wind, 

they do not continue to swing for very long once the wind has subsided. Wind loading that can 

cause a transmission line and insulators to sway is considered in the design and installation. 

The applicant further stated that, although rare, surface rust of the metallic cap may form where 

the galvanized coating is burned off due to flashover from lightning strikes. Surface rust is not a 

significant concern and would not cause a loss of intended function if left unmanaged for the 

period of extended operation. The applicant also stated that wear and surface rust has not 

been identified during routine switchyard inspections. 

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 
Aging Management Review Results 

 3-490 

Report recommends further evaluation of a plant-specific AMP to ensure that these aging 

effects are adequately managed. 

The staff noted various airborne materials such as dust, salt and industrial effluents can 

contaminate insulator surfaces. However, the buildup of surface contamination is gradual and 

in most areas such contamination is washed away by rain; the glazed insulator surface aids this 

contamination removal. Surface contamination can be a problem in areas where the greatest 

concentration of airborne particles such as near facilities that discharge soot or near the sea 

coast where salt spray is prevalent. Plant-specific operating experience at HCGS has shown 

that flashover of high-voltage insulator due to salt spray is an applicable aging mechanism that 

requires management. As described above, one plant-specific event occurred at HCGS in 

September 2003, when Hurricane Isabel passed a considerable distance to the south and west 

of the site. Strong winds with gusts in excess of 60 mph caused switchyard insulators to 

become coated with salt. The applicant proposed a plant-specific High Voltage Insulator 

Program to manage the buildup of salt deposits on high-voltage insulators. The staff evaluated 

this program in Section 3.0.3 of the SER. The staff determined that this AMP is acceptable 

because visual inspection is appropriate to inspect surface contamination for salt deposit. 

The staff determined that although loss of material of insulators due to mechanical wear is 

possible, wind loading that can cause a transmission line and insulators to vibrate or sway is 

considered in HCGS’s design and installation. Surface rust is not a significant aging effect 

because it would not cause a loss of intended function for insulation if left unmanaged for the 

period of extended operation. In addition, the applicant has not identified any wear or surface 

rust of insulators during routine inspections. Based on its review, the staff finds that mechanical 

wear or surface rust aging effect of high-voltage insulators is not an AERM. 

Based on the programs identified above, the staff concludes that the applicant has met the 

SRP-LR Section 3.6.2.2.2 criteria. For those line items that apply to LRA Section 3.6.2.2.2, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.6.2.2.3 Loss of Material Due to Wind–Induced Abrasion and Fatigue, Loss of Conductor 

Strength Due to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss 

of Preload 

In LRA Section 3.6.2.2.3, the applicant stated that the transmission conductors and connections 

evaluated for HCGS are those credited for supplying power to in-scope components for 

recovery of offsite power following an SBO. The applicant also stated that aging management 

activities regarding loss of conductor strength due to corrosion for HCGS transmission 

conductors are not required for the period of extended operation because the HCGS 

transmission conductors are not susceptible to corrosion. This aging effect refers to 

Table 3.6.1, item 3.6.1-13. The in-scope transmission conductors at HCGS are 2493 MCM 

54/37 aluminum conductor, aluminum-alloyed reinforced (ACAR) overhead electrical 

conductors. Each phase has two conductors. These transmission conductors are 

approximately 1.8 inches in diameter and are configured with 37 aluminum-alloyed conductor 

wire strands wrapped by 54 aluminum conductor wire strands. The applicant further stated that 

PSE&G Transmission & Distribution design practices follows the National Electrical Safety Code 

(NESC) methodologies. NESC Section 250.B sets the maximum tension a conductor must be 

designed to withstand under heavy load requirements, which includes consideration of ice, wind 
Aging Management Review Results 

 3-491 

and temperature. NESC Section 260.H.1.a requires that heavy load tension on installed 

conductors be less than 60 percent of the ultimate conductor strength. ACAR conductors are 

similar in construction to steel-reinforced design except that the core is an aluminum alloy that 

gives the conductor higher mechanical strength than that of all-aluminum conductor, while 

maintaining corrosion resistant properties in the core. In addition, the applicant stated that 

ACAR conductors, unlike aluminum conductor steel reinforced (ACSR) conductors, are not 

susceptible to environmental influences, such as SO2 concentration in the air. When aluminum 

corrodes, it forms a protective oxide layer that protects the underlying material from further 

corrosion. When the steel core of an ACSR conductor loses its galvanized coating, it will 

continually corrode causing a decrease in ultimate strength. Therefore, the HCGS transmission 

conductors are not susceptible to the same corrosion phenomenon as ACSR transmission 

conductors. 

The applicant stated that although the HCGS transmission conductors are not susceptible to 

same corrosion phenomenon as ACSR transmission conductors, in order to apply the findings 

from the Ontario Hydroelectric study of ACSR transmission conductors to the HCGS ACAR 

transmission conductors, it is postulated that the HCGS ACAR transmission conductors corrode 

at the same rate as comparable ACSR transmission conductors over 80 years. The applicant 

also stated that the study performed by Ontario Hydroelectric showed a 30 percent loss of 

composite conductor strength of an 80-year-old ACSR conductor due to corrosion. The Ontario 

Hydroelectric test did not include 2493 MCM 54/37 ACAR conductor. The Ontario Hydroelectric 

study did report, “The aluminum layers were found to have retained their original properties to a 

large degree. On the other hand the steel strands showed reductions in both tensile strength 

and the number of turns to failure.” 

The applicant stated that the Ontario Hydroelectric study is considered to bound the HCGS 

configuration and corrosion rate because the aluminum alloy core is more corrosion resistant 

than galvanized steel. The example presented in the EPRI License Renewal Electrical 

Handbook, TR-1013475, (page 13-10) compares a 4/0 ACSR conductor to the results of the 

Ontario Hydroelectric Study. The applicant stated that the same comparison method is made 

here for the HCGS transmission conductor. Tests performed by Ontario Hydroelectric showed a 

30 percent loss of composite conductor strength of an 80-year-old ACSR conductor due to 

corrosion. The ultimate strength and NESC design strength tension requirements of 2493 MCM 

54/37 ACAR are 57,600 pounds and 34,560 pounds, respectively. The margin between the 

NESC design strength and the ultimate strength is 23,040 pounds. The applicant further stated 

that the Ontario Hydroelectric study showed a 30 percent loss of composite conductor strength 

in an 80-year-old conductor. In the case of the 2493 MCM ACAR transmission conductors, 

postulating a 30 percent loss of ultimate strength would mean that there would still be 5,760 

pounds of margin between what is required by the NESC and the postulated 80-year ultimate 

conductor strength. The applicant then concluded that aging management activities regarding 

loss of conductor strength due to corrosion for HCGS transmission conductors are not required 

for the period of extended operation. 

The applicant also stated that the switchyard bus and connections evaluated for HCGS are 

those credited for supplying power to in-scope components for recovery of offsite power 

following an SBO. The switchyard buses within the scope of this review are constructed of rigid 

4-inch, schedule 80 aluminum pipe. The applicant also stated that switchyard buses at HCGS 

are connected to flexible conductors that do not normally vibrate and are supported by 

insulators and ultimately by static, structural components such as concrete footings and 

structural steel. Since there are no connections to moving or vibrating equipment, wind-induced 

abrasion and fatigue is not an applicable aging mechanism. The applicant further stated that 
Aging Management Review Results 

 3-492 

the HCGS switchyard bus is not subject to an ocean environment or industrial air pollution. 

HCGS is located in a rural area, not near heavy industry that would provide a source for 

contaminants, and is not in close proximity to the Atlantic Ocean. The station is located at the 

end of the Delaware River (at the head of Delaware Bay), 50 miles from the Atlantic Ocean. 

Therefore, HCGS is not considered to be a seacoast plant, where salt spray is prevalent. 

Aluminum bus material does not experience any appreciable aging effects in this environment. 

Therefore, corrosion is not an applicable aging mechanism. The applicant also stated that 

switchyard bus connections employ good bolting practices consistent with the recommendations 

of EPRI 1003471, “Electrical Connector Application Guidelines.” The connections are treated 

with corrosion inhibitors to avoid connection oxidation and torqued to avoid loss of preload, at 

the time of installation. The switchyard bus bolted connections are designed and installed using 

lock washers and stainless steel Belleville washers (not electroplated) that provide vibration 

absorption and prevent loss of preload. Therefore, the applicant concluded that oxidation and 

loss of preload are not applicable aging effects. The applicant further stated that transmission 

and distribution personnel perform normal maintenance activities on all portions of the 

switchyard, including transmission cable, switchyard bus, and connections. These maintenance 

activities have not revealed significant aging effects or mechanisms associated with this 

equipment to date. 

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 preload 

could occur in transmission conductors and connections, and in switchyard bus and 

connections. The GALL Report recommends further evaluation of a plant-specific AMP to 

ensure that this aging effect is adequately managed. 

The staff confirmed that switchyard buses at HCGS are connected to flexible conductors that do 

not swing and are supported by insulators and structural supports such as concrete footing and 

structural steel. Since there are no connections to moving or vibrating equipment, wind-induced 

abrasion and fatigue is not an applicable aging mechanism. The design of switchyard bolted 

connections at HCGS precludes torque relaxation and corrosion. The use of stainless steel 

Belleville washers is the industry standard to preclude torque relaxation. HCGS design 

incorporates the use of Belleville washers on bolted electrical connections of dissimilar metals to 

compensate for temperature changes, maintain the proper torque and prevent loosening. This 

method of assembly is consistent with the good bolting practices recommended by industry 

guidelines (EPRI TR-104213, “Bolted Joint Maintenance & Application Guide). The bolted 

connections and washers are coated with an anti-oxidant compound (a grease-type sealant) 

prior to tightening the connection to prevent the formation of oxides on the metal surface and to 

prevent moisture from entering the connection, thus reducing the chances of corrosion. This 

method of installation has been shown to provide a corrosion-resistant, low-electrical-resistance 

connection. The staff confirmed that the applicant’s maintenance activities have not revealed 

significant aging effects or mechanisms associated with switchyard bus and connections to 

date. Based on the review, the staff determined that loss of material due to wind induced 

abrasion and fatigue, increased resistance of connection due to oxidation or loss of preload of 

switchyard bus and connections are not significant aging effects requiring management at 

HCGS. 

The staff also noted that transmission conductors do not normally swing significantly. When 

transmission conductors swing due to a substantial wind, they do not continue to swing for very 

long once the wind has subsided. Wind loading that can cause a transmission line to sway is 

considered in design and installation. Furthermore, transmission conductors within the scope of 
Aging Management Review Results 

 3-493 

license renewal are generally in short span, and the surface areas exposed to wind loads are 

not significant. The staff determined that loss of material that could result from wind–induced 

transmission conductor vibration or sway is not an applicable AERM. 

The NESC sets the maximum tension a conductor must be designed to withstand under heavy 

load requirements, which include consideration of 1⁄2 inch of radial ice and 4 pounds per square 

feet. The NESC requires that heavy load tension on installed conductors be less than 

60 percent of the ultimate conductor strength. GALL AMR Table 3.6-1 does not have a specific 

line item dealing with ACAR transmission conductors. The staff noted that postulating a 

30 percent loss of ultimate strength of an 80-year old ACAR conductor would mean that the 

ultimate conductor strength of this conductor would be 40,320 pounds (57600 x 0.7). The ratio 

between the heavy load tension and the ultimate conductor strength (based on the longest span 

on a transmission line (885 ft) would be approximately 57 percent (22,800 pounds/40,320 

pounds). NESC requires the ratio between the heavy load tensions at 60 percent of the ultimate 

conductor strength. The postulated 80-year ultimate conductor strength would have enough 

margins to handle heavy load tension. The aluminum alloy core in ACAR transmission 

conductors is more corrosion resistant than the galvanized core steel in aluminum conductor 

steel reinforced (ACSR) transmission conductor. When aluminum corrodes, it forms a 

protective oxide layer that protects the underlying material from further corrosion. Furthermore, 

the applicant has confirmed that there is no operating experience with the transmission 

conductor to date. Based on this information, the staff determined that loss of material due to 

oxidization of ACAR transmission conductors at HCGS is not significant, and no aging 

management is required. 

Based on the programs identified above, the staff concludes that the applicant has met the 

SRP-LR Section 3.6.2.2.3 criteria. For those line items that apply to LRA Section 3.6.2.2.3, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 provides the staff’s evaluation of the applicant’s QA program. 

3.6.2.3 AMR Results That Are 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 through J that the combination of 

component type, material, environment, and AERM does not correspond to a line 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 whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following section. 
Aging Management Review Results 

 3-494 

In LRA Tables 3.6.1 and 3.6.2-1 under “Fuse Holders,” the applicant indicated based on HCGS 

design and operating experience, aging effects and mechanisms are not applicable for HCGS 

fuse holders. The applicant also stated that the metallic clamp portion of in-scope fuse holders 

that are not part of a larger assembly are not subject to frequent manipulation or environment 

conditions that could result in aging effects. The applicant assigned Note I. Note I states that 

the aging effects in the GALL Report for this component, material, and environment combination 

are not applicable. The applicant stated in LRA Section 3.6.2.3 that at HCGS, there are eight 

electrical panels that contain only fuse holders and terminal blocks that are within the scope of 

license renewal and are not part of a larger assembly. Four fuse panels located inside the 

auxiliary building control or diesel generator area are in an electrical panel room. The 

environment inside the room is air-conditioned. The other four fuse panels are located inside 

the switchyard control building. The environment inside the switchyard control house is also 

air-conditioned. The applicant also stated that oxidation and corrosion are not a concern since 

the fuse holders are not located in or near humid areas. The applicant further stated that all of 

the fuse holders are protected from chemical contamination, and are within a mild environment 

inside a building. There are no sources of chemicals in the vicinity of electrical panels. 

The applicant also stated that its walkdown of these enclosed electrical panels confirmed that 

the operating conditions for these holders are clean and dry, with no evidence of moisture 

intrusion, chemical contamination, oxidation, or corrosion. 

The applicant stated that fuse holders located in the auxiliary building control or diesel generator 

area are for 115-volt AC control power. The loads are instrumentation and control circuits that 

operate at low currents where no appreciate thermal cycling or ohmic heating occurs. The 

applicant also stated that the fuse holders located in the switchyard control house are for 

switchyard breaker DC control power. The normal supply of DC control power is from the 

battery charger. The battery is normally on a float charge, thus the fuses are lightly loaded with 

a small constant current. Therefore, the applicant stated that electrical and thermal cycling is 

not considered an applicable aging mechanism for these fuse holders. The applicant also 

stated that mechanical stress due to forces associated with electrical faults and transients are 

mitigated by the fast action of the circuit protective devices at high currents. Also, mechanical 

stress due to electrical faults is not considered a credible aging mechanism since such faults 

are infrequent and random in nature. 

The applicant stated that wear and fatigue is caused by repeated insertion and removal of 

fuses. The fuse in these fuse holders are not subject to frequent manipulation (i.e., removal and 

reinsertion) because they are neither clearance nor isolation points which support periodic 

testing nor preventive maintenance. The applicant also stated that these fuse holders are 

located in an electrical panel that is not mounted on moving or rotating equipment such as 

compressors, fans or pumps. Because the electrical panels are mounted with no attached 

sources of vibration, vibration is not an applicable aging mechanism. Therefore, the applicant 

concluded that the metallic clamps of these fuse holders will not exhibit the aging effect of 

fatigue due to mechanical stresses and/or frequent manipulation. 

During the audit of the LRA during the week of February 16, 2010, the staff walked down these 

fuse holder panels and discussed them with the applicant technical staff. The staff confirmed 

that these fuse holders are installed in indoor air-controlled environments. The staff determined 

that the applicant has provided an adequate evaluation to support the conclusion that aging 

effect and mechanism as identified in the GALL Report, Volume 2, Revision 1, item VI.A-8 are 

not applicable to the fuse holders at HCGS. Mechanical stress resulting from electrical faults 

and transients is not considered a credible aging mechanism, since the events are infrequent 
Aging Management Review Results 

 3-495 

and random in nature. Furthermore, stresses resulting from electrical faults are mitigated by 

fast acting circuit protective devices (etc., circuit breakers, fuses elements). The fuses are not 

routinely removed and reinserted to the metallic clamps. The fuses are only removed during 

fuse replacement with circuit isolation performed by circuit breakers in the circuit. Therefore, 

fatigue is not an applicable aging effect. The fuse panels are mounted on the wall and not on 

rotating machinery or in close proximity to rotating machines. Therefore, vibration is not an 

applicable aging effect. The fuse holders are located in a controlled air environment and are not 

exposed to fluid system leakage. Therefore, chemical contamination and corrosion is not an 

aging effect. These fuses are used in low voltage or low current application such that there is 

no significant ohmic heating. Ohmic heating and thermal cycling is not an applicable aging 

effect. The auxiliary room and switchyard control house are controlled air environments and 

oxidation of copper alloy fuse holder material is not expected in this environment. The staff 

walked down the enclosed electrical panels and confirmed that the operating conditions for 

these panels are clean and dry, with no evidence of moisture intrusion, chemical contamination, 

oxidation, or corrosion. Therefore, the staff determined that aging affects and mechanisms 

identified in the GALL Report are not applicable to HCGS. 

3.6.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the electrical and I&C components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, “Aging Management Review Results,” and 

Appendix B, “Aging Management Programs.” On the basis of its review of the AMR results and 

AMPs, the staff concludes that the applicant has demonstrated that the aging effects will be 

adequately managed so that the intended 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). 

With regard to these matters, the staff concludes that the activities authorized by the renewed 

license will continue to be conducted in accordance with the CLB, and any changes made to the 

CLB, in order to comply with 10 CFR 54.21(a)(3), are in accordance with NRC regulations. 

 4-1 

SECTION 4 

TIME-LIMITED AGING ANALYSES 

4.1 Identification of Time-Limited Aging Analyses

This section of the safety evaluation report (SER) addresses the identification of time-limited 

aging analyses (TLAAs). In Sections 4.2 through 4.8 of the license renewal application (LRA), 

PSEG Nuclear, LLC (PSEG or the applicant) addressed the TLAAs for Hope Creek Generating 

Station (HCGS). SER Sections 4.2 through 4.8 document the review of the TLAAs conducted 

by the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff). 

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined 

by the current operating term. Pursuant to Title 10, Section 54.21(c)(1), of the Code of Federal 

Regulations (10 CFR 54.21(c)(1)), an applicant must provide a list of TLAAs as defined in 

10 CFR 54.3, “Definitions.” 

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list existing plant-specific 

exemptions granted in accordance with 10 CFR 50.12, based on TLAAs. For any such 

exemption, the applicant must evaluate and justify the continuation of these exemptions for the 

period of extended operation. 

4.1.1 Summary of Technical Information in the Application 

To identify the TLAAs, the applicant evaluated calculations for HCGS against the six criteria 

specified in 10 CFR 54.3(a). The applicant prepared a list of potential generic TLAAs from 

NUREG-1800, Revision 1, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants” (SRP-LR), industry guidance, and operating experience. In addition, 

the applicant searched the current licensing basis (CLB) to confirm the existence of generic and 

plant-specific TLAAs. The CLB includes the following documents: updated final safety analysis 

report (UFSAR), operating license and license conditions, technical specifications (TSs), SERs, 

and licensing correspondence. The resulting list of potential TLAAs was reviewed against the 

six 10 CFR 54.3(a) criteria with the aid of design-basis documents, specifications, and 

calculations. 

In LRA Table 4.1-1, “Time Limited Aging Analysis Applicable to HCGS,” the applicant listed the 

following applicable TLAAs: 

● Neutron Embrittlement of the Reactor Pressure Vessel and Internals 

○ neutron fluence 

○ reactor pressure vessel materials upper-shelf energy reduction due to 

neutron embrittlement 

○ adjusted reference temperature for reactor pressure vessel materials due 

to neutron embrittlement 
Time-Limited Aging Analyses 

 4-2 

○ reactor pressure vessel analyses: pressure-temperature limits 

○ reactor pressure vessel circumferential weld examination relief 

○ reactor pressure vessel axial weld failure probability 

○ reactor pressure vessel core reflood thermal shock analysis 

○ reactor internals components 

● Metal Fatigue of the Reactor Pressure Vessel, Internals, and Reactor Coolant Pressure 

Boundary Piping and Components 

○ reactor pressure vessel fatigue analyses 

○ reactor pressure vessel internals fatigue analyses 

○ reactor coolant pressure boundary piping and component fatigue 

analyses 

○ non-Class 1 component fatigue analyses 

○ effects of reactor coolant environment on fatigue life of components and 

piping (Generic Safety Issue-190) 

● Environmental Qualification of Electrical Equipment 

● Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analyses 

○ fatigue analysis of primary containment, attached piping, and components 

○ primary containment process penetrations and bellows fatigue analysis 

○ vent line bellows 

● Other Plant-Specific Time-Limited Aging Analyses 

○ crane load cycle limit 

○ refueling bellows fatigue 

○ neutron fluence-induced bolt stress relaxation – jet pump auxiliary spring 

wedges and slip joint clamps 

The applicant stated that it had identified no exemptions that were based on a TLAA that 

requires evaluation for continued use during the period of extended operation. 
Time-Limited Aging Analyses 

 4-3 

4.1.2 Staff Evaluation 

The staff noted that the applicant’s list of potential TLAAs was assembled using regulatory and 

industry documents and operating experience. The staff finds the applicant’s use of these 

documents to compile a list of potential TLAAs reasonable because the applicant has used all 

available resources from the staff, the Nuclear Energy Institute (NEI), and past LRAs. 

The applicant performed a review of its CLB in order to determine if the design or analysis 

feature of each potential TLAA in fact exists at HCGS and in its licensing basis and to identify 

additional potential plant-specific TLAAs in accordance with 10 CFR 54.3(a). The staff finds the 

applicant’s approach in determining TLAAs reasonable because the applicant has performed a 

comprehensive search through its CLB, based on staff and industry guidance and operating 

experience, and has reviewed these potential TLAAs against the six criteria of a TLAA as 

defined in 10 CFR 54.3(a). 

The staff confirmed that the applicant’s LRA includes the TLAAs that are normally applicable to 

boiling-water reactor (BWR) applications. The staff finds the applicant’s identification of the 

TLAAs in the LRA acceptable because they are consistent with the TLAAs identified in SRP-LR 

Sections 4.2, 4.3, 4.4, and 4.6 as being applicable to BWR LRAs. 

The staff also verified that the LRA included the following additional plant-specific TLAAs: 

● crane load cycle limit 

● refueling bellows fatigue 

● neutron fluence-induced stress relaxation – jet pump auxiliary spring wedges and slip 

joint clamps 

The staff confirmed that the applicant’s identification of these additional TLAAs satisfies the 

recommendations in SRP-LR Section 4.7 and are in accordance with the requirements of 

10 CFR 54.3. The staff did not identify any omissions of TLAAs in the LRA. 

The staff confirmed that the TLAAs identified by the applicant as being applicable to the LRA 

have been evaluated by the applicant against the provisions and criteria of 10 CFR 54.21(c)(1). 

The staff evaluated the TLAAs and provided its basis for acceptance in the staff evaluations 

provided in SER Sections 4.2, 4.3, 4.4, 4.5, 4.6, and 4.7. 

Based on the information provided by the applicant as to the process it used to identify these 

exemptions and its results, the staff concludes, in accordance with 10 CFR 54.21(c)(2), there 

are no TLAA exemptions that the applicant must justify prior to entering into, and continuing 

through, the period of extended operation. 

4.1.3 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable list 

of TLAAs, as required by 10 CFR 54.21(c)(1). The staff confirms, as required by 

10 CFR 54.21(c)(2), that no exemption to 10 CFR 50.12 had been granted based on a TLAA. 
Time-Limited Aging Analyses 

 4-4 

4.2 Neutron Embrittlement of the Reactor Pressure Vessel and Internals

Neutron embrittlement describes changes in mechanical properties of reactor vessel (RV) 

materials caused by exposure to fast neutron flux (E>1.0 MeV) within the vicinity of the reactor 

core beltline region, i.e., the region that directly surrounds the active core. The most 

pronounced material change, relevant to this case, is a reduction in fracture toughness with 

increasing exposure to neutron flux. With additional exposure, the material’s resistance to crack 

propagation, e.g., fracture toughness, decreases. Fracture toughness is also dependent on test 

temperature within the brittle to ductile transition region; as test temperature increases, the 

material’s fracture toughness increases. The reference temperature for nil-ductility transition, 

RTNDT, is an index temperature for the fracture toughness curve for a material. As neutron 

fluence on a material increases, the RTNDT increases and, thus, higher temperatures are 

required for the material to remain ductile. This increased reference temperature is denoted as 

adjusted reference temperature (ART) and can be expressed by the equation 

ART = RTNDT + ΔRTNDT + MT 

where: 

ΔRTNDT is the increase induced by the fluence exposure 

MT is a margin term. 

In addition to the increase in reference temperature, neutron embrittlement results in a decrease 

in the upper shelf energy, defined as the energy absorption level under fully ductile failure 

conditions. 

Regulations governing RV integrity are found in 10 CFR Part 50. Specifically, 10 CFR 50.60 

requires all light-water reactors to meet the fracture toughness, pressure-temperature (P-T) 

limits, and material surveillance program requirements for the reactor coolant pressure 

boundary (RCPB) pursuant to 10 CFR Part 50, Appendices G and H. 

Determination of the projected RV reduction in fracture toughness as a function of neutron 

fluence affects several analyses that support HCGS operations: 

● RPV materials upper-shelf energy (USE) reduction due to neutron embrittlement 

● ART for RPV materials due to neutron embrittlement 

● P-T limits 

● RPV circumference weld examination relief 

● RPV axial weld failure probability 

● RPV core reflood thermal shock analysis 

● reactor internal components 

As extension of the operating period from 40 years to 60 years will increase neutron fluence, the 

60-year fluence value and its impact upon the analyses that support operation are evaluated 

below. 
Time-Limited Aging Analyses 

 4-5 

4.2.1 Neutron Fluence 

4.2.1.1 Summary of Technical Information in the Application 

The applicant stated that the fluence was calculated using the actual power histories for 

cycles 1–14, and conservatively assumed the extended power uprate (EPU) power level for the 

remainder of the 60-year period with a plant capacity factor of 100 percent. This corresponds to 

an end-of-extended-license exposure of 56 effective full-power years (EFPY). 

The applicant stated that the fluence values were calculated using the Radiation Analysis 

Modeling Application (RAMA) methodology5

 which was approved by the staff in an SER dated 

May 13, 2005 (ML051380572), based on its adherence to Regulatory Guide (RG) 1.190. The 

applicant also stated that the HCGS fluence analysis complies with the conditions of the RAMA 

SER. 

4.2.1.2 Staff Evaluation 

The RAMA methodology was reviewed by the staff and found acceptable because the 

calculational method, uncertainty, and qualification were found to adhere to the guidance 

contained in RG 1.190. Therefore, fluence analyses performed using the RAMA methodology 

adhere to the guidance contained in RG 1.190. 

In its SER approving the RAMA methodology, the staff included a condition. The condition 

stated that the RAMA methodology needed to be qualified using plant-specific dosimetry 

comparisons for any given BWR geometry. The initial qualification of the RAMA methodology 

was based on dosimetry comparisons to plants of the BWR/4 design, and HCGS was one of the 

plants against which the RAMA methodology was qualified. The RAMA methodology is, 

therefore, acceptably qualified not only for plants of the BWR/4 design, but also specifically 

based on HCGS capsule dosimetry. Therefore, the staff confirmed that the applicant’s fluence 

calculations comply with the conditions of the RAMA SER. Because the applicant’s fluence 

analysis meets the condition set forth in the staff’s SER approving the RAMA methodology and 

because the analysis was performed using the RAMA methodology, the staff finds that the 

applicant’s fluence analysis adheres to the guidance set forth in RG 1.190 and is, hence, 

acceptable. 

The applicant used a 100 percent capacity factor and evaluated fluences to 56 EFPY of 

exposure. This is acceptable and conservative because it will not be possible for the plant to 

operate at a 100 percent capacity factor through the end of extended license. Reductions in 

capacity factor will result from required refueling and maintenance outages and at times when 

the plant is unable to operate at its licensed power level. 

 

5

 The RAMA methodology is described in the following documents: (1) “BWR Vessel and 

Internals Project, RAMA Fluence Methodology Manual,” BWRVIP-114, June 11, 2003 

(ML031640195); (2) “RAMA Fluence Methodology Benchmark Manual-Evaluation of Regulatory 

Guide 1.190 Benchmark Problems,” BWRVIP-115, June 26, 2003 (ML031820254); and (3) 

“RAMA Fluence Methodology - Susquehanna Unit 2 Surveillance Capsule Fluence Evaluation 

for Cycles 1-5,” BWRVIP-117, August 5, 2003 (ML03230320). 
Time-Limited Aging Analyses 

 4-6 

The staff finds, in consideration of the items discussed above, that the peak fluence values 

identified by the applicant are acceptable due to the conservative nature of the 56 EFPY 

calculation and due to the calculational method’s adherence to the guidance contained in 

RG 1.190. 

4.2.1.3 UFSAR Supplement 

LRA Section A.4.2 provides the UFSAR supplement for the neutron fluence analysis TLAA 

evaluation. Based on its review of the UFSAR supplement, the staff concludes that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d), and consistent with SRP-LR Section 4.2.3.2. 

4.2.1.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that for RV neutron fluence, the analyses have been projected to the end 

of the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d), and is, therefore, acceptable. 

4.2.2 Reactor Pressure Vessel Materials Upper-Shelf Energy Reduction Due to Neutron 

Embrittlement 

4.2.2.1 Summary of Technical Information in the Application 

LRA Section 4.2.1 presents the applicant’s evaluation of Charpy USE values for the period of 

extended operation. The applicant stated that the HCGS CLB analyses evaluated reduction of 

fracture toughness of the RPV for 40 years and is a TLAA. The RPV neutron embrittlement 

TLAA has been projected to the end of the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(ii). 

The USE values are required to be at least 50 feet-pounds (ft-lb) for the life of the RPV including 

the period of extended operation. Specifically, 10 CFR Part 50, Appendix G requires that USE 

values for all RPV materials include the effects of neutron radiation and that the USE values at 

the one quarter thickness (1⁄4 T) of the RPV wall location for the beltline materials, including 

plates, welds, and nozzles, be maintained at no less than 50 ft-lb for the life of the RPV. 

Calculated neutron fluence values, considering the extended operation to 56 EFPY, are used to 

project changes in USE values for the period of extended operation, per 10 CFR Part 50, 

Appendix G. RG 1.99, Revision 2 is used to calculate the projected USE values. 

The applicant stated that all plates and welds meet the 50 ft-lb criterion at 56 EFPY, as seen in 

LRA Table 4.2.1-1. 

4.2.2.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.1 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the USE 

values have been projected to the end of the period of extended operation. According to 

RG 1.99, Revision 2, the predicted decrease in USE values due to neutron irradiation during 

plant operation is dependent upon the amount of copper in a given material and the predicted 
Time-Limited Aging Analyses 

 4-7 

neutron fluence on the given material. RG 1.99, Revision 2 includes two different methods for 

calculating the predicted decrease in USE values: 

● For materials that have less than two sets of credible surveillance data, the RG 

recommends Position 1.2. 

● For those cases when there are at least two sets of credible surveillance data, the RG 

recommends Position 2.2. 

The staff noted that for a conventional USE evaluation per RG 1.99, Revision 2, the unirradiated 

USE value is needed to calculate the decrease in USE due to irradiation. Transverse plate 

values for unirradiated USE were conservatively estimated as described in the UFSAR 

supplement. For the welds, the unirradiated USE values were assumed to be equal to the 

measured values at 10 °F. The staff has determined that the use of these values was 

acceptable. 

The staff also performed independent calculations and confirmed that the applicant’s projected 

USE values are conservative. In all cases, the beltline materials will have a projected USE at or 

above 50 ft-lb for 56 EFPY. For the limiting plate, weld, and nozzle materials, the projected 

USE values are 66.4, 60.2, and 62.6 ft-lb, respectively. Thus, the materials will meet the 

requirements of 10 CFR Part 50, Appendix G for 56 EFPY. 

4.2.2.3 UFSAR Supplement 

LRA Section A.4.2.1 provides the UFSAR supplement for the RPV materials USE reduction due 

to neutron embrittlement TLAA evaluation. The staff reviewed this UFSAR supplement 

description of the calculation and notes that it conforms to the recommended description for this 

type of program as described in SRP-LR Section 4.2.2.1.1.2. Based on its review of the UFSAR 

supplement, the staff concludes that the information in the UFSAR supplement is an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

4.2.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that all of the HCGS RPV beltline materials will have USE at the 1⁄4 T 

location of at least 50 ft-lb throughout the period of extended operation (through 56 EFPY), 

which meets the 10 CFR Part 50, Appendix G USE requirement. 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), and is, therefore, acceptable. 

4.2.3 Adjusted Reference Temperature for Reactor Pressure Vessel Materials Due to 

Neutron Embrittlement 

4.2.3.1 Summary of Technical Information in the Application 

The effects of neutron radiation on RTNDT are reflected in the adjusted reference temperature 

(ART). Which is calculated by adding ΔRTNDT to initial RTNDT with an appropriate margin for 

uncertainties. The applicant stated that the ΔRTNDT values for the RPV beltline plates and welds 

were projected to 56 EFPY using the methods described in RG 1.99, Revision 2 so that the ART 
Time-Limited Aging Analyses 

 4-8 

values could be revised to reflect the neutron exposure expected for the end of the period of 

extended operation. The applicant reviewed data from the NRC Reactor Vessel Integrity 

Database (RVID) and the Boiling Water Reactor Vessel and Internals Program (BWRVIP) 

Integrated Surveillance Program (ISP) and used the highest limiting material property values in 

computations of ΔRTNDT and ART for conservative results. The results are shown in LRA 

Table 4.2.2-1. The applicant dispositioned this TLAA for ART in accordance with 

10 CFR 54.21(c)(1)(ii). 

4.2.3.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.2 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 applicant 

calculated the ΔRTNDT and ART values based on the 56-EFPY neutron fluence for the RPV 

beltline materials as indicated in LRA Table 4.2.2-1. The staff performed independent 

calculations for comparison to those from the applicant. In each case, the applicant reports the 

same or a more conservative ΔRTNDT value than that determined in the staff’s calculations, and 

all of the ART values are developed in accordance with regulatory guidelines. Therefore, the 

staff finds the applicant has demonstrated that the analyses have been projected to the end of 

the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(ii). 

4.2.3.3 UFSAR Supplement 

LRA Section A.4.2.2 provides the UFSAR supplement for the ART for RPV materials due to 

neutron embrittlement TLAA evaluation. Based on its review of the UFSAR supplement, 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) and consistent with SRP-LR 

Section 4.2.3.2. 

4.2.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated that the ART 

analyses have been projected to the end of the period of extended operation in a manner 

consistent with 10 CFR 54.21(c)(1)(ii). 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), and is, therefore, acceptable. 

4.2.4 Reactor Pressure Vessel Analyses: Pressure-Temperature Limits 

4.2.4.1 Summary of Technical Information in the Application 

LRA Section 4.2.3 summarizes the evaluation of P-T limits for the period of extended operation. 

The HCGS TSs contain P-T curves that are valid through 32 EFPY. Revised P-T limits are not 

required at this time, but will continue to be updated, as required by 10 CFR Part 50, Appendix 

G, consistent with TLAA management in accordance with 10 CFR 54.21(c)(1)(iii). 
Time-Limited Aging Analyses 

 4-9 

4.2.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.3 to verify that the applicant’s analyses for the P-T curves 

have been developed in compliance with the requirements specified in 10 CFR Part 50, 

Appendix G. 

The staff noted that the current P-T limits, valid for operation up to 32 EFPY, were approved by 

the staff on November 1, 2004, and accounts for the change in neutron flux associated with 

operations under EPU conditions. The staff agrees that revised P-T limits are not required at 

this time. The staff notes that the applicant has committed to update the P-T curves as needed 

to assure that operational limits remain valid through the period of extended operation 

(Commitment No. 48). Therefore, the staff finds that the applicant’s plan to manage the P-T 

limits in accordance with 10 CFR 54.21(c)(1)(iii) is acceptable, because the applicant will 

implement changes to the P-T limit curves through the license amendment process (i.e., 

through revision of the plant TSs) and, thus, meet the requirements of 10 CFR 50.60 and 

10 CFR Part 50, Appendix G. 

4.2.4.3 UFSAR Supplement 

LRA Section A.4.2.3 provides the UFSAR supplement for the P-T limits TLAA evaluation. 

Based on its review of the UFSAR supplement, the staff concludes that the information in the 

UFSAR supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d), and consistent with SRP-LR Section 4.2.2.1.3.3. 

4.2.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that, for P-T limits, the effects of aging on the intended function will be 

adequately managed for the period of extended operation. The staff reviewed this UFSAR 

supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR 4.2.2.1.3.3. 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), and, therefore, is acceptable. 
Time-Limited Aging Analyses 

 4-10 

4.2.5 Reactor Pressure Vessel Circumferential Weld Examination Relief 

4.2.5.1 Summary of Technical Information in the Application 

LRA Section 4.2.4 summarizes the issues that govern inspection of the RPV circumferential 

welds at HCGS. The circumferential welds are required to be inspected at regular intervals 

described in Table IWB-2500-1, Examination Category B-A of ASME Code Section XI. HCGS 

has received inspection relief for the circumferential welds for the remaining initial licensed 

period of operation in an NRC letter dated November 1, 1999. The basis for this relief request 

was an analysis that satisfied the limiting conditional probability of failure (PoF) for the 

circumferential welds at the expiration of the current license, based on BWRVIP-05, “BWR 

Vessel and Internals Project, BWR Reactor Pressure Vessel Shell Weld Inspection 

Recommendations,” and the extent of neutron embrittlement expected through 40 years of 

operation. 

The analysis in LRA Section 4.2.4 uses the PoF and the mean ART (MART)6

 for the limiting 

beltline circumferential weld to characterize the anticipated metallurgical effects due to 

increased fluence expected for 56 EFPY. The PoF for the beltline circumferential welds due to 

a limiting event at HCGS, 4.10 x 10-8, is less than the PoF value for the Chicago Bridge and Iron 

(CB&I) reference plant, 1.78 x 10-5, in Table 2.6-5 of the SER of BWRVIP-05, “Final Safety 

Evaluation of the BWR Vessel and Internals Project BWRVIP-05 Report,” July 28, 1998. The 

MART value at 56 EFPY (9.4 °F) is bounded by the 64 EFPY MART value provided by the staff 

for the CB&I weld (70.6 °F). Taken together, the PoF and MART analyses justify the elimination 

of the RPV circumferential volumetric weld examination in the vessel beltline region to the end 

of the period of extended operation (56 EFPY). 

In LRA Section 4.2.4, the applicant also stated that the procedures and training used to limit 

RPV cold overpressure events will be the same as those approved by the staff when HCGS 

requested the BWRVIP-05 technical alternative be used for the current license period. 

In LRA Section A.5, Commitment No. 49, the applicant stated that it will request relief from the 

requirement to perform volumetric examinations of the RPV circumferential welds, in 

accordance with 10 CFR 50.55a, prior to the period of extended operation. The applicant 

dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(ii). 

4.2.5.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.4 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analyses to support the relief from the ASME Code Section XI inservice inspection (ISI) of 

circumferential welds have been projected to the end of the period of extended operation. The 

technical basis for the applicant’s alternative is found in the staff’s SER of the BWRVIP-05 

report. 

 

6 MART is defined as the RTNDT value for the unirradiated material added to a ΔRTNDT value that 

reflects the peak neutron fluence for the limiting weld at the end of extended period of operation. 

There is no margin term used in calculating the value of MART. 
Time-Limited Aging Analyses 

 4-11 

The SER indicated that BWR applicants may request relief from ISI requirements of 

10 CFR 50.55a(g) for volumetric examination of circumferential RPV welds by demonstrating: 

 (1) At the expiration of the license, the limiting conditional PoF for circumferential welds in 

the evaluation must be below the criterion specified in RG 1.154, “Format and Content of 

Plant-Specific Pressurized Thermal Shock Safety Analysis Reports for Pressurized 

Water Reactors,” and core damage frequency (CDF) of any BWR plant. 

 (2) The applicant must implement operator training and establish procedures that limit the 

frequency of cold overpressure events to the amount specified in the report. 

The first criterion is addressed in LRA Table 4.2-7 where the applicant has summarized the 

effects of irradiation on the limiting axial weld at HCGS and compared its properties to the NRC 

limiting CB&I circumferential weld used in the July 28, 1998, SER for BWRVIP-05. The staff 

notes that the HCGS circumferential weld has a lower copper and nickel content, as well as a 

lower neutron fluence at the clad/base metal interface than the limiting CB&I vessel 

circumferential weld. The unirradiated RTNDT is higher for the HCGS circumferential weld, but 

overall, the effects of chemistry and neutron fluence contribute to lower the MART for the HCGS 

circumferential weld when compared to the limiting CB&I vessel circumferential weld. The staff 

confirmed that the limiting HCGS circumferential weld is less susceptible to irradiation damage 

than the NRC limiting plant-specific case. Therefore, the applicant’s evaluation is acceptable. 

For the second criterion, the applicant stated in LRA Section 4.2.4 that HCGS will use the same 

procedures and training to the period of extended operation in the same manner that has been 

the practice during the original licensing period. Based on this, the staff determines that 

continued implementation of operator training and establishment of procedures limiting the 

frequency of cold overpressure events meets the criterion in the July 28, 1998, SER for 

BWRVIP-05. The staff determines that this condition concerns specific plant operation 

procedures and is not considered a TLAA. 

The staff finds the applicant’s conclusion for this TLAA acceptable because: (1) the staff’s 

evaluation, based on LRA Section 4.2.4, indicates that the conditional failure probability after 

56 EFPY for the RPV circumferential welds is bounded by the staff analysis in the July 28, 1998 

SER for BWRVIP-05; and (2) the applicant will request relief (Commitment No. 49) from the 

requirement to perform volumetric examinations of the RPV circumferential welds, in 

accordance with 10 CFR 50.55a, prior to entering the period of extended operation. 

4.2.5.3 UFSAR Supplement 

LRA Section A.4.2.4 includes the applicant’s UFSAR supplement summary description of its 

TLAA evaluation for relief from RPV circumferential weld examination. The staff reviewed this 

UFSAR supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR 4.2.2.1.4. Based on its review of 

the UFSAR supplement, the staff concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 
Time-Limited Aging Analyses 

 4-12 

4.2.5.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), for RPV circumferential weld examination relief that the analysis has 

been projected to the end of the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d), and, therefore, is acceptable. 

4.2.6 Reactor Pressure Vessel Axial Weld Failure Probability 

4.2.6.1 Summary of Technical Information in the Application 

LRA Section 4.2.5 summarizes the evaluation of RPV axial weld failure probability for the period 

of extended operation. The SER for BWRVIP-74, “BWR Vessel and Internals Project, BWR 

Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines,” evaluated the failure 

frequency of BWR RPV axial welds and determined it to be below 5.0 x 10-6 per reactor year for 

the first 40 years of reactor operation. Applicants for license renewal must evaluate RPV axial 

welds to show that their failure frequency remains below the 5.0 x 10-6 per reactor year 

calculated in the SER for BWRVIP-74. The SER states that an acceptable justification is that 

the MART for the limiting axial beltline weld at the end of the period of extended operation is 

less than the values specified in the SER. The value of MART for the limiting axial weld at 

HCGS after 56 EFPY is projected to be 14.3 °F, well below the generic value of 117.1 °F for 

CB&I axial welds that is found in the SER for BWRVIP-05, and thus the PoF for the limiting axial 

weld is well below the acceptable limit of 5.0 x 10-6 per reactor year. The applicant 

dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(ii). 

4.2.6.2 Staff Evaluation 

The staff has reviewed LRA Section 4.2.5 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analyses for the RPV axial welds have been projected to the end of the period of extended 

operation. 

In LRA Table 4.2.5-1, the applicant summarized the effects of irradiation on the limiting axial 

weld at HCGS and compared its properties to the NRC limiting CB&I axial weld used in the 

July 28, 1998, SER for BWRVIP-05. The staff notes that the HCGS weld has a lower copper 

and nickel content, as well as a lower neutron fluence at the clad/base metal interface than the 

limiting CB&I vessel axial weld; the two welds have the same unirradiated RTNDT. The staff 

concludes that the HCGS axial welds are less susceptible to irradiation damage than the NRC 

limiting CB&I axial weld; therefore, the applicant’s evaluation is acceptable. In addition, the 

principle of warm prestress provides assurance that brittle fracture of the HCGS RPV will not 

occur as the applied stress intensity factor recedes from its maximum value, at lower 

temperatures. 

4.2.6.3 UFSAR Supplement 

LRA Section A.4.2.5 provides the UFSAR supplement for the RPV axial weld PoF TLAA 

evaluation. The staff reviewed this UFSAR supplement description of the program and notes 

that it conforms to the recommended description for this type of program as described in 
Time-Limited Aging Analyses 

 4-13 

SRP-LR 4.2.2.1.5. 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). 

4.2.6.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that for RPV axial weld PoF, the analyses have been projected to the 

end of the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d), and, therefore, is acceptable. 

4.2.7 Reactor Pressure Vessel Core Reflood Thermal Shock Analysis 

4.2.7.1 Summary of Technical Information in the Application 

In LRA Section 4.2.6, the applicant addressed thermal shock on the RPV by re-evaluating a 

similar BWR-6 analysis, “Fracture Mechanics Evaluation of a Boiling Water Reactor Vessel 

Following a Postulated Loss of Coolant Accident, August 1979,” with the HCGS-specific wall 

thickness. The new analysis referenced in the LRA showed that at the temperature where the 

applied stress intensity factor from the analysis was a maximum, 100 ksi-in1/2 , the fracture 

toughness of the limiting beltline material (plate 5K3025/1) after 56 EFPY of service would be 

200 ksi-in1/2. Therefore, for the period of extended operation (56 EFPY), brittle fracture of the 

HCGS RPV is unlikely due to the thermal shock that could occur in the case of a reflood 

following a design-basis loss of coolant accident (LOCA) during operation. 

4.2.7.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.6 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 Sections 4.2.2 and 4.2.6 to verify the fracture toughness for the limiting 

beltline material. The staff noted that the input data used in the re-evaluation of the core reflood 

thermal shock analysis was consistent with the projected Charpy impact properties at 56 EFPY. 

The peak applied stress intensity used in the calculation is similar to that found in the thermal 

shock calculations done by Dickson and Kirk in the 2004 ASME Pressure Vessel and Piping 

conference paper “Assessment of Large-Scale Pressurized Thermal Shock Experiments Using 

the FAVOR Fracture Mechanics Computer Code.” The staff also noted that because the RPV 

wall thickness is a major parameter in determining stresses due to thermal shock, it was 

reasonable to assume that the slightly thicker HCGS RPV will have a peak stress intensity 

factor at the 1⁄4 T location that is above the 100 ksi-in1/2 value quoted for the BWR-6, but the 

increase is minor. The existing margin between the material property and the applied stress 

intensity factor is significant enough to assure safe operation. Based on the wide margin 

between the projected fracture toughness value and the estimated applied stress intensity 

factor, the staff determined that brittle fracture of the HCGS RPV is unlikely due to reflood 

thermal shock following a design-basis LOCA during the period of extended operation. 
Time-Limited Aging Analyses 

 4-14 

4.2.7.3 UFSAR Supplement 

LRA Section A.4.2.6 provides the UFSAR supplement for the RPV core reflood thermal shock 

analysis TLAA evaluation. Based on its review of the UFSAR supplement, the staff concludes 

that the information in the UFSAR supplement is an adequate summary description of the 

program, as required by 10 CFR 54.21(d) and consistent with SRP-LR Section 4.2.3.2. 

4.2.7.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that for the RPV core reflood thermal shock analysis, the analyses have 

been projected to the end of the period of extended operation. The staff also concludes that the 

UFSAR contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d), and, therefore, is acceptable. 

4.2.8 Reactor Internals Components 

4.2.8.1 Summary of Technical Information in the Application 

In LRA Section 4.2.7, the applicant stated that the core plate rim holddown bolts can experience 

stress relaxation due to the high neutron fluence in the core of the reactor. An initial 

plant-specific analysis performed in association with the EPU at HCGS showed that there was 

no concern with radiation-induced loss of preload on the core plate rim holddown bolts up to 

56 EFPY. A revised analysis with updated neutron fluence values for exposure up to 56 EFPY 

showed the preload on the core plate rim holddown bolts was adequate only up to 43.9 EFPY. 

The applicant dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(iii). 

Before entering the period of extended operation, the applicant committed (Commitment No. 51) 

to either: (1) install core plate wedges to retain the safety function of the core plate, or (2) show 

by analysis that the component function is maintained. 

4.2.8.2 Staff Evaluation 

The staff reviewed LRA Section 4.2.7 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

aging effects on the core plate rim holddown bolts will be managed to the end of the period of 

extended operation. 

The staff reviewed LRA Section 4.2.7 and compared the HCGS evaluation with the operating 

experience at other BWRs in the United States. The staff noted that the installation of the 

wedges prevents lateral motion of the core plate and removes the requirement to inspect the 

core plate rim holddown bolts; BWR/6 plants already use core plate wedges to replace the 

structural function of the bolts. 

The staff noted that the applicant committed (Commitment No. 51) to implement the following 

prior to the period of extended operation: (1) install core plate wedges to retain the safety 

function of the core plate, or (2) show by analysis that the component function is maintained. 

Based on industry experience, the staff considers the applicant’s commitment an acceptable 

method to manage the effects of loss of preload in the core plate rim holddown bolts. 
Time-Limited Aging Analyses 

 4-15 

4.2.8.3 UFSAR Supplement 

LRA Section A.4.2.7 provides the UFSAR supplement for the reactor internal components TLAA 

evaluation. The staff also notes that the applicant committed (Commitment No. 51) to perform 

one of the following prior to the period of extended operation: (1) install core plate wedges, or 

(2) perform an analysis that demonstrates the component function is maintained. 

Based on its review of the UFSAR supplement, the staff concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d) and consistent with SRP-LR Section 4.2.3.2. 

4.2.8.4 Conclusion 

On the basis of its review of LRA Section 4.2.7 and industry experience, the staff concludes that 

the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that for the core plate rim 

holddown bolts, the effects of aging on the intended function 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), and 

therefore, is acceptable. 
Time-Limited Aging Analyses 

 4-16 

4.3 Metal Fatigue of the Reactor Pressure Vessel, Internals, and Reactor Coolant 

Pressure Boundary Piping and Components

The applicant provided its assessment of those analyses in the CLB that comprise metal fatigue 

for the facility and are TLAAs in Section 4.3. The applicant divides this section of the LRA into 

the following subsections: 

● LRA Section 4.3.1, “Reactor Pressure Vessel Fatigue Analyses” 

● LRA Section 4.3.2, “Reactor Pressure Vessel Internals Fatigue Analyses” 

● LRA Section 4.3.3, “Reactor Coolant Pressure Boundary Piping and Component Fatigue 

Analyses” 

● LRA Section 4.3.4, “Non-Class 1 Component Fatigue Analyses” 

● LRA Section 4.3.5, “Effects of Reactor Coolant Environment on Fatigue Life of 

Components and Piping (Generic Safety Issue 190)” 

The staff evaluates the TLAAs contained in the LRA in the subsections that follow. 

4.3.1 Reactor Pressure Vessel Fatigue Analyses 

4.3.1.1 Summary of Technical Information in the Application 

LRA Section 4.3.1 summarizes the evaluation of the RPV fatigue analyses for the period of 

extended operation. This TLAA is based on the analysis in UFSAR Section 3.9. In this TLAA, 

the applicant stated that the metal fatigue evaluation was performed for the RPV and its 

components, including the vessel support skirt, shell, upper and lower heads, closure flanges 

and studs, nozzles and penetrations, nozzle safe ends, and refueling bellows support. The 

applicant also stated that these components were designed in accordance with ASME B&PV 

Code, Section III and, therefore, were subject to fatigue analyses. The applicant further stated 

that these analyses were based upon the number of thermal and pressure transients described 

in UFSAR Tables 3.9-1 and 3.9-1a and summarized in LRA Table 4.3.1-1. The applicant 

compiled the number of transients experienced at HCGS from initial plant startup up to 

December 31, 2007, using the HCGS Cycle Counting Program. Based on this data, the 

applicant derived the 60-year projected number of cycles and compared these values to 

design-basis number of cycles. The applicant addresses this TLAA for RPV fatigue analyses 

based on the criterion in 10 CFR 54.21(c)(1)(iii), in which the applicant demonstrates that the 

effects of aging associated with the analysis will be adequately managed for the period of 

extended operation using the Metal Fatigue of Reactor Coolant Pressure Boundary Program to 

monitor the numbers of cycles of the design transients, and the corresponding CUF for critical 

RPV components. 
Time-Limited Aging Analyses 

 4-17 

4.3.1.2 Staff Evaluation 

The staff reviewed the TLAAs in LRA Section 4.3.1 for RPV fatigue analyses against the criteria 

in SRP-LR Section 4.3.2.1.1.3 and review procedures in SRP-LR Section 4.3.3.1.1.3 in order to 

verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the RPV intended 

functions will be adequately managed for the period of extended operation. 

The staff also reviewed the following additional documents that are relevant to the staff’s 

evaluation of this TLAA: 

● TS 5.7, “Component Cyclic or Transient Limit” 

● UFSAR Section 3.9, “Mechanical Systems and Components” 

● UFSAR Table 3.9-1, “Plant Events” 

● UFSAR Table 3.9-1a, “Plant Events – Feedwater Nozzles” 

● 10 CFR 50.55a, “Codes and Standards” 

The staff reviewed the information summarized in LRA Table 4.3.1-1 and UFSAR Tables 3.9-1 

and 3.9-1a. The staff determined that the transients and the number of cycles specified in 

UFSAR Table 3.9-1 were used in fatigue analyses of the RPV and its components with 

exception of the feedwater nozzles analyses; whereas the transients and the number of cycles 

specified in UFSAR Table 3.9-1a were used in fatigue analyses of feedwater nozzles. The staff 

further determined that, for the same transients, the number of cycles used in the feedwater 

analyses are more limiting than those used in the analyses of the RPV and its other 

components. Because the applicant included a more limiting value for the numbers of cycles to 

be monitored under the Metal Fatigue of Reactor Coolant Pressure Boundary Program into LRA 

Table 4.3.1-1, the staff concluded that the methodology used to derive the allowable number of 

cycles is appropriate. 

From LRA Table 4.3.1-1, the staff noted that the limiting number of cycles for loss of feedwater 

heaters (turbine trip with 100 percent steam bypass and partial feedwater heater bypass) is 

23 cycles. In UFSAR Table 3.9-1a, the loss of feedwater heaters transient is separated into two 

transients of turbine trip with 100 percent steam bypass and with partial feedwater heater 

bypass, with 3 cycles and 20 cycles, respectively. 

By letter dated June 25, 2010, the staff issued RAI 4.3-01. Part 1 requested the applicant to 

clarify whether, in the fatigue analyses for the feedwater nozzles, the loss of feedwater heaters 

transients: (1) were accounted for as two separate transients and (2) should be included in the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program as two transients with 3 and 

20 limiting numbers of cycles. 

In its response dated July 22, 2010, the applicant responded to RAI 4.3-01, Part 1. By letter 

dated September 20, 2010, the applicant amended its response to RAI 4.3-01, Part 1. The 

applicant stated in the fatigue analyses for the feedwater nozzles, the turbine trip with 

100 percent steam bypass, and the partial feedwater heater bypass were accounted for as two 

separate transients. The applicant further stated that these transients are included in the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program and are counted as two separate 

transients per the current design basis. The applicant stated that the number of design-basis 

cycles does not represent a design limit and that the fatigue usage for a component is normally 

the result of several different thermal and pressure transients. Therefore, exceeding the 

number of cycles for one transient does not necessarily imply the fatigue usage factor will 
Time-Limited Aging Analyses 

 4-18 

exceed an acceptance limit. The applicant clarified that the two transients will not have limits 

set for them, since the calculated fatigue cumulative usage factor will be the limiting value and is 

monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff 

noted that the applicant’s method of monitoring the feedwater nozzle ensures the design code 

limit of 1 is not exceeded. The applicant further stated that due to the staff’s concerns with the 

fatigue monitoring program confirmatory evaluation performed to address RIS 2008-30, 

stress-based fatigue monitoring will not be used at this time. Furthermore, the applicant will 

only use cycle-based fatigue monitoring. The applicant stated that cycle-based fatigue 

monitoring uses the design-basis fatigue calculations which consider the six stress terms in 

accordance with the methodology from ASME Code Section III, Subsection NB, Subarticle 

NB-3200 for the RPV components. 

Based on its review, the staff finds the applicant’s response, as amended, to RAI 4.3-01, Part 1 

acceptable because the applicant clarified that the fatigue analyses for the feedwater nozzle 

account for the turbine trip with 100 percent steam bypass and with partial feedwater heater 

bypass transients, separately. In addition, the applicant will manage the effects of aging with its 

Metal Fatigue of Reactor Coolant Pressure Boundary Program to ensure the design code limit 

of 1 is not exceeded. The staff’s concern described in RAI 4.3-01, Part 1 is resolved. 

The staff reviewed LRA Table 4.3.1-1, which states that the limiting number of cycles for scram 

(turbine generator trip, feedwater on, isolation valves stay open, and all other scrams) is 

136 cycles. In UFSAR Table 3.9-1, the scram transient is separated into two transients for 

turbine generator trip, feedwater on, isolation valves stay open, and other scrams with 40 cycles 

and 140 cycles, respectively. 

By letter dated June 25, 2010, the staff issued RAI 4.3-01, Part 2 requesting that the applicant 

clarify whether scram transients: (1) were accounted for in the fatigue analyses for the RPV and 

its components, scrams transients were accounted for as two separate transients; and (2) 

should be included into the Metal Fatigue of Reactor Coolant Pressure Boundary Program as 

two transients. 

In its response to RAI 4.3-01, Part 2, dated July 22, 2010, the applicant stated: (1) the fatigue 

analyses for all the RV component locations, listed in LRA Table 4.3.1-2, other than the 

feedwater nozzle locations, combine the two transients (turbine generator trip, feedwater on, 

isolation valves stay open, and all other scrams); and (2) the two scram transients are included 

in the Metal Fatigue of Reactor Coolant Pressure Boundary Program. These two scram 

transients are combined by the fatigue monitoring software and used to compute fatigue usage 

for the RV component locations listed in LRA Table 4.3.1-2, other than the feedwater nozzle 

locations. The staff noted that since the applicant’s fatigue analyses for all the RV component 

locations other than the feedwater nozzle locations combined these two transients, it is 

reasonable that the applicant also counts these two transients together. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-01, Part 2 acceptable 

because: (1) the applicant clarified that the fatigue analyses for all the RV component locations 

other than the feedwater nozzle locations combine the two transients (turbine generator trip, 

feedwater on, isolation valves stay open, and all other scrams), and (2) these transients are 

appropriately monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program to 

ensure the assumptions in the fatigue analyses are not exceeded. The staff’s concern 

described in RAI 4.3-01, Part 2 is resolved. 
Time-Limited Aging Analyses 

 4-19 

The staff reviewed the applicant’s cycle projection methodology in LRA Section 4.3.1 for 

acceptability. The staff noted that the actual 60-year transient projection data that the applicant 

provided compared the design-basis transients to the design-basis limits for these transients in 

LRA Table 4.3.1-1 to determine whether the applicant had provided an acceptable basis for 

accepting these metal fatigue TLAAs. 

During its review, the staff noted that the applicant’s 60-year cycle projections are based on the 

number of transients experienced at HCGS from initial plant startup up to December 31, 2007, 

and the trends from the past 12 years of plant operation. However, LRA Section 4.3.1 does not 

provide sufficient information for the staff to conclude that the projection methodology used by 

the applicant is acceptable and would produce conservative values for 40- and 60-year cycle 

projections. 

By letter dated June 25, 2010, the staff issued RAI 4.3-02 requesting that the applicant provide: 

(1) additional information for all monitored transients on the number of cycles occurred during 

the last 12 years of plant operation, and (2) the technical basis for the assumption used that 

cycle accumulation trends during the period of extended operation will remain equal to or less 

than the trend over the last 12 years of plant operation. 

In its response dated July 22, 2010, the applicant stated that it has been tracking those 

transients required by the TSs, since initial operations of the unit commenced. The applicant 

further stated that Enhancement 1 for the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program is being made to add transients to the program beyond those defined in the TSs. The 

staff noted that those transients added to the program include the design-basis transients 

necessary to monitor those components determined to be within the scope of license renewal 

and have a cumulative fatigue usage TLAA. The staff further noted that for those transients not 

included in the applicant’s TSs, the applicant has the accumulated number of cycles as of 

December 31, 2007. The staff noted that the accumulation trends during the last twelve years 

of operation used in the 60-year transient projections are based on data from the present cycle 

counting program and are supplemented by retrieval of plant data and operating history to 

determine a conservative cycle count for transients in the applicant’s TSs and those transients 

associated with Enhancement 1 of the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program. 

The applicant also provided in its response the method to obtain the 60-year projected number 

of cycles. The staff noted that this methodology involved obtaining the average rate of 

occurrence for each transient that will require monitoring over a 12-year period (1995–2007) to 

determine the number of cycles that will occur from 2007 until 2026 (end of initial license) and 

2046 (end of renewed license). The staff further noted that this projected accumulation was 

summed with the number of cycles accrued as of December 31, 2007. The staff noted that this 

12-year period provides data that indicates changes in operation have been considered in 

making projections for 60 years of operation. Specifically, the applicant stated that a review of 

the operating history (e.g., unit capacity factor) during these 12 years as compared to that of 

previous years shows increases in capacity factor during the last 12 years when compared to 

the first nine years. The applicant attributes this increased capacity factor to improvements that 

have been made in operation, maintenance, and equipment reliability through company and 

industry improvement initiatives. The staff finds the applicant’s approach to determine the 

40-year and 60-year projections and use of the 12-year trending period reasonable because it is 

based on data from (1) actual cycle counting since initial plant operation or retrieval of plant 

data, and (2) recent operating history, (last 12 years) which indicates increased plant reliability 
Time-Limited Aging Analyses 

 4-20 

due to improvements in operation, maintenance, and equipment reliability over time and have 

decreased the rate of occurrence for plant transients. 

The staff noted the 60-year transient projections are representative of what is expected based 

on the transients experienced during the last 12 years, but these projections do not replace the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program implementing procedures which 

will include monitoring these transients to compute the cumulative usage factor (CUF). The 

staff further noted that the applicant’s program will monitor the numbers of cycles of the design 

transients, and the corresponding CUF for critical RPV components will be tracked to ensure 

that it remains less than the allowable limit. 

The applicant stated that assumptions were included to provide a conservative basis for 

accumulation trends during the last 12 years. Furthermore, examples of these assumptions 

include: (1) additional cycles were assumed when a degree of uncertainty existed; (2) additional 

cycles were assumed when no cycles were found during the last 12 years of operation for a 

given transient; and (3) additional cycles were added to injection transients, whose rate of 

occurrence may be affected by EPU. The staff noted that the applicant’s assumptions and 

60-year number of cycles assumed for analysis in LRA Table 4.3.1-1 are reasonable because it 

considers the possibility of the transients occurring in future years, even though no or few cycles 

had occurred during the last 12 years of operation. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-02 acceptable because: 

(1) the applicant confirmed it has been tracking transients since initial plant operation, as 

required by its TSs; (2) the applicant’s 60-year transient projections are based on data from the 

present cycle counting program and supplemented by retrieval of plant data and operating 

history; (3) the applicant included assumptions for additional cycles in its 60-year projections as 

described above; and (4) the applicant considered the possibility of the transients occurring in 

the future, even though no or few cycles had occurred during the last 12 years of operation. 

The staff’s concern described in RAI 4.3-02 is resolved. 

The applicant stated that the effects of aging on the intended functions of the RPV and its 

components, including the vessel support skirt, shell, upper and lower heads, closure flanges 

and studs, nozzles and penetrations, nozzle safe ends, and refueling bellows support will be 

managed for the period of extended operation using the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program for those locations with a CUF ratio predicted to exceed 0.4 in the 

original design-basis fatigue analysis or those locations identified in NUREG/CR-6260 for the 

newer-vintage General Electric plant. The applicant further stated that this aging management 

program (AMP) will monitor RPV and its components CUFs using either stress-based fatigue 

(SBF) monitoring or cycle-based fatigue (CBF) monitoring. LRA Table 4.3.1-2 summarizes RPV 

locations and its corresponding monitoring methods used to monitor the effects of aging using 

the Metal Fatigue of Reactor Coolant Pressure Boundary Program. 

LRA Section 4.3.1 states that SBF monitoring consists of computing a “real time” stress history 

for a given component from actual temperature, pressure, and flow histories via a finite 

element-based Green’s Function approach. The applicant stated that CUF is then computed 

from the computed stress history using appropriate cycle counting techniques and appropriate 

ASME Code Section III fatigue analysis methodology. Furthermore, the NRC concern regarding 

the simplified input to the Greens’ function of only one value of stress expressed in RIS 2008-30 

has been addressed in completion of the work done for the applicant by completing a detailed 

stress analysis using the six stress components as discussed in ASME Code Section III, 

Subsection NB, Subarticle NB-3200. The applicant further stated that SBF monitoring is 
Time-Limited Aging Analyses 

 4-21 

intended to duplicate the methodology used in the governing ASME Code stress report for the 

component in question, but uses actual transient severity in place of design-basis transient 

severity. The applicant stated that the confirmatory evaluation has been performed to verify the 

conservatism of the HCGS’ use of Green’s Function and associated SBF methodology. The 

staff noted that the LRA does not provide sufficient information or detail describing the 

confirmatory evaluation that was performed to verify the conservatism of the Green’s Function 

and associated SBF methodology. The staff also noted that the LRA does not describe in detail 

how the FatiguePro® software will be used in monitoring the CUF for the RPV components and 

how the software will adjust if new transients are observed or the distributions of transients 

changes. During a teleconference call between the staff and the applicant on September 15, 

2010, the applicant proposed that it will amend the LRA to state that the SBF monitoring module 

of FatiguePro® will not be used. The applicant also proposed that if SBF monitoring is used in 

the future, it will consider the six-stress terms in accordance with the methodology from ASME 

Code Section III, Subsection NB, Subarticle NB-3200. By letter dated September 20, 2010, the 

applicant amended LRA Section 4.3.1 to remove all references to the use of SBF monitoring. 

LRA Section 4.3.1, as amended by letter dated September 20, 2010, states that all of the CUF 

values reported for the RPV components in LRA Tables 4.3.1-2 and 4.3.5-1 were computed 

based on the fatigue tables from the design-basis calculations which consider the six stress 

terms in accordance with the methodology from ASME Code Section III, Subsection NB, 

Subarticle NB-3200. The applicant stated that the design-basis calculations were done using 

the code of record or updated to a later code edition pursuant to 10 CFR 50.55a, and therefore, 

the concerns of RIS 2008-30 have been addressed. 

Based on its review, the staff finds the applicant’s amendment to LRA Section 4.3.1 acceptable 

because the applicant: (1) does not rely on SBF monitoring software that uses a simplified input 

to the Greens’ function of only one value of stress that was expressed in RIS 2008-30; (2) relies 

only on CBF monitoring that uses the design-basis fatigue calculations which consider the six 

stress terms in accordance with the methodology from ASME Code Section III, 

Subsection NB-3200 for the RPV components; and (3) addressed the concerns associated with 

RIS 2008-30. 

LRA Section B.3.1.1 states that as a result of the high-pressure coolant injection (HPCI) event 

experienced in October 2004, the number of injection cycles exceeded the assumed number of 

cycles in the core spray nozzle fatigue analysis. The corrective action program was used to 

evaluate this event, resulting in an analysis indicating that the core spray nozzle CUF was 

0.815. LRA Section 4.3.1 states that the applicant performed reanalysis for the core spray 

nozzle in accordance with ASME B&PV Code Section III, 2001 Edition including 2003 Addenda. 

This reanalysis resulted in the core spray nozzle 40-year CUF of 0.063. It is not clear to the 

staff what assumptions used in the core spray nozzle reanalysis resulted in reduction of CUF by 

a factor of 13. Further, the staff identified inconsistencies in core spray nozzle 60-year CUF 

values reported in LRA Tables 4.3.1-2 and 4.3.5-1. 

By letter dated June 25, 2010, the staff issued RAI 4.3-03 requesting that the applicant clarify: 

(1) the assumptions used in the core spray nozzle reanalysis that resulted in a reduction of the 

CUF by a factor of 13 and (2) the inconsistencies in core spray nozzle 60-year CUF values 

reported in LRA Tables 4.3.1-2 and 4.3.5-1. 

In its response dated July 22, 2010, the applicant stated that the CUF values for the core spray 

nozzle (safe end/thermal sleeve and nozzle body) in LRA Table 4.3.1-2 were inadvertently not 

updated to reflect the final results of the calculation revision completed during preparation of the 

LRA. The applicant further stated that the updated 60-year CUF values are 0.0202 and 0.1063 
Time-Limited Aging Analyses 

 4-22 

for the core spray nozzle (safe end/thermal sleeve) and the core spray nozzle (nozzle body), 

respectively. The applicant stated the design-basis 60-year CUF values presented in LRA 

Table 4.3.5-1 for the core spray nozzle (safe end/thermal sleeve and nozzle body) are based on 

the final results of the revised calculation, which is the current design analysis of record. The 

applicant noted that the values presented in LRA Table 4.3.1-2 should be consistent with those 

presented in LRA Table 4.3.5-1 and, therefore, LRA Table 4.3.1-2 was amended in the RAI 

response. 

The applicant also stated in its response that prior to the most recent calculations performed for 

60 years of operation for the core spray nozzle (safe end/thermal sleeve) in support of the LRA, 

the previous analysis performed to evaluate the October 2004 HPCI injection used the original 

core spray nozzle safe end design. The applicant stated that the original safe end design used 

a threaded-in thermal sleeve, and the analysis applied a stress concentration factor of 5 at this 

location which resulted in the primary plus secondary stress intensity range significantly 

exceeding 3 Sm (three times the design stress intensity) and a resulting Ke (simplified 

elastic-plastic strain correction factor) value of 3.33. The applicant stated that this threaded 

location became the bounding location which was evaluated in subsequent analyses, and the 

original analysis design-basis CUF value at the bounding location for 40 years was 0.796. 

The applicant clarified that the safe end was replaced prior to initial plant operation but this 

configuration change was not incorporated into the previous fatigue analyses. The applicant 

stated the new configuration was an integral safe end without threads which was included in the 

revised finite element model and used to perform the fatigue analysis to support the LRA. The 

applicant also stated that the fatigue analysis performed for the LRA considered the integral 

safe end as fabricated of Alloy 600 instead of stainless steel, with a stainless steel thermal 

sleeve welded to the integral safe end, plus the addition of a new weld at the safe end to nozzle 

location. The applicant noted that beyond the changes in safe end design and material, the 

fatigue analysis performed for the LRA also refined the transient parameters, as compared to 

the simplified transient parameters used in the original analysis. The applicant further noted 

that these refinements included more detail with respect to time steps, nozzle and vessel 

temperatures and flows, and the use of actual lower flow rates associated with HPCI events 

when compared to flow rates shown in the thermal cycle diagram. The applicant stated that the 

thermal cycle diagram assumed all HPCI flow was injected through the core spray nozzle, even 

though the system is designed to split the flow between the core spray and feedwater nozzles. 

The applicant also stated that the fatigue summary from the previous fatigue analyses shows 

that the alternating stress values for all transient load set pairs were multiplied by the K, 

multiplier of 3.33, whereas only a few load set pairs in the current fatigue analysis are affected 

by Ke. 

The staff finds the reduction in CUF from the original fatigue analyses compared to the fatigue 

analyses performed for the LRA reasonable because the combination of the safe end design 

and material change, refinements with respect to time steps, nozzle and vessel temperatures 

and flows, and the use of actual lower flow rates associated with HPCI events and the 

application of Ke to the affected load set pairs would result in removal of conservatism that was 

assumed in the original analysis. The staff noted that with regard to the nozzle body location, 

the original design-basis 40-year CUF was 0.071 and it did not experience as large of a 

reduction in calculated fatigue usage. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-03 acceptable because: 

(1) the applicant’s reduction in CUF for the core spray nozzle (safe end/thermal sleeve) was 

reasonable based on the collective differences between design (geometry and material) and the 
Time-Limited Aging Analyses 

 4-23 

refinement of transient parameters, and (2) the applicant clarified the discrepancy between LRA 

Tables 4.3.1-2 and 4.3.5-1 and appropriately amended LRA Table 4.3.1-2 using the final 

calculation results. The staff’s concern described in RAI 4.3-03 is resolved. 

4.3.1.3 UFSAR Supplement 

LRA Section A.4.3.1 provides the UFSAR supplement for the RPV fatigue analyses TLAA 

evaluation. Based on its review of the UFSAR supplement, the staff concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d) and consistent with SRP-LR Section 4.3.3.3. 

4.3.1.4 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 effects of aging on the RPV intended functions 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), and therefore, is acceptable. 

4.3.2 Reactor Pressure Vessel Internals Fatigue Analyses 

4.3.2.1 Summary of Technical Information in the Application 

LRA Section 4.3.2 summarizes the evaluation of the RPV internals fatigue analyses for the 

period of extended operation. This TLAA is based on the analysis in UFSAR Section 3.9.5.3.5. 

In this TLAA, the applicant stated that the HCGS RPV internals were designed to plant-specific 

design requirements and not designed to ASME B&PV Code requirements for core support 

structures, however, the components were identified as a TLAA. To project the RPV internals 

CUFs to 60 years, the applicant multiplied the 40-year CUF, as reported in UFSAR 

Table 3.9-4c, by a factor of 1.5. The applicant noted that a factor of 1.5 represents an increase 

in the plant life from 40 to 60 years. The applicant further stated that the primary contributor to 

fatigue of RPV internals is from non-thermal dynamic loads such as those derived from 

accidents or seismic events. In this TLAA, the applicant accepts the TLAA for RPV internals 

fatigue analysis based on the criterion in 10 CFR 54.21(c)(1)(ii), which permits the TLAA to be 

accepted if it can be demonstrated that the analysis has been projected to the expiration of the 

period of extended operation. 

4.3.2.2 Staff Evaluation 

The staff reviewed the TLAAs in LRA Section 4.3.2 for RPV internals fatigue analyses against 

the criteria in SRP-LR Section 4.3.2.1.1.2 and the review procedures in SRP-LR 

Section 4.3.3.1.1.2 in order to verify the analyses are in accordance with 10 CFR 54.21(c)(1)(ii) 

and that the analyses for the RPV internals have been projected to the end of the period of 

extended operation. 
Time-Limited Aging Analyses 

 4-24 

The staff also reviewed the following additional documents that are relevant to the staff’s 

evaluation of this TLAA: 

● TS 5.7, “Component Cyclic or Transient Limit” 

● UFSAR Section 3.9.1.1.4, “Core Support Structures and Reactor Internals Transients” 

● UFSAR Section 3.9.5.3.5, “Stress, Deformation, and Fatigue Limits for Engineered 

Safety Feature Reactor Internals (Except Core Support Structure)” 

● UFSAR Table 3.9-1, “Plant Events” 

● UFSAR Table 3.9-1a, “Plant Events – Feedwater Nozzles” 

● UFSAR Table 3.9-4c, “Reactor Internals and Associated Equipment” 

● 10 CFR 50.55a, “Codes and Standards” 

The staff reviewed UFSAR Section 3.9.1.1.4, which states that the transients and the number of 

cycles specified in UFSAR Table 3.9-1 were used in 40-year fatigue analyses of the RPV 

internals. LRA Section 4.3.2 states that the applicant derived 60-year CUF values for RPV 

components by multiplying 40-year CUF values by a factor of 1.5, which represent an increase 

in the plant life from 40 to 60 years. The applicant stated that the RPV internals components in 

UFSAR Table 3.9-4c had CUFs of: (1) 0.111 for the core support plate (at stud), (2) 0.435 for 

the top guide (at beam slot), and (3) less than 0.05 for the core differential pressure sensing line 

(at elbow). The staff confirmed that by multiplying each of these CUF values by 1.5 would not 

lead to a CUF above the design limit. However, for some transients used in the RPV 

component fatigue analyses, the 40-year cycle projections summarized in LRA Table 4.3.1-1 

exceed the values reported in UFSAR Table 3.9-1. Therefore, to project the RPV internals 

CUFs to 60 years, the fatigue analyses for these components need to be updated based on the 

60-year cycle projections. However, LRA Section 4.3.2 does not provide sufficient information 

for the staff to determine whether 60-year RPV internals fatigue analyses have been updated to 

incorporate 60-year cycle projections. 

By letter dated June 25, 2010, the staff issued RAI 4.3-04 requesting that the applicant clarify 

whether the fatigue analyses for RPV internals have been updated based on the 60-year cycle 

projections as summarized in LRA Table 4.3.1-1. 

In its response dated July 22, 2010, the applicant stated that a review of the design-basis CUF 

calculations was performed for the core support plate (at stud), the top guide (at beam slot), and 

the core differential pressure sensing line (at elbow). The applicant has determined that the 

60-year projections of the number of cycles for the transients which were paired within the 

scope of the design-basis CUF calculations for these components were determined to increase 

no greater than 1.5 times the 40-year design input pairing values in the original design-basis 

calculations. The applicant stated that, therefore, the use of the simple multiplication of the 

design-basis CUF by a factor of 1.5 is conservative relative to the CUF which would be 

calculated using the actual 60-year cycle projections for the transients that are within the scope 

of the CUF calculations for these components. The staff noted that the approach taken by the 

applicant is conservative because the use of 60-year cycle projections does not yield CUF 

values greater than multiplying the 40-year design-basis CUF by a factor of 1.5. 
Time-Limited Aging Analyses 

 4-25 

Based on its review, the staff finds the applicant’s response to RAI 4.3-04 acceptable because 

the applicant’s approach of multiplying the 40-year design-basis CUF by a factor of 1.5 is 

conservative and the CUF values for these components calculated using the 60-year cycle 

projections is not greater than those computed by the applicant’s approach. The staff’s concern 

described in RAI 4.3-04 is resolved. 

4.3.2.3 UFSAR Supplement 

LRA Section A.4.3.2 provides the UFSAR supplement of the RPV internals fatigue analyses 

TLAA evaluation. Based on its review of the UFSAR supplement, the staff concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d) and consistent with SRP-LR Section 4.3.3.3. 

4.3.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the fatigue analyses of the RPV internals have been projected to the 

end of the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the TLAA evaluation, as required by 

10 CFR 54.21(d), and therefore, is acceptable. 

4.3.3 Reactor Coolant Pressure Boundary Piping and Component Fatigue Analyses 

4.3.3.1 Summary of Technical Information in the Application 

LRA Section 4.3.3 summarizes the evaluation of RCPB piping and component fatigue analyses 

for the period of extended operation. This TLAA is based on the analysis in UFSAR 

Section 3.2.2. In this TLAA, the applicant stated that the HCGS RCPB piping was designed in 

accordance with ASME B&PV Code Section III, Class 1 requirements and, therefore, was 

identified as a TLAA. The applicant further stated that high-energy line breaks (HELBs) in the 

HCGS piping have been postulated, and based on analyses performed on these breaks, means 

for avoiding damage to surrounding equipment and systems have been incorporated in the 

plant. The applicant performed 40-year design-basis fatigue analysis for HELB piping locations 

with allowable CUF values of 0.1 and, therefore, HELB locations are TLAAs. The applicant 

stated that the list of controlling transients is shown in LRA Table 4.3.1-1, which encompasses 

all transients listed in UFSAR Tables 3.9-1 and 3.9-1a. The applicant further stated that piping 

component locations with CUF ratios predicted to exceed 0.4 in the original design-basis fatigue 

analysis will be included in the Metal Fatigue of Reactor Coolant Pressure Boundary Program. 

In this TLAA, the applicant dispositioned the TLAA for RCPB piping and components based on 

the criterion in 10 CFR 54.21(c)(1)(iii), consistent with a demonstration that the effect of aging 

associated with the analysis will be adequately managed for the period of extended operation. 

4.3.3.2 Staff Evaluation 

The staff reviewed the TLAA in LRA Section 4.3.3 for RCPB piping and component fatigue 

analyses against the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 and the review 

procedures in SRP-LR Section 4.3.3.1.1.3 in order to verify the analyses are in accordance with 

10 CFR 54.21(c)(1)(iii) and that the effects of aging on the RCPB piping intended functions will 

be adequately managed for the period of extended operation. 
Time-Limited Aging Analyses 

 4-26 

The staff also reviewed the following additional documents that are relevant to the staff’s 

evaluation of this TLAA: 

● TS 5.7, “Component Cyclic or Transient Limit” 

● UFSAR Section 3.2.2, “System Quality Group Classification” 

● UFSAR Section 3.9.1.1.5, “Main Steam System Transients” 

● UFSAR Section 3.9.1.1.6, “Recirculation System Transients” 

● UFSAR Table 3.9-1, “Plant Events” 

● UFSAR Table 3.9-1a, “Plant Events – Feedwater Nozzles” 

● 10 CFR 50.55a, “Codes and Standards” 

The staff reviewed the applicant’s cycle projection methodology in LRA Section 4.3.1, which is 

evaluated in SER Section 4.3.1.2. During its review, the staff confirmed that the transients used 

in the RCPB piping analyses have been included into the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program, as summarized in LRA Table 4.3.1-1. The staff determined that 

the bounding piping components will be managed by the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program using the CBF monitoring method. The staff determined that CBF 

monitoring performs cycle counting and CUF computations based on the counted cycles and, 

therefore, is acceptable for monitoring aging effects in RCPB piping. The staff further 

determined that the postulated allowable CUF value for HELB piping of 0.1 is based on the CLB 

and is below the code limit of 1.0. The staff noted that there were four components whose 

estimated 60-year CUF values exceeded the design limit of 0.1. These were the: (1) feedwater 

line node 197 with a CUF value of 0.136, (2) main steam line D with a CUF value of 0.124, 

(3) residual heat removal (RHR) shutdown cooling (SDC) return A node 601 with a CUF value of 

0.113, and (4) RHR SDC return A node 608 with a CUF value of 0.106. The applicant indicated 

that these components would be managed by the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program to ensure that appropriate actions will be taken prior to the allowable limit 

being exceeded by monitoring the numbers of cycles of the design transients, and the 

corresponding CUF for critical reactor coolant pressure boundary piping and components. The 

staff concluded that effects of aging in RCPB piping will be managed for the period of extended 

operation. 

4.3.3.3 UFSAR Supplement 

LRA Section A.4.3.3 provides the UFSAR supplement of the RCPB piping and component 

fatigue analyses TLAA evaluation. Based on its review of the UFSAR supplement, the staff 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d) and consistent with SRP-LR Section 4.3.3.3. 

4.3.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the RCPB piping and component intended 

functions 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), and therefore, is acceptable. 
Time-Limited Aging Analyses 

 4-27 

4.3.4 Non-Class 1 Component Fatigue Analyses 

4.3.4.1 Summary of Technical Information in the Application 

LRA Section 4.3.4 summarizes the evaluation of fatigue analyses for non-Class 1 component 

for the period of extended operation. This TLAA is based on the analysis in UFSAR 

Section 3.2. In this TLAA, the applicant stated that non-Class 1 components were designed in 

accordance with ASME B&PV Code Section III, Class 2 and 3 or American National Standards 

Institute (ANSI) B31.1/B31.7 piping code; therefore, fatigue analyses were not required, but 

cyclic loading was considered in a simplified manner for the design process. 

The applicant analyzed stresses due to thermal expansion and anchor movement for 

non-Class 1 components identified in UFSAR Tables 3.2-1, 3.2-2, and 3.2-3, which include 

piping, tubing, fittings, tanks, vessels, heat exchangers, valve bodies, pump casting, and 

miscellaneous process components. The applicant indicated that the assumed thermal cycle 

count could be approximated by the thermal cycles expected for the RPV. The applicant 

combined all the expected transients in Table 4.3.1-1 and determined it was less than 2700 for 

60 years of plant operation. Because this is less than the acceptance criteria of 7,000, the 

applicant determined that piping analyses designed to ANSI B31.1 or ASME Code Section III, 

Class 2 and 3 are valid within the scope of license renewal. The applicant dispositioned the 

TLAA for non-Class 1 component fatigue analyses based on the criterion in 

10 CFR 54.21(c)(1)(i), consistent with a demonstration that the current analysis remains valid 

for the period of extended operation. 

4.3.4.2 Staff Evaluation 

The staff reviewed the TLAA in LRA Section 4.3.4 for non-Class 1 component fatigue analyses 

against the acceptance criteria in SRP-LR Section 4.3.2.1.2.1 and the review procedures in 

SRP-LR Section 4.3.3.1.2.1 in order to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation. 

The staff also reviewed the following additional documents that are relevant to the staff’s 

evaluation of this TLAA: 

● TS 5.7, “Component Cyclic or Transient Limit” 

● UFSAR Section 3.2.2, “System Quality Group Classification” 

● UFSAR Table 3.2-1, “HCGS Classification of Structures, Systems, and Components” 

● UFSAR Table 3.2-2, “Code Group Designation – Industry Codes and Standards for 

Mechanical Components (NSSS Scope)” 

● UFSAR Table 3.2-3, “Code Requirements for Components and Quality Groups for Public 

Service Electric and Gas Company/Bechtel-Procured Components” 

● UFSAR Table 3.9-1, “Plant Events” 
Time-Limited Aging Analyses 

 4-28 

● UFSAR Table 3.9-1a, “Plant Events – Feedwater Nozzles” 

● 10 CFR 50.55a, “Codes and Standards” 

The staff reviewed the applicant’s cycle projection methodology in LRA Section 4.3.1, which is 

evaluated in SER Section 4.3.1.2. During its review, the staff determined that the applicant 

assumed a thermal cycle counts for non-Class 1 components that are the same as the thermal 

cycles expected for the RPV and its components. The applicant used 60-year projections 

derived for these events as summarized in LRA Table 4.3.1-1. The applicant determined that 

60-year projected number of thermal cycles applicable to non-Class 1 components is less than 

2700 and, therefore, would not exceed the cycle threshold of 7000 cycles. 

The staff issued RAI 4.3-02 due to concerns about the applicant’s cycle projection methodology. 

RAI 4.3-02 and the applicant’s response to RAI 4.3-02 is evaluated in SER Section 4.3.1.2. The 

staff’s concern described in RAI 4.3-02 is resolved and the projected number of cycles for this 

TLAA is acceptable. 

Based on its review, the staff finds that the fatigue evaluation for the non-Class 1 components 

remains valid for the period of extended operation since the allowable number of cycles, at 

maximum displacements for normal operating conditions, is greater than those projected for 

60 years. 

4.3.4.3 UFSAR Supplement 

LRA Section A.4.3.4 provides the UFSAR supplement of the non-Class 1 component fatigue 

analyses TLAA evaluation. Based on its review of the UFSAR supplement, the staff concludes 

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d) and consistent with SRP-LR Section 4.3.3.3. 

4.3.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the analyses for non-Class 1 components 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), and 

therefore, is acceptable. 

4.3.5 Effects of Reactor Coolant Environment on Fatigue Life of Components and Piping 

(Generic Safety Issue 190) 

4.3.5.1 Summary of Technical Information in the Application 

LRA Section 4.3.5 summarizes the evaluation of the environmentally-assisted fatigue (EAF) 

analyses for the period of extended operation. This TLAA is based on the analysis in 

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components.” 
Time-Limited Aging Analyses 

 4-29 

In this TLAA, the applicant stated that the effects of the reactor coolant system environment on 

fatigue life were evaluated for the following representative components that are identified in 

NUREG/CR-6260 for newer vintage General Electric plants: 

● RPV shell and lower head 

● RPV feedwater nozzle 

● reactor recirculation piping (including RPV inlet and outlet nozzles) 

● core spray line RPV nozzle and associated Class 1 piping 

● RHR nozzles and associated Class 1 piping 

● feedwater Class 1 piping 

The applicant stated that the plant-specific limiting locations were identified for the 

NUREG/CR-6260 sample locations and EAF calculations were performed following the 

guidance of NUREG/CR-6583, “Effects of LWR Coolant Environments on Fatigue Curves of 

Carbon and Low-Alloy Steels,” for components made of carbon and low-alloy steels and the 

guidance of NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design 

Curves of Austenitic Stainless Steels,” for components made of austenitic stainless steel. The 

applicant further stated that EAF results showed that CUFs which include environmental effects 

would not exceed the code limit of 1.0 for 60 years of plant operation for all locations except the 

RPV feedwater nozzle safe end, which had a projected CUF of 2.3810. However, the applicant 

included all plant-specific limiting locations identified for the NUREG/CR-6260 sample locations 

into the Metal Fatigue of Reactor Coolant Pressure Boundary Program, which provides for 

corrective actions to prevent the CUF from exceeding the design code limit. The applicant 

dispositioned the TLAA for EAF analyses based on the criterion in 10 CFR 54.21(c)(1)(iii), 

based on a demonstration that the effects of aging associated with the analysis will be 

adequately managed for the period of extended operation. 

4.3.5.2 Staff Evaluation 

The staff reviewed the TLAA in LRA Section 4.3.5 for EAF analyses against the acceptance 

criteria in SRP-LR 4.3.2.2 and the review procedures in SRP-LR Section 4.3.3.2 in order to 

verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

function(s) will be adequately managed for the period of extended operation. 

The staff also reviewed the following additional documents that are relevant to the staff’s 

evaluation of this TLAA: 

● NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected 

Nuclear Power Plant Components” 

● NUREG/CR-6583, “Effects of LWR Coolant Environments on Fatigue Design Curves of 

Carbon and Low-Alloy Steels” 

● NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of 

Austenitic Stainless Steel” 

During its review, the staff noted that the applicant identified the plant-specific components and 

limiting component locations for the NUREG/CR-6260 sample locations and performed EAF 

calculations for these components to evaluate the effects of the reactor coolant system 
Time-Limited Aging Analyses 

 4-30 

environment on fatigue life. The applicant indicated that it chose the locations based on the 

required evaluations from NUREG/CR-6260. The staff noted that there were other reactor 

components with high 60-year projected CUF values, such as the feedwater piping line on LRA 

Table 4.3.3-1 with a 0.841 CUF that was not evaluated for environmental effects. The staff 

determined that LRA Section 4.3.5 does not provide sufficient information on the methodology 

used in determining the plant-specific components and limiting component locations for the 

NUREG/CR-6260 sample locations. 

By letter dated June 25, 2010, the staff issued RAI 4.3-05 requesting that the applicant explain 

the methodology used in determining the plant-specific components and limiting component 

locations for the NUREG/CR-6260 sample locations. 

In its response dated July 22, 2010, the applicant clarified its basis for the components analyzed 

for EAF shown in LRA Table 4.3.5-1. The applicant provided a table that clarified its basis for 

selecting the RCPB locations that were considered to be the equivalent bounding HCGS sample 

locations recommended in NUREG/CR-6260, as applied to new-vintage General Electric 

designed BWRs. The applicant also clarified its basis for concluding that these components 

were the most limiting. The applicant clarified that a review of its design basis did not identify 

any additional locations more limiting than those analyzed for EAF in LRA Table 4.3.5-1. 

The staff reviewed the applicant’s component locations analyzed for EAF in LRA Table 4.3.5-1. 

The staff compared this information to applicable design-basis CUF data and 60-year projected 

CUF data that the applicant provided for RV components in LRA Table 4.3.1-2 and for ASME 

Code Class 1 piping locations in LRA Table 4.3.3-1. The staff confirmed that, with the exception 

of the Class 1 portion of the feedwater piping, the applicant selected at least two component 

locations as being representative of each component location that was recommended in 

NUREG-6260. The information in the fourth column of SER Table 4.3.5-1 shown below 

provides the staff’s basis for accepting that the applicant’s selections of the component locations 

for EAF analysis are valid and conservative: 

Table 4.3.5-1 Basis for Accepting Applicant EAF Analysis Locations 

NUREG/CR-6260 

Recommended 

Location

HCGS EAF 

Location 

HCGS Basis for 

Picking Equivalent 

Location

The Staff’s Basis for Accepting the 

Applicant’s EAF Component Location

RV Shell and Lower 

Head 

Control Rod Drive 

(CRD) Housing 

Weld 

The applicant identified 

this component as an 

additional RV shell or 

lower head component 

for EAF analysis. The 

applicant stated that this 

component is the most 

limiting RV shell and 

lower head component 

for EAF and that the 

housings are made from 

stainless steel and the 

CRD housing-to-nozzle 

welds are made from 

stainless steel material. 

The staff confirmed that even though the 

CRD housing is welded to CRD penetration 

nozzles, the housings are more 

appropriately considered as CRD piping 

locations. The staff also confirmed that LRA 

Table 4.3.5-1 identifies that the 60-year EAF 

for CRD housing welds are more limiting 

than the CRD penetration nozzles. The staff 

noted that the housing welds are more 

limiting for EAF because they are subjected 

to a much higher Fen adjustment factor. The 

staff finds the inclusion of the CRD housing 

welds as the limiting RV shell and lower 

head component for EAF to be valid and 

conservative because it is more limiting than 

the CRD penetration nozzle location. This 

demonstrates the validity of the applicant’s 

response to RAI 4.3-05, Request 2 that 

additional components do not need to be 

analyzed for EAF beyond those assessed in 
Time-Limited Aging Analyses 

 4-31 

NUREG/CR-6260 

Recommended 

Location

HCGS EAF 

Location 

HCGS Basis for 

Picking Equivalent 

Location

The Staff’s Basis for Accepting the 

Applicant’s EAF Component Location

LRA Table 4.3.5-1. 

CRD Penetrations 

with Excavation 

Additional RV shell 

component even though 

the CRD housing welds 

are considered to be 

more limiting. The 

penetration nozzle is 

fabricated from 

Alloy 600. 

The staff confirmed that the component type 

is welded to the RV lower head and is 

considered to be an RV appurtenance. The 

staff finds the inclusion of this component for 

EAF analysis to be a conservative practice 

because the component is equivalent to the 

NUREG/CR-6260 RV shell and lower head 

location. 

RV Feedwater 

Nozzle 

Feedwater Nozzle Applied 

NUREG-recommended 

component for EAF 

calculations. 

The staff finds the inclusion of this 

component for EAF analysis valid and 

conservative because the component is 

equivalent to the NUREG/CR-6260 

feedwater nozzle location. 

Feedwater Nozzle 

Safe End

Safe end was 

conservatively included 

as an additional 

feedwater nozzle 

component location 

because this feedwater 

nozzle component was 

more limiting for EAF 

than the feedwater 

nozzle itself.

The staff confirmed that LRA Table 3.1.2-1 

lists the feedwater nozzle safe end as an RV 

component and that the applicant identified 

this as an additional feedwater nozzle 

equivalent location for EAF analysis. The 

staff finds the inclusion of the feedwater 

nozzle safe end for EAF analysis to be valid 

and conservative because the component 

represents an additional equivalent 

feedwater nozzle location and the EAF value 

for the feedwater nozzle safe end is more 

limiting than that listed in LRA Table 4.3.5-1 

for the feedwater nozzle. The staff noted 

that this demonstrates the validity of the 

applicant’ response to RAI 4.3-05, Request 

2 that there does not need to be an 

additional feedwater nozzle component 

location analyzed for EAF beyond those in 

LRA Table 4.3.5-1.

Reactor 

Recirculation Piping 

(including RV inlet 

and outlet nozzles)

RHR Return Tee Provided as the 

equivalent Class 1 

reactor recirculation 

piping location.

The staff confirmed that the applicant listed 

the Class 1 RHR return tee in the reactor 

recirculation loop in LRA Table 4.3.5-1 

because it represents the equivalent Class 1 

reactor recirculation piping location and the 

return tee represented the most limiting 

reactor recirculation piping component for 

EAF due to its high Fen factor.

RV Inlet Nozzle 

Forging

Provided as the 

equivalent RV inlet 

nozzle location.

The staff confirmed that the applicant 

appropriately listed RV inlet nozzle forging 

for EAF in LRA Table 4.3.5-1 because it 

represents the equivalent RV inlet nozzle 

location.

RV Outlet Nozzle 

Forging

Provided as the 

equivalent RV outlet 

nozzle location.

The staff confirmed that the applicant 

appropriately listed RV outlet nozzle forging 

for EAF in LRA Table 4.3.5-1 because it 

represents the equivalent RV outlet nozzle 

location.

Core Spray Line RV 

Nozzle and 

Associated Class 1 

Piping

Core Spray Nozzle Provided as the 

equivalent core spray 

nozzle location.

The staff confirmed that the applicant 

appropriately listed RV inlet nozzle forging 

for EAF in LRA Table 4.3.5-1 because it 

represents the equivalent core spray nozzle 

location.
Time-Limited Aging Analyses 

 4-32 

NUREG/CR-6260 

Recommended 

Location

HCGS EAF 

Location 

HCGS Basis for 

Picking Equivalent 

Location

The Staff’s Basis for Accepting the 

Applicant’s EAF Component Location

Core Spray Nozzle 

Safe End

Provided as the 

equivalent core spray 

line piping location.

The staff noted that, although LRA 

Table 3.1.2-1 lists the core spray nozzle 

safe end as an RV component, the 

component represents an additional spool of 

pipe that is welded to the core spray nozzle 

on one end and to the core spray piping on 

its opposite end. The staff finds that the 

applicant identified the core spray safe end 

locations as the equivalent core spray piping 

location. The staff also confirmed that the 

core spray nozzles are the more limiting 

core spray line component for EAF. 

Therefore, the staff finds that the inclusion of 

the core spray nozzle safe end for EAF 

analysis is conservative and acceptable.

RHR Class 1 Piping RHR Supply Piping 

from Stainless 

Steel

Provided as the 

equivalent Class 1 RHR 

piping location for piping 

made from stainless 

steel.

The staff confirmed that the applicant 

appropriately listed this RHR piping for EAF 

in LRA Table 4.3.5-1 because it represents 

an equivalent Class 1 RHR piping location 

and the applicant conservatively listed both 

an equivalent stainless steel RHR piping 

location and a carbon steel RHR piping 

location for EAF in LRA Table 4.3.5-1. This 

component represents the stainless steel 

entry.

RHR Supply Piping 

from Carbon Steel

Provided as the 

equivalent Class 1 RHR 

piping location for piping 

made from carbon steel.

The staff confirmed that the applicant 

appropriately listed this RHR piping for EAF 

in LRA Table 4.3.5-1 because it represents 

an equivalent Class 1 RHR piping location 

and the applicant conservatively listed both 

an equivalent stainless steel RHR piping 

location and a carbon steel RHR piping 

location for EAF in LRA Table 4.3.5-1. This 

component represents the carbon steel 

entry.

Class 1 Feedwater 

Piping

Tee on Header to 

RV Feedwater 

Nozzle N4E

Provided as the 

equivalent Class 1 

feedwater piping 

location.

The staff confirmed that the applicant 

appropriately listed feedwater tee for EAF in 

LRA Table 4.3.5-1 because it represents the 

equivalent Class 1 feedwater piping location.

The staff noted that the Feedwater Line No. AE-036, node 200 has a 60-year CUF of 0.841. 

However the RPV feedwater nozzle (safe end and nozzle forging) and feedwater Class 1 piping 

(tee on header to RPV Nozzle N4E) which were evaluated for reactor water environmental 

effects, consistent with NUREG/CR-6260, have lower 60-year CUF values. The staff is unclear 

whether the Feedwater Line No. AE-036, node 200 should be evaluated for reactor water 

environmental effects or if it is bounded by the locations that have already been evaluated for 

reactor water environmental effects. In addition, the staff needs confirmation that the applicant 

has verified that estimated 60-year CUF values for LRA Table 4.3.3-1 are still conservative and 

bounded, as compared to those of components in LRA Table 4.3.5-1, when adjusted for 

environmental effects. This is identified as confirmatory item CI 4.3.5.2-1. 
Time-Limited Aging Analyses 

 4-33 

By letter dated January 6, 2011, the applicant responded to confirmatory item CI 4.3.5.2-1. The 

applicant’s response was separated into the following three subject areas: 

 A. The review of the selection of the limiting NUREG/CR-6260 feedwater Class 1 piping 

location. 

 B. The review of the CUF values presented in LRA Tables 4.3.3-1 and 4.3.5-1. 

 C. A commitment to perform additional reviews to confirm the limiting HCGS locations per 

NUREG/CR-6260 are bounding as compared to other plant-specific locations. 

In response to subject area A, the applicant stated that it performed a verification to confirm the 

limiting locations evaluated per NUREG/CR-6260 are bounding as compared to other 

plant-specific locations (e.g. Feedwater line No. AE-036, node 200/130) for the feedwater 

Class 1 piping. The applicant described the actions taken for this verification, which included a 

review of the feedwater piping values of LRA Table 4.3.3-1 and the basis documents which 

support the table. 

From this review, the applicant concluded that Feedwater Line No. AE-035 Node 200 instead of 

Feedwater Line No. AE-036 Node 130 listed in LRA Table 4.3.3-1 should have been used to 

determine the EAF CUF for feedwater piping in LRA Table 4.3.5-1. The staff noted that the 

applicant’s conclusion was based on using the highest design-basis 40-year CUF. The 

applicant indicated that the use of Node 130 instead of Node 200 was caused by an error in the 

stress report input during the preparation of the calculations for the LRA. The applicant clarified 

that Node 200 is at the terminal end of the piping system where it attaches to the RPV 

feedwater nozzle safe end. 

The staff noted that based on these results, the applicant reviewed the feedwater nozzle 

analysis since it includes the bounding terminal end of the piping. The staff noted that the 

feedwater nozzle analysis results shown in LRA Table 4.3.5-1 were obtained from an ASME 

Section III NB-3200 analysis that used a finite element model that included the low alloy steel 

nozzle forging, the carbon steel safe end (with a stainless steel inlay), and the terminal end of 

the carbon steel pipe that correlates with AE-035 Node 200. 

The applicant stated that this NB-3200 analysis of the feedwater nozzle was performed using 

loads that are bounding for all the feedwater nozzles and the finite element model showed that 

the highest stress location within the nozzle assembly was in the safe end. The staff finds that 

since the safe end was shown to be the highest stress location, which results in the highest 

fatigue usage, it can be considered bounding for the terminal end of the carbon steel pipe, 

which correlates to AE-035 Node 200. The applicant stated that the 60-year CUF value for the 

safe end is 0.1982 and that by applying the carbon steel Fen multiplier of 4.73 for the feedwater 

piping, an environmentally-adjusted CUF value of 0.9375 is determined for AE-035 Node 200. 

The staff’s review of the applicant’s assumptions used to determine the carbon steel Fen

multiplier of 4.73 is discussed in RAI 4.3-06 and documented in SER Section 4.3.5.2. 

The applicant also clarified the higher 60-year projected CUF value of 0.841, in LRA 

Table 4.3.3-1, for Feedwater Line No. AE-036 Node 200 as compared to other feedwater piping 

locations. The staff noted that the design-basis CUF calculations, for both Feedwater Line 

No. AE-035 Node 200 and AE-036 Node 200, include the operating basis earthquake (OBE) 

transient, and the estimated 40-year and 60-year CUF calculations were based on projected 

transients. The staff noted that the estimated 40-year and 60-year CUF calculations did not 
Time-Limited Aging Analyses 

 4-34 

assume an OBE transient, consistent with LRA Table 4.3.1-1, because the numbers of 

occurrences expected for 40 and 60 years of operation were obtained by extrapolating the 

numbers of occurrences actually incurred to-date. The staff’s review of the applicant’s 

projection methodology is discussed in RAI 4.3-02 and documented in SER Section 4.3.1.2. 

The staff finds it acceptable that the applicant did not consider the OBE transient in the 

estimated 40-year and 60-year CUF calculations because: (1) the projected cycles for 40 and 

60 years of operation and the estimated 40-year and 60-year CUF calculations were provided in 

the LRA as information only and does not represent the applicant’s design calculations or 

analysis of record and (2) the applicant’s Metal Fatigue of Reactor Coolant Pressure Boundary 

Program will continue to monitor and track those transients that are important to determining a 

CUF, during the period of extended operation. 

The applicant stated that the OBE transient has a higher impact on Feedwater Line No. AE-035 

Node 200 analysis than it does on the Feedwater Line No. AE-036 Node 200 analysis. The 

staff finds it reasonable that the estimated 60-year projected CUF was higher for Feedwater 

Line No. AE-036 Node 200, although the design CUF for Feedwater Line No. AE-035 Node 200 

was greater than Feedwater Line No. AE-036 Node 200, because the OBE transient has a 

higher impact on Feedwater Line No. AE-035 Node 200 and was not included in the estimated 

60-year projected CUF. 

The staff noted that the applicant amended LRA Table 4.3.5-1 to indicate that the terminal end 

of piping at the feedwater nozzle safe end at the applicant’s site corresponds to the 

NUREG/CR-6260 location, “Feedwater Class 1 Piping.” 

Based on its review, the staff finds the applicant’s response to CI 4.3.5.2-1, subject area A, 

acceptable because: (1) the applicant considered the effects of reactor water environment on 

fatigue life on the most bounding location, Feedwater Line No. AE-035 Node 200, for the 

feedwater Class 1 piping; (2) the environmentally adjusted CUF for this location was below the 

design limit of 1.0; (3) the applicant justified the difference in the estimated 60-year CUF 

between Feedwater Line No. AE-036 Node 200 and AE-035 Node 200, as described above; 

and (4) the applicant will continue to monitor fatigue usage, including environmental effects, for 

this location with its Metal Fatigue of Reactor Coolant Pressure Boundary Program. 

In response to subject area B, the applicant stated that as a result of the stress report input error 

identified for the feedwater Class 1 piping component location, a comprehensive review of the 

stress reports supporting the LRA tables was performed. During this review, the applicant found 

that the stress report for the reactor water cleanup (RWCU) piping system contained a second 

40-year design CUF value at Node 905, which is higher than that reported in LRA Table 4.3.3-1. 

The applicant stated that RWCU Node 905 is located at the transition between carbon steel 

piping and stainless steel piping. Furthermore, the higher CUF value of 0.573 is attributed to 

the evaluation of stainless steel material at this location, which is in addition to the CUF value of 

0.523 for carbon steel already presented in LRA Table 4.3.3-1. The applicant clarified that the 

weld material used at this transition is stainless steel. Based on its review, the applicant 

concluded that the remaining values in LRA Table 4.3.3-1 and LRA Table 4.3.5-1 are correct 

based on the stress report inputs. 

The applicant stated that other than the feedwater Class 1 piping, its review also concluded the 

component locations in LRA Table 4.3.5-1 are the limiting plant-specific locations that correlate 

with the NUREG/CR-6260 components, however, additional plant-specific locations may exist 

which are more limiting than those considered in NUREG/CR-6260. The staff noted the 
Time-Limited Aging Analyses 

 4-35 

applicant will perform an additional review as described in Commitment No. 54 and subject 

area C. 

In response to subject area C, the applicant committed (Commitment No. 54) to the following: 

PSEG will perform a review of design basis ASME Code Class 1 fatigue 

evaluations to determine whether 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 the Hope Creek plant configuration. If more 

limiting locations are identified, the most limiting location will be evaluated for the 

effects of the reactor coolant environment on fatigue usage. If any of the limiting 

locations consist of nickel alloy, NUREG/CR-6909 methodology for nickel alloy 

will be used in the evaluation. 

The applicant stated that these additional evaluations will be performed through the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program and the most limiting location will be 

monitored in accordance with 10 CFR 54.21(c)(1)(iii). 

Based on its review, the staff finds the applicant’s response to CI 4.3.5.2-1, subject area B, 

acceptable because: (1) as a result of the stress report input error identified for the feedwater 

Class 1 piping, the applicant took corrective actions to ensure that the remaining CUF values 

reported in the LRA are accurate and correct; (2) the applicant identified a second 40-year 

design CUF value at RWCU Node 905 that corresponded to the stainless steel material at this 

node and amended LRA Table 4.3.3-1, as appropriate; and (3) the applicant verified that the 

remaining values in LRA Table 4.3.3-1 and LRA Table 4.3.5-1 are correct based on stress 

report inputs. 

Based on its review, the staff finds the applicant’s response to CI 4.3.5.2-1, subject area C, and 

Commitment No. 54 acceptable because: (1) the applicant will review its design-basis ASME 

Code Class 1 fatigue evaluations to determine whether 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; (2) if a more limiting location is identified, the 

applicant will perform EAF analyses for the most limiting location; (3) the methodology 

consistent with NUREG/CR-6909 will conservatively be used in the evaluation, if the limiting 

component identified consists of nickel alloy; and (4) Commitment No. 54 is consistent with the 

recommendations in SRP-LR Sections 4.3.2.2 and 4.3.3.2, and GALL AMP X.M1, to consider 

environmental effects for the NUREG/CR-6260 locations, at a minimum. Confirmatory item 

CI 4.3.5.2-1 is closed. 

The staff’s review of LRA Section 4.3.5, identified that the applicant had used NUREG/CR-6583 

and NUREG/CR-5704 to determine the environmental fatigue multiplier (Fen). However, the 

staff determined that the LRA does not provide sufficient information on the basis for 

assumptions used in calculating the Fen values for the NUREG/CR-6260 sample locations. By 

letter dated June 25, 2010, the staff issued RAI 4.3-06 requesting that the applicant provide the 

basis for assumptions used (e.g., sulfur content, dissolved oxygen, temperature, strain rate) in 

the Fen calculations for the NUREG/CR-6260 sample locations. 

In its response dated July 22, 2010, the applicant clarified the assumptions used in the 

derivation of its Fen factors for the EAF calculations. For calculation of Fen factors for transients 

that are driven by dynamic loading, the applicant stated that it assumed a Fen value of 1.0. For 

these types of transients, the applicant stated that the dynamic loadings occur too rapidly for a 

contribution of the reactor coolant environment on the stress range for the transients. 
Time-Limited Aging Analyses 

 4-36 

The staff noted that acceptable recommendations for calculating Fen factors are provided in 

NUREG/CR-6583 for carbon steel or low-alloy steel materials and in NUREG/CR-5704 for 

austenitic stainless steel materials. The staff also noted that the NRC recommendations for 

calculating Fen factors apply to those transients that are thermally driven and in which the 

exposure of the reactor coolant environment could impact the material properties associated 

with a component’s material of fabrication and potentially the growth rate for any microcracks 

that are postulated in the component’s material. The staff noted that the applicability of the 

staff’s EAF recommendations and application of Fen factor apply only to those transients in 

which there is ample time for the reactor coolant to impact the component. Therefore, the staff 

finds the applicant’s application of a Fen factor of 1.0 for dynamic load transients to be a 

reasonable assumption because the contribution of the reactor coolant on the stress ranges for 

dynamic load transients is negligible. 

For the remaining transients, the applicant clarified that the following strain rate and temperature 

assumptions were used to derive the Fen factors: 

● For all cases, the strain rates and sulfur content used in derivation of the Fen factors 

were those that maximized the Fen values. 

● For all cases, the temperatures used in derivation of the Fen factors assumed a design 

temperature of 550 °F; for the feedwater nozzles, the derivation of the Fen factor used 

the maximum temperature for each load pair in the CUF calculation for the component. 

The staff noted that the applicant’s use of the design temperature of the component is 

reasonable because this should be the maximum temperature the component would experience 

during any transient. The staff finds the use of these assumptions to be acceptable because: 

(1) the Fen factors would be maximized based on the slow strain rate and high sulfur content; 

(2) the applicant used the design temperature of the component; and (3) for the feedwater 

nozzle, the applicant used a refined approach. 

The applicant clarified that the dissolved oxygen level used for the derivation of the Fen factors 

applied a weighted average of the dissolved oxygen content concentration in the reactor coolant 

for both the period when normal water chemistry (NWC) control was applied and the period 

when hydrogen water chemistry (HWC) was applied at the facility. The staff noted the weighted 

average for NWC accounts for 15 percent of the time at power operations and HWC accounts 

for 85 percent of the time at power operations, including time during the period of extended 

operation. The applicant clarified that the average of the dissolved oxygen content value for 

NWC conditions and HWC conditions used the measured oxygen content values, as taken and 

measured in accordance with its chemistry sampling and testing processing activities for the 

primary coolant. 

Based on its review, the staff finds the applicant’s response to RAI 4.3-06 acceptable because 

the applicant: (1) applied those strain rates and sulfur content values that maximized the 

contributions to the Fen factors; (2) either applied appropriate design-basis temperature or 

transient temperatures to the Fen factor; and (3) appropriately accounted for dissolved oxygen 

conditions for both NWC and HWC, as derived from actual plant records or conservatively 

estimated based on those from documented records for periods when NWC and HWC were in 

effect. The staff’s concern described in RAI 4.3-06 is resolved. 
Time-Limited Aging Analyses 

 4-37 

During the staff’s review of LRA Section 4.3.5, the applicant stated that the Fen factor of 1.49 

was used for the Alloy 600 component (CRD penetration and core spray nozzle). However, the 

staff determined that the LRA does not provide sufficient information to determine what 

methodology was used in obtaining Fen. 

By letter dated June 25, 2010, the staff issued RAI 4.3-07 requesting that the applicant: 

(1) justify using the value of 1.49 for the Fen factor if it is not a bounding/conservative value for 

the Alloy 600 component when compared to the Fen factor calculated based on 

NUREG/CR-6909 for nickel alloys, and (2) describe the current or future planned actions to 

update the CUF calculation with the Fen factor for the Alloy 600 component only, consistent with 

the methodology in NUREG/CR-6909. 

In its response dated July 22, 2010, the applicant stated that a review was performed that 

indicates that using the NUREG-6909 methodology would result in a conservative value for a 

Fen of 3.56. The applicant stated that Equations A.14 through A.17 contained in Appendix A to 

NUREG/CR-6909 were used and the review was based on a reactor maximum temperature of 

550 °F and a value for transformed strain rate to maximize Fen. Furthermore, an overall HWC 

availability of 85 percent was accounted for when computing the Fen of 3.56. The applicant 

stated that when using the NUREG/CR-6909 methodology, the resultant EAF CUF for the CRD 

penetration with excavation is 0.80 and for the core spray nozzle safe end, the resultant EAF 

CUF is 0.10. The staff noted that for both components, the resultant EAF CUF is below the 

ASME Code design limit of 1.0. The applicant further stated that a conservative application of 

the NUREG/CR-6909 methodology for the Alloy 600 locations (CRD penetration with excavation 

and core spray nozzle safe end) determined that the 60-year CUF values with a Fen factor 

remain below 1.0 and are acceptable for the period of extended operation, therefore, there are 

no planned actions to update the CUF calculations with a Fen factor consistent with the 

methodology in NUREG/CR-6909. 

By letter dated September 9, 2010, the applicant amended its response to RAI 4.3-07 by stating 

that future revisions or updates to the environmental fatigue calculations for Alloy 600 locations 

will use the data and the methodology that is described in NUREG/CR-6909 or later 

revisions/reports for Ni-Cr-Fe alloys to determine the Fen factor and fatigue usage. The staff 

noted that LRA Table 4.3.1-2 states that the CRD penetration with excavation and core spray 

nozzle safe end components are monitored by CBF monitoring, in which CUF is determined by 

using the actual number of transients that occur and assumes each actual transient has a 

severity equal to that assumed in the design basis. 

The staff finds it acceptable that the applicant will use the methodology in NUREG/CR-6909 in 

future revisions or updates to the environmental fatigue calculations because: (1) the applicant 

counts the number of transient cycles, determines the CUF assuming the severity is equal to 

that assumed in the design basis, and ensures the design limit of 1.0 is not exceeded, and 

(2) the 60-year CUF value with a Fen for both Alloy 600 components before and after using the 

worse-case Fen factor from NUREG/CR-6909 is below the design limit of 1.0. 

Based on its review, the staff finds the applicant‘s response to RAI 4.3-07, as supplemented by 

letter dated September 9, 2010, acceptable because: (1) the applicant calculated the 

worse-case Fen factor for its Alloy 600 components consistent with NUREG/CR-6909, (2) the 

60-year CUF value with a Fen for both Alloy 600 components before and after using the 

worse-case Fen factor calculated consistent with NUREG/CR-6909 is below the design limit of 

1.0, (3) the effects of aging for these Alloy 600 components will be managed by the applicant’s 

Metal Fatigue of Reactor Coolant Pressure Boundary Program that will take corrective actions 
Time-Limited Aging Analyses 

 4-38 

prior to the 60-year CUF value with a Fen exceeding the design limit of 1.0, and (4) the applicant 

committed (Commitment No. 53) to use the data and the methodology that is described in 

NUREG/CR-6909 or later revisions or reports for Ni-Cr-Fe alloys in the determination of the Fen

factor and fatigue usage in its environmental fatigue calculations upon calculation revisions. The 

staff’s concern described in RAI 4.3-07 is resolved. 

4.3.5.3 UFSAR Supplement 

LRA Section A.4.3.5 provides the UFSAR supplement for the effects of reactor coolant 

environment on fatigue life of components and piping (Generic Safety Issue-190) TLAA 

evaluation. Based on its review of the UFSAR supplement, the staff concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d) and consistent with SRP-LR Section 4.3.3.3. 

4.3.5.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging associated with reactor coolant environment on 

fatigue for component piping intended functions 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), and, 

therefore, is acceptable. 
Time-Limited Aging Analyses 

 4-39 

4.4 Environmental Qualification of Electrical Equipment

4.4.1 Summary of Technical Information in the Application 

LRA Section 4.4 summarizes the evaluation of environmental qualification (EQ) of electrical 

equipment for the period of extended operation. The applicant stated that the HCGS EQ 

program is in compliance with the requirements of 10 CFR 50.49 and is being used to manage 

the aging of equipment in the EQ program during the current license term. The applicant also 

stated that the existing HCGS EQ program will be used to manage aging of equipment in the 

EQ program during the period of extended operation and includes provisions to ensure that the 

qualification bases are maintained and the components do not exceed their qualified lives. The 

applicant further stated TLAA disposition to 10 CFR 54.21(c)(1)(iii), which states that the effects 

of aging will be adequately managed for the period of extended operation, and the EQ of 

Electric Components Program will manage the aging effects of the components associated with 

the EQ TLAA. 

4.4.2 Staff Evaluation 

The EQ 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 instrumentation and controls (I&C) components 

that are important to safety and are located in a harsh environment. The harsh environments of 

the plant are those areas subject to environmental effects by a LOCA, HELB, or post-LOCA 

environment. EQ equipment is comprised of safety-related, nonsafety-related equipment that 

the failure of which could prevent satisfactory accomplishment of any safety-related function, 

and necessary post-accident monitoring equipment. 

The staff reviewed LRA Sections 4.4 and B.3.1.2, plant basis documents, additional information 

provided to the staff, and interviewed staff personnel to verify whether the applicant provided 

adequate information to meet the requirement of 10 CFR 54.21(c)(1). For electrical equipment, 

the applicant uses 10 CFR 54.21(c)(1)(iii) in its TLAA evaluation to demonstrate that the aging 

effects of EQ equipment will be adequately managed during the period of extended operation. 

Per NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” Revision 1, dated 

September 2005, plant EQ programs that implement the requirements of 10 CFR 50.49 are 

considered acceptable AMPs for meeting the requirements of 10 CFR 54.21(c)(1)(iii). GALL 

AMP X.E1, “Environmental Qualification (EQ) of Electric Components,” provides a means to 

meet the requirements of 10 CFR 54.21(c)(1)(iii). 

The staff’s evaluation of the applicant’s EQ of Electric Components Program is documented in 

SER Section 3.0.3.1.22. 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 function for the period of extended operation. 
Time-Limited Aging Analyses 

 4-40 

The staff’s evaluation of the component’s 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 and B.3.1.2 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. 

On the basis of its audit, the staff confirmed that each element of the applicant’s program is 

consistent with the corresponding element of GALL 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 AMP X.E1 and, therefore, 

acceptable. The staff further concludes that the applicant’s EQ of electric 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 

LRA Section A.4.4 provides the UFSAR supplement for the EQ of electrical equipment TLAA 

evaluation. The staff reviewed this UFSAR supplement description of the program and notes 

that it conforms to the recommended description for this type of program as described in 

SRP-LR Tables 4.4-1 and 4.4-2. The staff concludes 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 of the applicant’s EQ of electrical equipment TLAA, 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 pursuant to 10 CFR 54.21(c)(1)(iii) 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 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). 
Time-Limited Aging Analyses 

 4-41 

4.5 Loss of Prestress in Concrete Containment Tendons

4.5.1 Summary of Technical Information in the Application 

LRA Section 4.5, stated that HCGS containment does not have prestressed tendons. As such, 

loss of prestress in concrete containment tendons is not a TLAA. 

4.5.2 Staff Evaluation 

The staff reviewed the applicant’s UFSAR supplement and confirmed that the containment does 

not have prestressed tendons and, therefore, finds the applicant’s statement acceptable. 

4.5.3 UFSAR Supplement 

LRA Section A.4.5 provides the UFSAR supplement for the fatigue analyses of loss of prestress 

in concrete containment tendons TLAA evaluation. The staff reviewed the applicant’s UFSAR 

supplement and confirmed that the containment does not have prestressed tendons and, 

therefore, finds the applicant’s statement acceptable. 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) and consistent with SRP-LR Section 4.5.3.2. 

4.5.4 Conclusion 

Based on its review, the staff concludes that loss of prestress in concrete containment tendons 

is not a TLAA. 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), and, therefore, is 

acceptable. 
Time-Limited Aging Analyses 

 4-42 

4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analyses

The interior surface of a concrete containment structure is lined with thin metallic plates to 

provide a leak-tight barrier against the uncontrolled release of radioactivity to the environment. 

The liner plates are attached to the concrete containment wall by an anchorage system. The 

design process assumes that the liner plates do not carry loads. However, normal loads, such 

as from concrete shrinkage, creep, and thermal changes, imposed on the concrete containment 

structure, are transferred to the liner plates through the anchorage system. Internal pressure 

and temperature loads are directly applied to the liner plates. Thus, under design-basis 

conditions, the liner plate could experience significant strains. 

The containment liner plates, metal containments, penetration sleeves, and penetration bellows 

may be designed in accordance with requirements of the ASME B&PV Code Section III. If a 

plant’s code of record requires a fatigue analysis, then this analysis may be a TLAA and must 

be evaluated in accordance with 10 CFR 54.21(c)(1) to ensure that the effects of aging on the 

intended functions will be adequately managed for the period of extended operation. 

4.6.1 Fatigue Analysis of Primary Containment, Attached Piping, and Components 

4.6.1.1 Summary of Technical Information in the Application 

Section 4.6.1, stated that the HCGS primary containment was designed in accordance with the 

ASME Code Section III. Subsequently, during large-scale testing for the Mark III containment 

system and the in-plant testing for Mark I primary containment systems, new suppression 

chamber hydrodynamic loads were identified. Therefore, re-evaluation of the primary 

containment structure was performed in two parts: generic analyses applicable to each of the 

several classes of BWR containments, and Mark I Containment Program plant-unique analyses. 

The Mark I analyses are detailed in the HCGS Plant Unique Analysis Report (PUAR) and 

assume 596 single safety relief valve (SRV) lifts and 370 multiple SRV lifts. 

In the LRA, the applicant also stated that to address license renewal requirements, the historical 

number of SRV lifts was researched to determine the number of SRV lifts from 1986 (initial plant 

startup testing) through the end of 2007. Based on this research, the applicant has projected 

592 single SRV lifts and 26 multiple lifts for 60 years of operation. Both of these numbers are 

below the values assumed in the Mark I analyses (596 single SRV lifts and 370 multiple SRV 

lifts). The applicant further stated that the associated CUF are projected to be within the original 

design assumptions and that all relevant plant transient events will be tracked to ensure that the 

CUF remains less than 1.0 for all monitored components. This conclusion is based on a 

comprehensive review governing fatigue analyses of the bounding set of primary containment 

locations. The scope of the analyses includes the pressure suppression chamber (shells and 

welds), the drywell-to-pressure suppression chamber vents (header and downcomers), SRV 

discharge piping, other piping attached to the pressure suppression chamber, penetrations, and 

vent bellows. The applicant has dispositioned this TLAA in accordance with 

10 CFR 54.21(c)(1)(iii), using the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

to monitor the number of cycles of the design transients and the corresponding CUF for critical 

primary containment components. 
Time-Limited Aging Analyses 

 4-43 

4.6.1.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.1 and found that the number of cycles and the associated 

CUF are projected to be within the original design assumptions. The CUF for the different 

components of the HCGS primary containment are listed in the LRA Table 4.6.1-1. The 

maximum design-basis CUF of 0.98 for 40-year life is for the drywell shell at vent line 

penetration. Therefore, the applicant has committed to monitor the number of cycles at this 

particular location prior to the period of extended operation. 

For all other locations, the design-basis CUF for 40-year life is less than 0.80, and the estimated 

CUF, based on projected number of cycles for 60 years of operations is not more than 0.366. 

However, the applicant plans to track all relevant plant transient events to ensure that the CUF 

remains less than 1.0 for all monitored components. The applicant will perform validation for 

primary containment locations by monitoring the design-basis CUF ratios that exceed 0.4 (or 

40 percent of the allowable value). For locations with a CUF less than 0.4, a 20-year increase 

in service life will not raise the CUF significantly close to the allowable value of 1.0 and will not 

be monitored. 

Therefore, the staff has determined that the effects of aging on the primary containment 

components will be adequately managed for the period of extended operation. The Metal 

Fatigue of Reactor Coolant Pressure Boundary Program will monitor the number of cycles of the 

design transients and the corresponding CUF for critical primary components, thus, managing 

the effects of aging due to fatigue on the primary containment, in accordance with 

10 CFR 54.21(c)(1)(iii). The staff’s evaluation of the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program is documented in SER Section 3.0.3.2.19. 

4.6.1.3 UFSAR Supplement 

LRA Section A.4.6.1 provides the UFSAR supplement for the fatigue analyses of primary 

containment, attached piping, and components TLAA evaluation. The staff reviewed this 

UFSAR supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR Table 4.6-1. The staff concludes 

that the information in the UFSAR supplement is an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

4.6.1.4 Conclusion 

Based on its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended function(s) will be adequately 

managed for the period of extended operation and found that the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program will monitor the effects of aging due to fatigue on the 

primary containment, attached piping, and components in accordance with 

10 CFR 54.21(c)(1)(iii). 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), and 

therefore, is acceptable. 
Time-Limited Aging Analyses 

 4-44 

4.6.2 Primary Containment Process Penetrations and Bellows Fatigue Analysis 

4.6.2.1 Summary of Technical Information in the Application 

In LRA Section 4.6.2, the applicant stated that the primary containment process piping 

penetrations meet ASME Code Section III, Class 1 or 2 requirements, as applicable. The 

primary containment process piping penetrations use flued heads to connect the process piping 

to the drywell sleeves. The flued heads for the ASME Code Section III, Class 1 process piping 

systems have been analyzed for fatigue. These Class 1 fatigue analyses are based upon 

thermal cycles specified for the 40-year life of the plant and have, therefore, been identified as 

TLAAs requiring evaluation for the period of extended operation. The applicant further stated 

that the maximum 40-year CUF ratio (CUF/allowable) identified for any of these penetrations is 

0.957 for feedwater penetrations P-2A and P-2B. 

Since these two penetration locations have CUF ratios that exceed 0.4, the triple flued heads 

will be included in the Metal Fatigue of Reactor Coolant Pressure Boundary Program as a 

program enhancement. All relevant plant transient events will be tracked to ensure that the 

CUF remains less than 0.1 for these two triple flued heads. Furthermore, the applicant stated 

that all other governing penetration fatigue analyses have been reviewed, and the CUF ratios 

for all other penetrations are less than 0.4. 

The applicant also stated that the penetration design includes a flexible bellows to seal the triple 

flued head to the drywell penetration sleeve. The flexible bellows were designed in accordance 

with ASME Code Section III, Class 2 requirements. The applicant further stated that analyses 

for the flexible bellows were reviewed. It was determined that the fatigue usage experienced by 

the flexible bellows was bounded by the corresponding attached triple flued head. Monitoring of 

the fatigue usage for the triple flued heads will provide assurance that no flexible bellows will 

exceed its allowable value. The applicant has dispositioned this TLAA in accordance with 

10 CFR 54.21(c)(1)(iii), using the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

to monitor the number of cycles of the design transients and the CUF for the triple flued heads. 

4.6.2.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.2 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. 

The staff noted that the maximum 40-year CUF ratio identified for any of these penetrations is 

0.957 for feedwater penetrations P-2A and P-2B. However, the applicant has stated that since 

these two penetration locations have CUF ratios that exceed 0.4, the triple flued heads will be 

included in the Metal Fatigue of Reactor Coolant Pressure Boundary Program as a program 

enhancement. All relevant plant transient events will be tracked to ensure that the CUF remains 

less than 0.1 for these two triple flued heads. 

In a letter dated June 1, 2010, the staff issued RAI 4.6-1 requesting that the applicant explain 

how all relevant plant transient for feedwater penetrations P-2A and P-2B will be tracked to 

ensure that the CUF remains less than 0.1. 

In its response to RAI 4.6-1 dated June 24, 2010, the applicant stated that feedwater 

penetrations are located in a no-break zone for the HELB. Therefore, their allowable CUF is 
Time-Limited Aging Analyses 

 4-45 

0.10. The design CUF is divided by the allowable CUF to determine the CUF ratio. The 

applicant further stated that the 40-year design fatigue value for these two penetrations is 

0.0957 and CUF ratio of 0.957. Therefore, these two penetrations will be monitored using the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program. 

The staff’s evaluation of the Metal Fatigue of Reactor Coolant Pressure Boundary Program is 

documented in SER Section 3.0.3.2.19. The staff reviewed the applicant’s response to 

RAI 4.6-1 and found it acceptable because the applicant’s use of design CUF of 0.10 is 

consistent with UFSAR Section 3.6.2.1.1.1. According to UFSAR Section 3.6.2.1.1.1, the 

feedwater system piping penetrations are not designed to withstand the loadings resulting from 

a HELB and are designed for a CUF of less than 0.1 associated with normal, upset, and testing 

conditions. Therefore, the applicant’s commitment to monitor these two penetrations using the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program is acceptable. 

4.6.2.3 UFSAR Supplement 

LRA Section A.4.6.2 provides the UFSAR supplement for the fatigue analyses of primary 

containment process penetrations and bellows TLAA evaluation. The staff reviewed this 

UFSAR supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR Tables 4.6-1. The staff concludes 

that the information in the UFSAR supplement is an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

4.6.2.4 Conclusion 

Based on its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

function(s) will be adequately managed for the period of extended operation and found that the 

triple flued heads will be included in the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program as a program enhancement to monitor the effects of aging due to fatigue on the 

primary containment process piping penetrations and bellows in accordance with 

10 CFR 54.21(c)(1)(iii). 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), and 

therefore, is acceptable. 

4.6.3 Vent Line Bellows 

4.6.3.1 Summary of Technical Information in the Application 

In LRA Section 4.6.3, the applicant stated that the fatigue evaluation for the vent line bellows 

that seal the drywell shell to the vent lines, which connect to the torus, is based on the number 

of cycles assumed for the 40-year life of the plant. The applicant also stated that the originally 

specified number of thermal load and internal pressure cycles was 150 cycles and the bellows 

have a rated capacity of 230 cycles at maximum displacements for normal operating conditions. 

The applicant further stated that the maximum number of startup and shutdown cycles expected 

for 60 years of operation at HCGS is 180 cycles, based on LRA Table 4.3.1-1. 

The applicant stated that since the allowable number of cycles, at maximum displacements for 

normal operating conditions, are greater than those projected for 60 years, the fatigue 
Time-Limited Aging Analyses 

 4-46 

evaluation for the vent line bellows remains valid for the period of extended operation, in 

accordance with 10 CFR 54.21(c)(1)(i). 

4.6.3.2 Staff Evaluation 

The staff reviewed LRA Section 4.6.3 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation. The staff noted that in LRA 

Table 4.3.1-1, the startup and shutdown cycles as of December 31, 2007, were 79 cycles and 

the projected cycles for 40 years and 60 years were 125 cycles and 174 cycles, respectively, 

based on the number of events as of December 31, 2007, and the trends from the past 12 years 

of the actual plant operation. The rated capacity of the bellows is 230 cycles at maximum 

displacements for normal operating conditions. 

Based on its review, the staff finds that the fatigue evaluation for the vent line bellows remains 

valid for the period of extended operation since the allowable number of cycles, at maximum 

displacements for normal operating conditions, is greater than those projected for 60 years. 

4.6.3.3 UFSAR Supplement 

LRA Section A.4.6.3 provides the UFSAR supplement for the fatigue analyses of the vent line 

bellows TLAA evaluation. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 4.6-1. The staff concludes that the information in the UFSAR 

supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

4.6.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), for the vent line bellows fatigue TLAA, the 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), and 

therefore, is acceptable. 
Time-Limited Aging Analyses 

 4-47 

4.7 Other Plant-Specific Time Limited Aging Analyses

There are certain plant-specific safety analyses that may have been based on an explicitly 

assumed 40-year plant life and may, therefore, be TLAAs. Pursuant to 10 CFR 54.21(c), the 

applicant is required to evaluate TLAAs. 

This subsection is the staff’s review of other plant-specific TLAAs that the applicant has 

evaluated in the LRA. 

4.7.1 Crane Load Cycle Limit 

4.7.1.1 Summary of Technical Information in the Application 

In LRA Section 4.7.1, the applicant stated that the reactor building polar crane and the service 

water intake structure gantry crane are within the scope of license renewal and have been 

identified as having a TLAA, which requires evaluation for 60 years as follows: 

Reactor Building Polar Crane. The applicant stated that the reactor building polar crane at 

HCGS is designed to meet or exceed the design fatigue requirements of the Crane 

Manufacturers Association of America (CMAA) Specification 70, “Specifications for Top Running 

Bridge and Gantry Type Multiple Girder Electric Overhead Traveling Cranes.” The applicant 

also stated that the polar crane was designed for a minimum of 100,000 load cycles, 

corresponding to the criteria of CMAA Specification 70 for service Class A. The applicant 

further stated that the total number of lifts for the polar crane has been estimated to be 

2,720 cycles for the total life of the plant, including the period of extended operation associated 

with license renewal. The applicant stated that this estimated data is less than the minimum 

allowable design value of 100,000 cycles. 

Service Water Intake Structure Gantry Crane. The applicant stated that the service water intake 

structure gantry crane purchasing specification required that the crane conform to the latest 

edition CMAA, Specification 70 for electric overhead traveling cranes, and was designed for 

100,000 to 500,000 load cycles. The applicant also stated that a review of service water intake 

structure gantry crane operation during the current life of the plant, including an estimated 

200 lifts during original construction, indicates that the total number of lifts is less than 

600 cycles. The applicant further stated that an average rate of 32 lifts per year over the course 

of 60 years results in the service water intake structure gantry crane experiencing 1,920 lifts. 

The applicant stated that these estimated data are less than the minimum allowable design 

value of 100,000 cycles. 

The applicant dispositioned these TLAAs in accordance with 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation. 

4.7.1.2 Staff Evaluation 

The staff reviewed LRA Section 4.7.1 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation. The staff noted that in LRA 

Section 2.3.3.8, “Scoping and Screening,” the applicant listed a total of 18 cranes and hoists as 

within the scope of license renewal. LRA Table 3.3.2-8 requires a TLAA for component group 
Time-Limited Aging Analyses 

 4-48 

“Crane/Hoist Bridge/Trolley Girders” for aging management due to cumulative fatigue damage 

and fatigue per the GALL Report recommendations. 

Therefore, by letter dated June 1, 2010, the staff issued RAI 4.7-1 requesting that the applicant 

explain why the reactor building polar crane and the service water intake structure gantry crane 

are the only two cranes with a TLAA when there are 18 cranes within the scope of license 

renewal. 

In its response to RAI 4.7-1, dated June 24, 2010, the applicant stated that a review of potential 

TLAAs related to the cranes and hoists for the LRA did not identify calculations or analyses for 

any of the in-scope cranes that involved time-limited assumptions. Structural calculations were 

provided by the vendors during original design and construction of HCGS for the reactor 

building polar crane and service water intake gantry crane. These calculations, along with other 

documents for the two cranes, were found to contain references to procurement specifications 

that require the cranes to be designed in accordance CMAA Specification 70, “Specifications for 

Top Running Bridge and Gantry Type Multiple Girder Electric Overhead Traveling Cranes.” As 

a result, these two cranes were conservatively considered to have TLAAs and evaluated with a 

service class consisting of 100,000 to 500,000 load cycles. 

In its response of June 24, 2010, the applicant also stated that only other in-scope girders for 

HCGS are associated with the main steam tunnel underhung bridge crane and diesel generator 

underhung cranes. These cranes are nonsafety-related, but were evaluated as potential 

TLAAs; however, no potential calculations or analyses were identified that meet the definition of 

TLAA per 10 CFR 54.3(a). The applicant further stated that the other in-scope cranes are 

simple devices and do not have a TLAA. 

Based on the review of LRA Section 4.7.1 and the applicant’s response to RAI 4.7-1, the staff 

has concluded that the effects of aging on the in-scope cranes has been properly evaluated and 

will be adequately managed for the period of extended operation because: 

The reactor building polar crane is designed, and complies, with the CMAA Specification 70 and 

Class A requirement. The crane, therefore, was designed for a minimum of 100,000 load cycles 

for a 40-year life. The number of maximum rated load cycles for the polar crane originally 

projected for a 60-year life has been estimated to be 2,720, which are significantly less than the 

design limit of 100,000 cycles. 

The service water intake structure gantry crane purchasing specification required that the crane 

conform to the latest edition of design for 100,000 to 500,000 load cycles. The number of 

estimated rated load cycles for the service water intake structure gantry crane for a 60-year life 

has been estimated to be 1,920, which is significantly less than the design limit of 100,000 

cycles. 

The main steam tunnel underhung bridge crane and diesel generator underhung cranes are: 

(1) nonsafety-related and original design-basis documents do not include any calculation or 

analysis, (2) designed and procured to conform with CMAA Specification 70 and Class A 

requirements, and (3) less frequently used as compared to the reactor building polar crane. 

Therefore, the main steam tunnel underhung bridge crane and diesel generator underhung 

cranes do not require TLAAs per 10 CFR 54.3(a). 

The other 14 in-scope cranes are simple devices consisting of hoists and monorails, do not 

have any bridge or trolley girders, and do not require TLAAs in accordance with 10 CFR 54.3(a). 
Time-Limited Aging Analyses 

 4-49 

4.7.1.3 UFSAR Supplement 

LRA Section A.4.7.1 provides the UFSAR supplement for the load cycle limits of reactor building 

polar crane and service water intake structure gantry crane TLAA evaluation. The staff 

reviewed this UFSAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program as described in SRP-LR Section 4.7.3.2. The 

staff concludes that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

4.7.1.4 Conclusion 

Based on its review, as discussed above, the staff concludes, that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for fatigue load cycle limits of the reactor 

building polar crane and the service water intake structure gantry crane, the analyses remain 

valid for the period of extended operation. The other in-scope cranes are not frequently used 

and do not require a TLAA in accordance with 10 CFR 54.3(a). 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), and therefore, is acceptable. 

4.7.2 Refueling Bellows Fatigue 

4.7.2.1 Summary of Technical Information in the Application 

LRA Section 4.7.2 discusses refueling bellows fatigue. The applicant stated that a fatigue 

analysis was performed for each of the two bellows that seal the drywell bulkhead and RV and 

the drywell bulkhead and drywell shell for refueling operations. The applicant also stated that 

fatigue analysis for each of these bellows is based on the number of cycles assumed for the 

40-year life of the plant; therefore, these analyses satisfy the criteria of 10 CFR 54.3(a) and are 

evaluated as TLAAs in accordance with 10 CFR 54.21(c). 

The applicant stated that the bulkhead-to-drywell bellows exhibited the highest calculated 

fatigue usage of 0.124. The applicant further stated that fatigue usage for both bellows was 

determined by the number of cycles of startup and shutdown and the number of flood-up events 

at each refueling outage. The applicant indicated that the fatigue analysis assumed 360 cycles 

for startup and shutdown and reflood over the life of the plant. 

The applicant also stated that, as listed in LRA Table 4.3.1-1, the maximum number of startup 

and shutdown cycles expected for 60 years of operations at HCGS is 180 cycles for startup and 

shutdown and 55 cycles for refueling operations, for a total of 235 cycles. The applicant 

concluded that since the number of cycles used in the analyses for these events are greater 

than those projected for 60 years, the fatigue analyses for the refueling bellows remain valid for 

the period of extended operation. The applicant dispositioned this refueling bellows fatigue 

TLAA in accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of 

extended operation. 
Time-Limited Aging Analyses 

 4-50 

4.7.2.2 Staff Evaluation 

The staff reviewed the TLAA in LRA Section 4.7.2 against the acceptance guidance in SRP-LR 

Section 4.7.3.1.1 for dispositioning plant-specific TLAAs in accordance with 

10 CFR 54.21(c)(1)(i). LRA Section 4.7.2 states that the refueling bellows were designed for 

360 cycles for startup and shutdown and reflood over the life of the plant. The staff noted that 

the applicant has projected the number of startup and shutdown and reflood cycles to the end of 

the period of extended operation to be 235 cycles. 

The staff reviewed LRA Table 4.3.1-1 to determine how the applicant projected the number of 

cycles for 60 years. The staff determined that the applicant has counted the number of events 

as of December 31, 2007, and projected this number forward for 60 years based on trends from 

the past 12 years (9 operating cycles) of actual plant operation. The staff determined that the 

applicant appropriately projected the number of cycles for 60 years. Based on this 

consideration, the staff finds the applicant’s claim that the refueling bellows will maintain their 

structural integrity during the period of the extended operation acceptable because: (1) the 

maximum number of startup and shutdown, and reflood cycles projected for 60 years (e.g., 

235 cycles) have been demonstrated to be bounded by the 360 cycle limit assumed in the 

refueling bellows fatigue analysis; (2) the highest calculated fatigue usage for 40-year life is 

0.124, which is significantly less than the limit of 1.0; and (3) the analysis demonstrates 

compliance with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(i), in that the current 

analysis has been demonstrated to remain valid for the period of extended operation. 

4.7.2.3 UFSAR Supplement 

LRA Section A.4.7.2 provides the UFSAR supplement for the load cycle limits of refueling 

bellows fatigue TLAA evaluation. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Section 4.7.3.2. The staff concluded that the information in the UFSAR 

supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

4.7.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the refueling bellows fatigue in the CLB has been demonstrated to 

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). 

4.7.3 Neutron Fluence-Induced Bolt Stress Relaxation – Jet Pump Auxiliary Spring 

Wedges and Slip Joint Clamps 

4.7.3.1 Summary of Technical Information in the Application 

LRA Section 4.7.3 presents the applicant’s evaluation of the bolt stress relaxation in auxiliary 

spring wedges (installed in 2007 and 2009) and the slip joint clamps (installed on the jet pumps 

in 2006). 
Time-Limited Aging Analyses 

 4-51 

For the auxiliary spring wedge bolts, the original evaluation showed that the preload on the bolts 

would be acceptable up to a neutron fluence (energy > 1.0 MeV) of 1.07 x 1020 neutrons per 

square centimeter (n/cm2) for the 40-year life of the jet pumps. A new analysis has determined 

that the actual neutron fluence on the auxiliary spring wedge bolts after 60 years of service for 

the jet pumps at HCGS is below the original 40-year value. Since the projected 60-year neutron 

fluence on the auxiliary spring wedge bolts is bounded by the initial neutron fluence of 

1.07 x 1020 n/cm2

, the analysis remains valid for the period of extended operation. 

For the slip joint clamp bolts, the original evaluation showed that the preload on the bolts would 

be acceptable up to a neutron fluence of 1.50 x 1018 n/cm2

 for the 40-year life of the jet pumps. 

A new analysis has determined that the actual neutron fluence on the slip joint clamp bolts will 

reach the bounding fluence of 1.50 x 1018 n/cm2

 after 35.4 EFPY of service for the jet pumps at 

HCGS. 

Since the analysis on the slip joint clamp bolts is not bounding for the period of extended 

operation, the staff discussed its concern in a telephone call on September 2, 2010. In a letter 

dated September 9, 2010 (ADAMS Accession No. ML102580031), the applicant committed 

(Commitment No. 52) to: (1) replace the slip joint clamp at the last refueling outage prior to 

reaching the bounding value of 35.4 EFPY, or (2) 2 years before reaching the bounding value of 

35.4 EFPY, perform an analysis that demonstrates that the function of the component is 

maintained. 

4.7.3.2 Staff Evaluation 

The staff reviewed LRA Section 4.7.3 to evaluate that the neutron fluence-induced bolt stress 

relaxation analyses of the auxiliary spring wedge bolts and slip joint clamp bolts have been 

projected to the end of the period of extended operation. The applicant performed a new 

analysis for each of the two cases. 

For the first TLAA (the auxiliary spring wedge bolts), the new analysis showed that the projected 

neutron exposure on the bolts after 60 years of service for the jet pumps will be less than the 

original, conservative estimate of 1.07 x 1020 n/cm2 for a 40-year life. Therefore, given the 

updated analysis, the staff agrees that the current analysis for the auxiliary spring wedge bolts 

remains valid for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i). 

For the second TLAA (the slip joint clamp bolts), the new analysis showed that the projected 

neutron exposure on the slip joint clamp bolts will exceed the original estimate of 

1.50 x 1018 n/cm2 after 35.4 EFPY of service for the jet pumps at HCGS; this TLAA is not 

bounded by the original analysis for the period of extended operation. Therefore, HCGS will 

either: (1) replace the slip joint clamp at the last refueling outage prior to reaching the bounding 

value of 35.4 EFPY; or (2) 2 years before the neutron fluence reaches the bounding value of 

35.4 EFPY , perform an analysis that demonstrates that the function of the component is 

maintained. 

Therefore, given the applicant’s commitment, the staff agrees that the second TLAA for the 

auxiliary spring wedge bolts will be managed for the period of extended operation, in 

accordance with 10 CFR 54.21(c)(1)(iii). 
Time-Limited Aging Analyses 

 4-52 

4.7.3.3 UFSAR Supplement 

LRA Section A.4.7.3 provides the UFSAR supplement of its neutron fluence-induced bolt stress 

relaxation TLAA evaluation. The staff reviewed this UFSAR supplement description of the 

program and notes that it conforms to the recommended description of this type of program as 

described in SRP-LR Section 4.7.3.2. The staff also notes that the applicant committed in a 

revised Commitment No. 52 to either: (1) replace the slip joint clamp at the last refueling outage 

prior to reaching the bounding value of 35.4 EFPY; or (2) 2 years before the neutron fluence 

reaches the bounding value of 35.4 EFPY, perform an analysis that demonstrates that the 

function of the component is maintained. 

On the basis of its review, the staff finds the summary description of the applicant’s actions to 

address neutron fluence-induced bolt stress relaxation adequate, 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 has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the neutron fluence-induced bolt stress relaxation TLAA for the 

auxiliary spring wedge bolts remains valid for the period of extended operation. For the neutron 

fluence-induced bolt stress relaxation analysis of the slip joint clamp bolts, the applicant will 

manage aging, pursuant to 10 CFR 54.21(c)(1)(iii), according to a revised Commitment No. 52. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluations, as required by 10 CFR 54.21(d), and therefore, is 

acceptable. 

4.8 Conclusion for Time-Limited Aging Analyses

The staff reviewed the information in LRA Section 4, “Time-Limited Aging Analyses.” On the 

basis of its review, the staff concludes that the applicant has provided a sufficient list of TLAAs, 

as defined in 10 CFR 54.3, and that the applicant has demonstrated that: (1) the TLAAs will 

remain valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i); (2) the 

TLAAs have been projected to the end of the period of extended operation, as required by 

10 CFR 54.21(c)(1)(ii); or (3) that the effects of aging on intended functions will be adequately 

managed for the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii). The staff 

also reviewed the UFSAR supplement for the TLAAs and finds that the supplement contains 

descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In addition, 

the staff concludes, as required by 10 CFR 54.21(c)(2), that no plant-specific, TLAA-based 

exemptions are in effect. 

With regard to these matters, the staff concludes that there is reasonable assurance that the 

activities authorized by the renewed licenses will continue to be conducted in accordance with 

the CLB and that any changes made to the CLB, 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 

The NRC staff issued its safety evaluation report (SER) with open items related to the renewal 

of the operating license for Hope Creek Generating Station (HCGS) on September 30, 2010. 

On November 3, 2010, the applicant presented its license renewal application, and the staff 

presented its review findings to the ACRS Plant License Renewal Subcommittee. The staff 

reviewed the applicant’s comments on the SER and completed its review of the license renewal 

application. The staff’s evaluation is documented in an SER that was issued by letter dated 

March 9, 2011. Subsequently, the staff received additional information from the applicant dated 

May 19, 2011, regarding the ASME Section XI, Subsection IWE Program which manages the 

drywell air gap drain lines. Specifically, the applicant noted that, based on boroscope 

inspections, it could not verify the actual configuration of the drain lines and provided additional 

enhancements to the ASME Section XI, Subsection IWE Program. The staff revised the SER to 

reflect the staff’s latest evaluation of the applicant’s ASME Section XI, Subsection IWE Program 

and its review is documented in SER Section 3.0.3.2.14. 

During the 594th meeting of the ACRS, June 8-10, 2011, the ACRS completed its review of the 

HCGS license renewal application and the NRC staff’s SER. The ACRS documented its 

findings in a letter to the Commission dated June 16, 2011. A copy of this letter is provided on 

the following pages of this SER Section. 
 5-2 

UNITED STATES 

NUCLEAR REGULATORY COMMISSION 

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 

WASHINGTON, DC 20555 - 0001 

June 16, 2011 

The Honorable Gregory B. Jaczko 

Chairman 

U. S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL 

 APPLICATION FOR THE HOPE CREEK GENERATING STATION 

Dear Chairman Jaczko: 

During the 584th meeting of the Advisory Committee on Reactor Safeguards, June 8-10, 2011, 

we completed our review of the license renewal application for the Hope Creek Generating 

Station (HCGS) and the final Safety Evaluation Report (SER) prepared by the NRC staff. 

During our 583rd meeting, May 12-14, 2011, we reviewed a previous version of this application 

and the associated staff SER. Our Plant License Renewal Subcommittee also reviewed this 

matter during its meeting on November 3, 2010. During these reviews, we had the benefit of 

discussions with representatives of the NRC staff and PSEG Nuclear, LLC (PSEG or the 

applicant). We also had the benefit of the documents referenced. This report fulfills the 

requirement of 10 CFR 54.25 that the ACRS review and report on all license renewal 

applications. 

CONCLUSION AND RECOMMENDATION

1. The programs established and committed to by the applicant to manage age-related 

degradation provide reasonable assurance that HCGS can be operated in accordance with 

its current licensing basis (CLB) for the period of extended operation (PEO) without undue 

risk to the health and safety of the public. 

2. The PSEG application for renewal of the operating license of HCGS should be approved. 

BACKGROUND AND DISCUSSION

HCGS is a General Electric (GE) Model 4 boiling water reactor (BWR) with a Mark I 

containment. HCGS is located approximately 40 miles from Philadelphia, Pennsylvania, and 8 

miles from Salem, New Jersey. The licensed power output of the unit is 3,840 megawatts 

thermal with a gross electrical output of approximately 1,268 megawatts electric. PSEG has 

requested renewal of the HCGS operating license for 20 years beyond the current license term, 

which expires on April 11, 2026. 

In the final SER, the staff documented its review of the license renewal application and other 

information submitted by the applicant or obtained from the staff audits and inspection at the 

plant site. The staff reviewed the completeness of the applicant’s identification of the structures, 

systems, and components (SSCs) that are within the scope of license renewal; the integrated 
 5-3 

plant assessment process; the applicant’s identification of the plausible aging mechanisms 

associated with passive, long-lived components; the adequacy of the applicants Aging 

Management Programs (AMPs); and the identification and assessment of time-limited aging 

analyses (TLAAs) requiring review. 

In the HCGS license renewal application, PSEG identified the SSCs that fall within the scope of 

license renewal. For these SSCs, the applicant performed a comprehensive aging 

management review. Based on this review, the applicant will implement 47 AMPs for license 

renewal, of which 33 are existing programs and 14 are new programs. Fifteen of the programs 

are enhanced and eight programs have exceptions compared with the corresponding programs 

described in the Generic Aging Lessons Learned (GALL) Report. Six of the programs are plant 

specific programs that do not have counterparts in the GALL Report. The PSEG application 

either demonstrates consistency with the GALL Report or documents deviations to the 

approaches specified in the Report. We have reviewed the exceptions and agree with the staff 

that they are acceptable. 

The staff conducted two license renewal audits and an inspection at HCGS. The audits verified 

the appropriateness of the scoping and screening methodology, aging management review, and 

associated AMPs. The inspection verified that the license renewal requirements are 

appropriately implemented. Based on the audit and inspection, the staff concluded in the final 

SER that the proposed activities will reasonably manage the effects of aging of SSCs identified 

in the application and that the intended functions of these SSCs will be maintained during the 

PEO. We agree with these conclusions. 

Industry operating experience documents instances of corrosion on inaccessible exterior 

surfaces of the drywell shell of GE BWR Mark I containments. PSEG performed ultrasonic 

thickness (UT) measurements, for the drywell shell in 2007 and 2009. The results of these 

inspections showed no loss of material due to corrosion. A small reactor cavity leak was 

identified in 2009 during the refueling outage. The leak only occured when the reactor cavity 

was flooded. The probable leakage path is through a weld defect in the reactor cavity seal plate 

through the air gap between the drywell shell and the concrete shield wall. Some leakage 

exited the air gap through an instrument penetration sleeve in the concrete shield wall and 

formed a small puddle on the torus room floor. 

Borescope inspections indicated that wetting of the concrete occurred over about a 30° azimuth 

span. Such leakage could collect at the base of the gap between the shell and the shield wall. 

There were supposed to be drain lines at the base of this gap to prevent moisture collection, but 

borescope examinations of each of the four drain lines showed that all of the drain lines were 

blocked. Probes inserted into the exit of one drain line in the torus room indicate that the line is 

blocked about six feet from the inner surface of the concrete shield wall. The configuration of 

the other three drains is not known at this time, but all of the drains are, and probably have 

been, nonfunctional since original construction. Thus, potential moisture from leaks could 

collect at the base of the drywell gap and wet a ring of the drywell shell about 1.4 feet in height 

before spilling out of the openings around the drywell vent lines. However, no spillage has been 

observed. 

PSEG has made many UT measurements around the drywell shell at the base of the air gap 

and up the drywell shell opposite the known wetted area of the concrete. All the measured 

thicknesses, except for a small region at the base of the drywell air gap in the region where 

wetting of the concrete could be observed at higher elevations, are above the nominal 
 5-4 

thicknesses and the design thicknesses. The minimum measured thickness is well above that 

assumed in the design analyses. 

The AMP for the drywell shell is based on ASME Section XI, Subsection IWE. PSEG has 

committed to a number of enhancements beyond this program. They will continue to search for 

the source of the reactor cavity water leakage and repair it, if practical, before the PEO. PSEG 

will verify that the reactor cavity seal rupture drain lines are open. The program also commits to 

the establishment of drainage from the bottom of the air gap drains and provides for augmented 

UT examinations of the drywell shell to provide assurance of the integrity of the drywell shell. 

To ensure compliance with these commitments, the staff has added two license conditions: 

The first of these requires the applicant to establish drainage capability from the bottom of the 

drywell air gap from all four quadrants. Until drainage is established, the applicant will perform 

borescope examinations and UT measurements. The applicant will monitor penetration sleeve, 

J13, daily for water leakage when the reactor cavity is flooded and will submit a report to the 

staff summarizing the results from the borescope examinations, UT measurements, and 

leakage detected from the penetration. 

The second license condition requires PSEG to submit a report to the staff when drainage has 

been established from the bottom of the air gap in all four quadrants. PSEG will also perform 

UT measurements during the next three refueling outages and submit a report to the staff 

summarizing the results from the UT measurements. 

Based on this enhanced AMP for the drywell shell, the staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions of the primary containment will be maintained consistent with the CLB for the PEO. 

We concur with the staff's conclusion. 

Inaccessible medium-voltage cables in certain manholes at HCGS have been exposed to 

significant moisture, i.e., in standing water for more than a few days. The staff has identified 

water in manholes as a generic, current operating plant issue in Information Notice 2002-12, 

“Submerged Safety-Related Electrical Cables,” dated March 21, 2002, and Generic Letter 2007-

01, “Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation 

Systems or Cause Plant Transients,” dated February 7, 2007. During the current period of 

operation, this issue is being addressed through the reactor oversight process, in accordance 

with the requirements of 10 CFR Part 50. 

The problem is exacerbated at HCGS because the service water cable vaults are not easily 

accessible. They have 60-ton concrete blocks as covers. In addition, there are sections of inscope cables that go in duct banks below the elevation of the manholes. Operating experience 

suggests that the moisture ingress is event-driven, i.e., infiltration from storms. Physical 

modifications have been made to the service water cable vault covers to allow more frequent 

inspection and dewatering. PSEG is also making repairs to try to reduce inleakage. Despite a 

history of water intrusion, HCGS has no history of failures of in-scope inaccessible low and 

medium voltage power cables. 

PSEG has committed to implement a Non-EQ Inaccessible Medium-Voltage Cables Program. 

This program includes (1) testing of in-scope, inaccessible cables (480 volts (V); 4,160V; and 

13,800V) that are exposed to significant moisture, and (2) inspection of cable vaults, including 
 5-5 

subsequent removal of accumulated water if required, as a preventive measure to minimize the 

potential exposure of in-scope cables to significant moisture. 

In-scope cables will be subject to electrical performance testing to ensure suitability for 

operation. The cables will be tested to detect deterioration of the insulation system due to 

wetting, using tests such as power factor, partial discharge, or polarization index, as described 

in EPRI TR-103834-P1-2, or other testing that is state-of-the-art at the time the test is 

performed. PSEG currently uses Tan δ testing on in-scope medium voltage cables and 

insulation resistance testing on in-scope low voltage power cables. The cable test frequency 

will be established based on test results and industry operating experience. The maximum time 

between tests, however, will not exceed six years. 

Manholes for in-scope cables are now being monitored on a weekly basis. PSEG has 

committed to perform sufficient manhole and cable vault inspections prior to the PEO so that 

proper inspection frequencies can be established to minimize the exposure of power cables to 

significant moisture during the PEO. The maximum time between inspections will be no more 

than one year. 

The staff has determined that the Non-EQ Inaccessible Medium-Voltage Cables Program, if 

implemented as committed to by the applicant, will ensure that the aging affects on inaccessible 

power cables will be adequately managed during the PEO. We agree with this conclusion. 

The Buried Piping Inspection Program provides aging management of carbon steel, ductile cast 

iron, and gray cast iron buried piping susceptible to general corrosion, pitting, crevice corrosion, 

and microbially induced corrosion. There are no in–scope buried tanks. The program relies on 

the visual inspection of excavated piping, including the associated coatings and wrappings. 

Portions of the carbon steel piping are cathodically protected. The rectifiers for the cathodic 

protection system are monitored on a semi-monthly basis and inspected and tested on an 

annual basis. For the past five years, cathodic protection availability has exceeded 90 percent. 

There have been no leaks of buried in-scope piping at HCGS as a result of external piping 

corrosion, and inspections of coatings that have occurred during opportunistic inspections of 

ductile cast iron fire protection piping have also found the coatings to be in acceptable condition. 

All buried piping has been risk-ranked in accordance with NACE and EPRI guidelines, and 

PSEG is implementing the NEI Industry Initiative on Buried Piping. 

The applicant has committed to perform at least one opportunistic or focused excavation and 

inspection on piping from each of the material types during each 10 year period, beginning 10 

years prior to entry into the PEO. Reinforced concrete piping is addressed under a different 

program, but will be subject to the same inspection requirement. A second opportunistic or 

focused excavation and inspection on a carbon steel piping segment, which is not cathodically 

protected, will be performed during each 10 year period, beginning 10 years prior to entry into 

the PEO. A different segment will be inspected in each 10 year period. 

The staff has concluded that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the PEO, as required by 10 CFR 54.21(a)(3). We concur with this conclusion. 

The applicant identified the systems and components requiring TLAAs and reevaluated them for 

the PEO. The staff concluded that the applicant has provided an adequate list of TLAAs. 

Further, the staff concluded that the applicant has met the requirements of the License Renewal 
 5-6 

Rule by demonstrating that the TLAAs will remain valid for the PEO, or that the TLAAs have 

been projected to the end of the PEO, or that the aging effects will be adequately managed for 

the PEO. 

We agree with the staff that there are no issues related to the matters described in 10 CFR 

54.29(a)(1) and (a)(2) that preclude renewal of the operating license for HCGS. The programs 

established and committed to by PSEG provide reasonable assurance that the HCGS can be 

operated in accordance with its current licensing basis for the PEO without undue risk to the 

health and safety of the public. The PSEG application for renewal of the operating license for 

HCGS should be approved. 

Sincerely, 

 /RA/ 

 Said Abdel-Khalik 

 Chairman 

References: 

1. NRC Safety Evaluation Report Related to the License Renewal of Hope Creek Generating 

Station, June 2011 (ML11158A166) 

2. NRC Safety Evaluation Report Related to the License Renewal of Hope Creek Generating 

Station, March 2011 (ML110690244) 

3. PSEG Nuclear LLC License Renewal Application for Hope Creek Generating Station, 

August 18, 2009, (ML092430375: Cover Latter; ML092430373: LRA Section1 thru Section 

3.3; ML092430374: LRA Section 3.4 thru Appendix D) 

4. Letter from P. Davison, PSEG Nuclear, LLC: Response to NRC Draft Request for Additional 

Information B.2.1.28-4 related to the ASME Section Xl Subsection IWE Aging Management 

Program associated with the Hope Creek Generating Station License Renewal Application, 

May 19, 2011 (ML11144A016) 

5. NRC Scoping and Screening Audit Summary Regarding Hope Creek Generating Station 

License Renewal Application, August 19, 2010 (ML102100544) 

6. NRC Audit Report Regarding Hope Creek Generating Station License Renewal Application, 

September 3, 2010 (ML101660452) 

7. NRC License Renewal Inspection Report 05000272/2010010, 05000311/2010010, 

05000354/2010010, October 14, 2010 (ML102871030) 

8. NRC NUREG-1800, Revision 1, “Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants,” September 2005 (ML052700171) 
 5-7 

9. NRC NUREG-1801, Volumes 1 & 2, Revision 1, “Generic Aging Lessons Learned Report,” 

September 2005 (ML052700171) 

10. NRC Information Notice 2002-12, “Submerged Safety-related Electrical Cables,” dated 

March 21, 2002 (ML020790238) 

11. NRC Generic Letter 2007-01, “Inaccessible or Underground Power Cable Failures that 

Disable Accident Mitigation Systems or Cause Plant Transients,” dated February 7, 2007 

(ML070360665)

 6-1 

SECTION 6 

CONCLUSION 

The staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff) reviewed the license 

renewal application (LRA) for Hope Creek Generating Station (HCGS) 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 the requirements of 

10 CFR 54.29(a) have been met. 

The staff notes that any requirements of 10 CFR Part 51, Subpart A is documented in 

Supplement 45 to NUREG-1437, “Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants (GEIS),” “Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants Regarding Hope Creek Generating Station and Salem Nuclear 

Generating Station, Units 1 and 2.” 

 A-1 

APPENDIX A 

HOPE CREEK GENERATING STATION 

LICENSE RENEWAL COMMITMENTS 

During the review of the Hope Creek Generating Station (HCGS), license renewal application 

(LRA) by the staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff), PSEG Nuclear, 

LLC (PSEG or the applicant) made commitments related to aging management programs 

(AMPs) to manage aging effects of structures and components (SCs) prior to the period of 

extended operation. The following table lists these commitments, along with the implementation 

schedules and the sources for each commitment. 
Appendix A 

 A-2 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD A.2.1.1 Ongoing LRA Section B.2.1.1 

August 18, 2009 

2 Water Chemistry A.2.1.2 Ongoing LRA Section B.2.1.2 

August 18, 2009 

3 Reactor Head Closure Studs A.2.1.3 Ongoing LRA Section B.2.1.3 

August 18, 2009 

4 BWR Vessel ID Attachment Welds A.2.1.4 Ongoing LRA Section B.2.1.4 

August 18, 2009 

5 BWR Feedwater Nozzle A.2.1.5 Ongoing LRA Section B.2.1.5 

August 18, 2009 

6 BWR Control Rod Drive Return Line Nozzle A.2.1.6 Ongoing LRA Section B.2.1.6 

August 18, 2009 

7 BWR Stress Corrosion Cracking is an existing program that will be enhanced 

to include: 

1. For the components within the scope of the BWR Stress Corrosion 

Cracking program, resistant materials will be used for new and replacement components. This includes low carbon stainless piping and stainless steel weld material limited to a maximum carbon content 0.035 wt% and a minimum ferrite content of 7.5%. 

A.2.1.7 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.2.1.7 August 18, 2009 

8 BWR Penetrations A.2.1.8 Ongoing LRA Section B.2.1.8 

August 18, 2009 
Appendix A 

 A-3 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

9 BWR Vessel Internals 

Existing program is credited. PSEG is committed to implement the BWRVIP guidelines for Hope Creek as follows: • PSEG will inform the NRC staff of any decision to not fully implement a 

BWRVIP guideline approved by the staff. 

• PSEG will notify the staff if changes are made to the RPV and its 

internals’ programs that affect the implementation of the BWRVIP guideline. 

• PSEG will submit any deviation from the existing flaw evaluation 

guidelines that are specified in the BWRVIP guideline. 

A.2.1.9 Ongoing LRA Section B.2.1.9 

August 18, 2009 

10 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic 

Stainless steel (CASS) is a new program that will provide for aging management of CASS reactor internal components within the scope of license renewal. The program will include a component specific evaluation of the loss of fracture toughness in accordance with the specified criteria. For those components where loss of fracture toughness may affect function of the component, a supplemental inspection will be performed. 

A.2.1.10 Program to be 

implemented prior to the period of extended operation. 

LRA Section B.2.1.10 August 18, 2009 

11 Flow-Accelerated Corrosion A.2.1.11 Ongoing LRA Section B.2.1.11 

August 18, 2009 

12 Bolting Integrity Program is an existing program that will be enhanced to 

include: 

1. In the following cases, bolting material should not be reused: 

a. Galvanized bolts and nuts, b. ASTM A490 bolts; and c. Any bolt and nut tightened by the turn of nut method. 

A.2.1.12 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.2.1.12 August 18, 2009 

13 Open-Cycle Cooling Water System A.2.1.13 Ongoing LRA Section B.2.1.13 

August 18, 2009 
Appendix A 

 A-4 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

14 Closed-Cycle Cooling Water System is an existing program that will be 

enhanced to include: 

1. New recurring tasks will be established for enhancing the 

performance monitoring of the Closed Cycle Cooling Water System. 

2. New recurring tasks will be established for enhancing the 

performance monitoring of the Chilled Water System. 

3. A one-time inspection of selected Closed-Cycle Cooling Water 

program components in stagnant flow areas will be conducted to confirm the effectiveness of the Closed-Cycle Cooling Water program. 

4. A one-time inspection of selected Closed-Cycle Cooling Water 

program chemical mixing tanks and associated piping will be conducted to confirm the effectiveness of the Closed-Cycle Cooling Water program on the interior surfaces of the tanks and associated 

piping. 

5. The program will be enhanced such that the plant auxiliary building 

chilled water system, which is part of the Control Area Chilled Water System, will comply with the pure water control program in accordance with EPRI 1007820 prior to the period of extended operation. 

6. A one-time inspection of selected Control Area Chilled Water 

System components, including the plant auxiliary building chilled water system, will be conducted to confirm the effectiveness of the Closed-Cycle Cooling Water program. 

A.2.1.14 Program to be 

enhanced and one-time inspections to be performed prior to the period of extended operation. 

LRA Section B.2.1.14 August 18, 2009 
Appendix A 

 A-5 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

15 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems is an existing program that will be enhanced to include: 

1. Visual inspection of structural components and structural bolts for 

loss of material due to general, pitting, and crevice corrosion and structural bolting for loss of preload due to self-loosening. 

2. Visual inspection of the rails in the rail system for loss of material due 

to wear. 

3. The acceptance criteria will be enhanced to require evaluation of 

significant loss of material due to corrosion for structural components 

and structural bolts, and significant loss of material due to wear of rail in the rail system. 

A.2.1.15 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.2.1.15 August 18, 2009 

16 Compressed Air Monitoring A.2.1.16 Ongoing LRA Section B.2.1.16 

August 18, 2009 

17 Fire Protection is an existing program that will be enhanced to include: 

1. The routine inspection procedures will be enhanced to provide 

additional inspection guidance to identify degradation of fire barrier walls, ceilings, and floors for aging effects such as cracking, spalling and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates. 

2. The fire pump supply line functional tests will be enhanced to provide 

specific guidance for examining exposed external surfaces of the fire pump diesel fuel oil supply line for corrosion during pump tests. 

3. The Halon and Carbon Dioxide fire suppression system functional 

test procedures will be enhanced to include visual inspection of system piping and component external surfaces for signs of corrosion or other age related degradation, and for mechanical damage. The functional test procedures will also be enhanced to include acceptance criteria stating that identified corrosion or mechanical damage will be evaluated, with corrective action taken as appropriate.

A.2.1.17 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.2.1.17 August 18, 2009 Hope Creek Letter LR-N10-0190 RAI B.2.1.17-02 June 14, 2010 
Appendix A 

 A-6 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

18 Fire Water System is an existing program that will be enhanced to include: 

1. The Fire Water System aging management program will be 

enhanced to inspect selected portions of the water based fire protection system piping located aboveground and exposed to the fire water internal environment by non-intrusive volumetric examinations. These inspections shall be performed prior to the period of extended operation and will be performed every 10 years thereafter. 

2. The Fire Water System aging management program will be 

enhanced to replace or perform 50-year sprinkler head inspections and testing using the guidance of NFPA-25 “Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems” (2002 Edition), Section 5-3.1.1. These inspections will be performed prior to the 50-year in-service date and every 10-years thereafter. 

A.2.1.18 Program to be 

enhanced prior to the period of extended operation. Inspection schedule identified in commitment. 

LRA Section B.2.1.18 August 18, 2009 

19 Aboveground Steel Tanks is an existing program that will be enhanced to 

include: 

1. The program will be enhanced to include internal UT measurements 

to measure the wall thickness on the bottom of the tanks supported on a fiber pad on top of the concrete foundation (Fire Water Storage Tanks). Measured wall thickness will be monitored and trended if significant material loss is detected. These thickness measurements of the tank bottom will be taken and evaluated against design thickness and corrosion allowance to ensure that significant degradation is not occurring and the component intended function will be maintained during the extended period of operation. 

2. The program will be enhanced to provide routine visual inspections 

of the carbon steel tanks external surfaces (Fire Water Storage Tanks, Fire Diesel Fuel Oil Tank and 17-Ton CO2 Storage Tank), 

including removal of tank insulation from the Fire Water Storage tank to detect degradation. These inspections will be performed to detect degraded paint and coatings, and any resulting metal degradation, prior to loss of the tank intended function. 

A.2.1.19 Program to be 

enhanced prior to the period of extended operation. Tank bottom UT inspections will also be performed prior to the period of extended operation. 

LRA Section B.2.1.19 August 18, 2009 
Appendix A 

 A-7 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

20 Fuel Oil Chemistry is an existing program that will be enhanced to include: 

1. Equivalent requirements for fuel oil purity and fuel oil testing as 

described by the Standard Technical Specifications. 

2. Addition of biocides, stabilizers and corrosion inhibitors as 

determined by fuel oil sampling or inspection activities. 

3. Internal inspection of Diesel Fire Pump Fuel Oil 280-gallon tank 

(T-565) using visual inspections and ultrasonic thickness examination of tank bottom. 

4. Quarterly water and sediment multilevel sampling on the Diesel Fuel 

Oil Storage Tanks identified in A.2.1.20 

5. Internal inspection of the Diesel Fuel Oil Storage Tanks identified in 

A.2.1.20 using visual inspections and ultrasonic thickness examination of tank bottoms. 

6. Quarterly particulate sampling of Diesel Fire Pump Fuel Oil 280-

gallon tank (T-565). 

7. To confirm the absence of any significant aging effects, a one-time 

inspection of each of the 550-gallon Diesel Fuel Oil Day Tanks will be performed. 

A.2.1.20 Program to be 

enhanced and one-time inspections to be performed prior to the period of extended operation. 

LRA Section B.2.1.20 August 18, 2009 
Appendix A 

 A-8 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

21 Reactor Vessel Surveillance is an existing program that will be enhanced to 

include: 

1. Implement the requirements of BWRVIP-116, “BWR Vessel and 

Internals Project Integrated Surveillance Program (ISP) Implementation for License Renewal,” including the conditions specified by the NRC in its Safety Evaluation dated February 24, 2006. 

2. If future plant operations exceed the limitations specified in RG 1.99, 

the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated and the NRC will be notified. 

Similarly, if future plant operation exceeds the bounds established by surveillance data that are to determine Upper Shelf Energy or P-T limits, then the impact of plant operation changes on the extent of reactor vessel embrittlement will be evaluated and the NRC will be notified. Additionally, when all the surveillance capsules are removed, then operating restrictions will be established to ensure 

that the plant is operated within the conditions to which the surveillance capsules were exposed. If the reactor vessel exposure conditions (neutron flux, spectrum, irradiation temperature, etc.) are altered, then the basis for the projection to 60 years is reviewed; and, if deemed appropriate, a revised fluence projection is prepared and the effects of the revised fluence analysis on neutron embrittlement calculations will be evaluated. If necessary an active surveillance program will be reinstituted for Hope Creek. The employment of additional surveillance specimens will be coordinated through the BWRVIP Integrated Surveillance Program (ISP). Any changes to the reactor vessel exposure conditions and the potential need to reinstitute a vessel surveillance program will be discussed with the NRC staff prior to changing the plant's licensing basis. 

A.2.1.21 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.2.1.21 August 18, 2009 
Appendix A 

 A-9 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

22 One-Time Inspection is a new program and will be used for the following: 

1. To confirm the effectiveness of the Water Chemistry program to 

manage the loss of material, cracking, and the reduction of heat transfer aging effects for aluminum, copper alloy, ductile cast iron, gray cast iron, nickel alloy, steel, stainless steel, and cast austenitic stainless steel in treated water, steam, sodium pentaborate and 

reactor coolant environments. 

2. To confirm the effectiveness of the Fuel Oil Chemistry program to 

manage the loss of material aging effect for copper alloy, steel, galvanized steel and stainless steel in a fuel oil environment. 

3. To confirm the effectiveness of the Lubricating Oil Analysis program 

to manage the loss of material and the reduction of heat transfer aging effects for copper alloy, gray cast iron, steel and stainless steel in a lubricating oil environment. 

4. To confirm loss of material in carbon steel piping and fittings is 

insignificant in an air/gas-wetted (internal) environment. 

The sample plan for inspections associated with the One-Time Inspection program will be developed to ensure there are adequate inspections to address each of the material, environment, and aging effect combinations. A sample size of 20% of the population (up to a maximum of 25 inspections) will be established for each of the sample groups.

A.2.1.22 Program to be 

implemented prior to the period of extended operation. One-time inspections to be performed within the ten-year period prior to the period of extended operation. 

LRA Section B.2.1.22 August 18, 2009 Hope Creek Letter LR-N11-0006 RAI B.2.1.22-1 January 6, 2011 
Appendix A 

 A-10 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

23 Selective Leaching of Materials is a new program that will include one-time 

inspections of a representative sample of susceptible components to determine where loss of material due to selective leaching is occurring. A sample size of 20% of susceptible components will be subjected to a one-time inspection with a maximum of 25 inspections for each of the susceptible material groups. Where selective leaching is identified, further aging management activities will be implemented such that the component intended function is maintained consistent with the current licensing basis through the period of extended operation. 

A.2.1.23 Program to be 

implemented prior to the period of extended operation. One-time inspections to be performed within the ten-year period prior to the period of extended operation. 

LRA Section B.2.1.23 August 18, 2009 Hope Creek Letter LR-N10-0319 LRA Supplement August 26, 2010 Hope Creek Letter LR-N11-0006 RAI B.2.1.23-1 January 6, 2011 

24 Buried Piping Inspection is an existing program that will be enhanced to 

include: 

1. At least one (1) opportunistic or focused excavation and inspection 

will be performed on each of the material groupings, which include carbon steel, ductile cast iron, and gray cast iron piping and components during each ten (10) year period, beginning ten (10) years prior to entry into the period of extended operation. A second opportunistic or focused excavation and inspection on a carbon steel piping segment, which is not cathodically protected, will be performed on the Service Water System during each ten year period, beginning ten years prior to entry into the period of extended operation. A different segment will be inspected in each ten year period. 

A.2.1.24 Program to be 

enhanced prior to the period of extended operation. Inspection schedule identified in commitment. 

LRA Section B.2.1.24 August 18, 2009 Hope Creek Letter LR-N10-0323 RAI B.2.1.24 September 1, 2010 Hope Creek Letter LR-N10-0371 RAI B.2.1.24-02 October 29, 2010 

25 External Surfaces Monitoring is a new program that directs visual inspections 

of components such as piping, piping components, ducting and other components in the scope of license renewal, exposed to an air environment, to manage aging effects. 

A.2.1.25 Program to be 

implemented prior to the period of extended operation. 

LRA Section B.2.1.25 August 18, 2009 
Appendix A 

 A-11 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

26 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components is a new program that manages the aging of the internal surfaces of piping, piping components and piping elements, tanks and ducting components. 

A.2.1.26 Program to be 

implemented prior to the period of extended operation. 

LRA Section B.2.1.26 August 18, 2009 

27 Lubricating Oil Analysis A.2.1.27 Ongoing LRA Section B.2.1.27 

August 18, 2009 

28 ASME Section XI, Subsection IWE is an existing program that will be 

enhanced to include: 

1. Install an internal moisture barrier at the junction of the drywell 

concrete floor and the steel drywell shell prior to the period of extended operation. 

2. Require inspection of the moisture barrier for loss of sealing in 

accordance with IWE 2500 after it is installed. 

3. Verify that the reactor cavity seal rupture drain lines are clear from 

blockage and that the monitoring instrumentation is functioning properly once prior to the period of extended operation, and one additional time during the first ten years of the period of extended operation. 

4. Establish drainage capability from the bottom of the drywell air gap 

on or before June 30, 2015. The drywell air gap will be divided into four approximately equal quadrants. Drainage consists of one drain in each quadrant for a total of four drains. Each drain will be open at the bottom of the drywell air gap and be capable of draining water from the air gap. Verify that drains at the bottom of the drywell air gap are clear from 

blockage once prior to the period of extended operation, and one 

additional time during the first ten years of the period of extended operation. 

5. Investigate the source of any leakage detected by the reactor cavity 

seal rupture drain line instrumentation and assess its impact on the 

A.2.1.28 Program to be 

enhanced prior to the period of extended operation. Inspection schedule identified in commitment. 

LRA Section B.2.1.28 August 18, 2009Hope Creek Letter LR-N10-0190 RAI B.2.1.28-01 June 14, 2010 Hope Creek Letter LR-N10-0291 RAI B.2.1.28-01 August 9, 2010 Hope Creek Letter LR-N11-0016 RAI B.2.1.28-03 January 19, 2011 Hope Creek Letter LR-N11-0164 DRAI B.2.1.28-4 May 19, 2011 
Appendix A 

 A-12 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

drywell shell. 

6. After drainage has been established from the bottom of the air gap 

from all four drains, monitor the drains at the bottom of the drywell air gap daily for leakage in the event leakage is detected by the reactor cavity seal rupture drain line instrumentation. 

7. Monitor penetration sleeve J13 daily for water leakage when the 

reactor cavity is flooded up. In addition, perform a walkdown of the torus room to detect any leakage from other drywell penetrations. These actions shall continue until corrective actions are taken to prevent leakage through J13 or through the four air gap drains. 

8. Until drainage is established from all four drains, when the reactor 

cavity is flooded up, perform boroscope examination of the bottom of the drywell air gap through penetrations located at elevation 93’ in four quadrants, 90 degrees apart. The personnel performing the boroscope examination shall be certified as VT-1 inspectors in accordance ASME Section XI, Subsection IWA-2300, requirements. The examiners will look for signs of water accumulation and drywell shell corrosion. Adverse conditions will be documented and addressed in the corrective action program. After drainage has been established from the bottom of the air gap from all four drains, monitor the lower drywell air gap drains daily for water leakage when the reactor cavity is flooded up. 

9. Until drainage is established from all four drains, perform UT 

thickness measurements each refuel outage from inside the drywell in the area of the drywell shell below the J13 penetration sleeve area to determine if there is a significant corrosion rate occurring in this area due to periodic exposure to reactor cavity leakage. In addition, UT measurements shall be perfomed each refuel outage around the full 360 degree circumference of the drywell between elevations 86’-11” and 88’-0” (underside of the torus down comer vent piping penetrations). Inspection and acceptance criteria will be in accordance with IWE-2000 and IWE-3000 respectively. The results of the UT measurements shall be used to establish a corrosion rate and demonstrate that the effects of aging will be adequately 
Appendix A 

 A-13 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

managed such that the drywell can perform its intended function until April 11, 2046. Evidence of drywell shell degradation will be documented and addressed in the corrective action program. After drainage has been established from the bottom of the air gap from all four drains, UT thickness measurements will be taken each of the next three refueling outages at the same locations as those previously examined as described above. These UT thickness measurements will be compared to the results of the previous UT inspections and, if corrosion is ongoing, a corrosion rate will be determined for the drywell shell. In the event a significant corrosion rate is detected, the condition will be entered in the corrective action process for evaluation and extent of condition determination. 

10. The cause of the reactor cavity water leakage will be investigated 

and repaired, if practical, before PEO. If repairs cannot be made prior to the PEO, the program will be enhanced to incorporate the following aging management activities, as recommended in the Final Interim Staff Guidance LR-ISG-2006-01. a. Identify drywell surfaces requiring examination and implement 

augmented inspections for the period of extended operation in accordance with IWE-1240, as identified in Table IWE-2500-1, Examination Category E-C. 

b. Demonstrate through the use of augmented inspections that 

corrosion is not occurring or that corrosion is progressing so slowly that the age-related degradation will not jeopardize the intended function of the drywell shell through the period of extended operation. 

c. Develop a corrosion rate that can be inferred from past UT 

examinations. If degradation has occurred, evaluate the drywell 

shell using the developed corrosion rate to demonstrate that the drywell shell will have sufficient wall thickness to perform its intended function through the period of extended operation. 

29 ASME Section XI, Subsection IWF A.2.1.29 Ongoing LRA Section B.2.1.29 

August 18, 2009 
Appendix A 

 A-14 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

30 10 CFR Part 50, Appendix J A.2.1.30 Ongoing LRA Section B.2.1.30 

August 18, 2009 

31 Masonry Wall is an existing program that will be enhanced to include: 

1. Additional buildings and masonry walls as described in A.2.1.31. 2. Add an Examination Checklist for masonry wall inspection 

requirements. 

3. Specify an inspection frequency of not greater than 5 years for 

masonry walls. 

A.2.1.31 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.2.1.31 August 18, 2009 

32 Structures Monitoring is an existing program that will be enhanced to include: 

1. Additional structures and components as described in A.2.1.32 2. Concrete structures will be observed for a reduction in equipment 

anchor capacity due to local concrete degradation. This will be accomplished by visual inspection of concrete surfaces around anchors for cracking, and spalling. 

3. Clarify inspection criteria for loss of material due to corrosion and 

pitting of additional steel components, such as embedments, panels and enclosures, doors, siding, metal deck, and anchors. 

4. Perform a one-time inspection of the external stainless steel surfaces 

of the expansion bellows at Condensate Storage Tank Dike for loss of material due to corrosion, within the ten-year period prior to the period of extended operation. 

5. Require inspection of penetration seals, structural seals and 

elastomers for degradations that will lead to a loss of sealing by visual inspection of the seal for hardening, shrinkage and loss of strength. 

6. Require monitoring of vibration isolators, associated with component 

supports other than those covered by ASME XI, Subsection IWF. 

7. Add an Examination Checklist for masonry wall inspection 

requirements. 

8. Parameters monitored for wooden components will be enhanced to 

include: Change in Material Properties, Loss of Material due to Insect 

Damage and Moisture Damage. 

A.2.1.32 Program to be 

enhanced prior to the period of extended operation. One-time inspection to be performed within the ten-year period prior to the period of extended operation. 

LRA Section B.2.1.32 August 18, 2009 
Appendix A 

 A-15 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

9. Specify an inspection frequency of not greater than 5 years for 

structures including submerged portions of the Service Water Intake Structure. 

10. Require individuals responsible for inspections and assessments for 

structures to have a B.S. Engineering degree and/or Professional Engineer license, and a minimum of four years experience working on building structures. 

11. Perform periodic sampling, testing, and analysis of ground water 

chemistry for pH, chlorides, and sulfates on a frequency of 5 years. 

12. Require supplemental inspections of the in scope structures within 

30 days following extreme environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and tornadoes). 

13. Perform a chemical analysis of ground or surface water in-leakage 

when there is significant in-leakage or there is reason to believe that 

the in-leakage may be damaging concrete elements or reinforcing steel. 

14. Implementing procedures will be enhanced to include additional 

acceptance criteria details specified in ACI 349.3R-96. 
Appendix A 

 A-16 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

33 RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear 

Power Plants” is an existing program that will be enhanced to include: 

1. Shoreline Protection and Dike structures will be added to the 

program. 

2. Parameters monitored for wooden components will be enhanced to 

include change in material properties and loss of material due to insect damage and moisture damage. 

3. The inspection requirement for submerged concrete structural 

components will be enhanced to require that inspections be performed by dewatering a pump bay or by a diver if the pump bay is not dewatered. 

4. Specify an inspection frequency of not greater than 5 years for 

structures including submerged portions of the Service Water Intake Structure. 

5. Require supplemental inspections of the in scope structures within 

30 days following extreme environmental or natural phenomena (large floods, significant earthquakes, hurricanes, and tornadoes). 

A.2.1.33 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.2.1.33 August 18, 2009 

34 Protective Coating Monitoring and Maintenance Program A.2.1.34 Ongoing LRA Section B.2.1.34 

August 18, 2009 

35 Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements is a new program and will be used to manage aging of non-EQ cables and connections during the period of extended operation. 

A.2.1.35 Program and 

initial inspections to be implemented prior to the period of extended operation. 

LRA Section B.2.1.35 August 18, 2009 
Appendix A 

 A-17 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

36 Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits is a new program that will be implemented to manage the aging of the cable and connection insulation of the in scope portions of the Leak Detection and Radiation Monitoring System, and the Neutron Monitoring System. 

A.2.1.36 Program and 

initial assessment of testing and calibration results to be implemented prior to the period of extended operation. 

LRA Section B.2.1.36 August 18, 2009 
Appendix A 

 A-18 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

37 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements is a new program that will be used to manage the aging effects and mechanisms of non-EQ, in scope inaccessible power cables (480V, 4,160V, 13,800V). The cable test frequency will be established based on test results and industry operating experience. The maximum time between tests will be no longer than 6 years. Manholes and cable vaults associated with the cables included in this aging management program will be inspected for water collection (with water removal as necessary) with the objective of minimizing the exposure of power cables to significant moisture. Prior to the period of extended operation, the frequency of inspections for accumulated water will be established based on inspection results to minimize the exposure of power cables to significant moisture. The maximum time between inspections will be no longer than one year. The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements aging management program will be enhanced as follows: 

1. Add low voltage power cables (480 volts or greater) to the scope 

of the program.

2. Change cable testing maximum frequency from 10 years to 6 

years. Change cable vault and manhole inspection maximum frequency from 2 years to 1 year.

A.2.1.37 Enhanced 

program and initial cable tests and manhole inspections to be implemented prior to the period of extended operation. Test and inspection schedule identified in commitment. 

LRA Section B.2.1.37 August 18, 2009 Hope Creek Letter LR-N10-0190 RAI B.2.1.37-01 June 14, 2010 Hope Creek Letter LR-N10-0190 RAI B.2.1.37-02 June 14, 2010 Hope Creek Letter LR-N10-0325 LRA Supplement September 7, 2010 Hope Creek Letter LR-N10-0360 LRA Supplement September 30, 2010 

38 Metal Enclosed Bus is a new program that will manage the aging of in-scope 

metal enclosed busses. 

A.2.1.38 Program and 

initial inspections to be implemented prior to the period of extended operation. 

LRA Section B.2.1.38 August 18, 2009 
Appendix A 

 A-19 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

39 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements is a new program that will be used to confirm the absence of an aging effect with respect to electrical cable connection stressors. A representative sample of non-EQ electrical cable connections will be selected, for one-time testing considering application (medium and low voltage), circuit loading (high loading) and location, with respect to connection stressors. 

A.2.1.39 Program and 

one-time testing to be implemented prior to the period of extended operation. 

LRA Section B.2.1.39 August 18, 2009 

40 High Voltage Insulators is a new program that manages the degradation of 

insulator quality due to the presence of salt deposits or surface contamination. 

A.2.2.1 Program to be 

implemented prior to the period of extended operation. 

LRA Section B.2.2.1 August 18, 2009 

41 Periodic Inspection is a new program that manages the aging of piping, piping 

components, piping elements, ducting components, tanks and heat exchanger components. 

A.2.2.2 Program to be 

implemented prior to the period of extended operation. 

LRA Section B.2.2.2 August 18, 2009 

42 Aboveground Non-Steel Tanks is a new program that will manage loss of 

material of outdoor non-steel tanks. The Aboveground Non-Steel Tanks program will include a UT wall thickness inspection of the bottom of the only tank in the program, which is the stainless steel condensate storage tank. The UT measurements will be taken to ensure that significant degradation is not occurring and that the component intended function will be maintained during the extended period of operation. 

A.2.2.3 Program to be 

implemented prior to the period of extended operation. Tank bottom UT inspections will also be performed prior to the period of extended operation. 

LRA Section B.2.2.3 August 18, 2009 
Appendix A 

 A-20 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

43 Buried Non-Steel Piping Inspection is an existing program that will be 

enhanced to include: 

1. At least one (1) opportunistic or focused excavation and inspection 

will be performed on buried reinforced concrete piping and components during each ten (10) year period, beginning ten (10) years prior to entry into the period of extended operation. 

2. At least one (1) opportunistic or focused excavation and inspection 

will be performed on Condensate Storage and Transfer System buried stainless steel piping and components, which contain fluid that exceed EPA drinking water limits, during each ten (10) year period, beginning ten (10) years prior to entry into the period of extended operation. 

3. Guidance for inspection of concrete aging effects. 

A.2.2.4 Program to be 

enhanced prior to the period of extended operation. Inspection schedule identified in commitment. 

LRA Section B.2.2.4 August 18, 2009 Hope Creek Letter LR-N10-0323 RAI B.2.1.24 September 1, 2010 Hope Creek Letter LR-N10-0371 RAI B.2.1.24-02 October 29, 2010 

44 Boral Monitoring Program is an existing program that will be enhanced to 

include: 

1. Inspection, testing and evaluation of one coupon from the Hope 

Creek spent fuel pool prior to the period of extended operation and one coupon within the first 10 years after entering the period of extended operation. Testing will include dimensional and neutron attenuation measurements with an acceptance criteria of no more than a 10% increase in thickness and no more than a 5% decrease in B-10 areal density. 

A.2.2.5 Program to be 

enhanced prior to the period of extended operation. Inspection schedule identified in commitment 

LRA Section B.2.2.5 August 18, 2009 Hope Creek Letter LR-N10-0154 RAI 2.2.5-1 May 11, 2010 
Appendix A 

 A-21 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

45 Small-Bore Class 1 Piping is a new program that will manage the aging 

effects of cracking in small-bore (greater than or equal to NPS 1 and less than NPS 4) Class 1 piping through the use of a combination of volumetric examinations and visual inspections. 

A.2.2.6 Program to be 

implemented prior to the period of extended operation, with the supplemental inspections performed within the six year period prior to the period of extended operation. 

LRA Section B.2.2.6 August 18, 2009 Hope Creek Letter LR-N10-0415 RAI B.2.2.6-01 December 15, 2010 

46 Metal Fatigue of the Reactor Coolant Pressure Boundary is an existing 

program that will be enhanced to include: 

1. Adding transients beyond those defined in the Technical 

Specifications and the UFSAR, and expanding the fatigue monitoring program to encompass other components identified to have fatigue as an analyzed aging effect, which require monitoring. 

2. Using a software program to automatically count transients and 

calculate cumulative usage on select components. At this time only cycle–based fatigue monitoring will be used. If stress–based fatigue monitoring is used in the future, it will consider the six stress terms in accordance with the methodology from ASME Section III, Subsection NB, Subarticle NB-3200. 

3. Addressing 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 identified in NUREG/CR-6260. 

4. Requiring a review of additional reactor coolant pressure boundary 

locations if the usage factor for one of the environmental fatigue sample locations approaches its design limit. 

A.3.1.1 Program to be 

enhanced prior to the period of extended operation. 

LRA Section B.3.1.1 August 18, 2009 Hope Creek Letter LR-N10-0356 RAI 4.3-01 September 20, 2010 
Appendix A 

 A-22 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

47 Environmental Qualification of Electric Components (EQ) A.3.1.2 Ongoing LRA Section B.3.1.2 

August 18, 2009 

48 New P-T Curves 

Revised Pressure-Temperature (P-T) limits will be submitted to the NRC when necessary to comply with 10 CFR 50 Appendix G. 

A.4.2.3 Ongoing LRA Section 4.2.3 

August 18, 2009 

49 RPV Circumferential Weld Examination Relief 

PSEG will request relief from the requirement to perform volumetric examinations of the Reactor Pressure Vessel Circumferential Welds, in accordance with 10 CFR 50.55(a) 

A.4.2.4 Prior to the period 

of extended operation. 

LRA Section 4.2.4 August 18, 2009 

50 Operating Experience Review 

PSEG will perform an evaluation of operating experience at extended power uprate (EPU) levels prior to the period of extended operation to ensure that operating experience at EPU levels is properly addressed by the aging management programs. The evaluation will include Hope Creek and other BWR plants operating at EPU levels. 

All programs Prior to the period 

of extended operation. 

NUREG-1800 Section 3.0.2 

51 Reactor Internals Components – Core Plate Rim Hold-Down Bolts 

PSEG will perform one of the following: 

1. Install core plate wedges, or 2. Perform an analysis that demonstrates the component function is 

maintained. 

A.4.2.7 Prior to the period 

of extended operation. 

LRA Section 4.2.7 and Appendix C August 18, 2009 
Appendix A 

 A-23 

APPENDIX A: HCGS LICENSE RENEWAL COMMITMENTS

Item 

Number 

Commitment Updated Final Safety 

Analysis Report 

(UFSAR) 

Supplement Section/

LRA Section 

Enhancement or 

Implementation 

Schedule 

Source

52 Jet Pump Slip Joint Clamp Bolt 

PSEG will replace the slip joint clamp or perform an analysis that demonstrates the function of the component is maintained. 

A.4.7.3 Two years before 

reaching the bounding value of 35.4 EFPY, perform the analysis, or replace the slip joint clamp at a refueling outage prior to reaching the bounding value of 35.4 EFPY. 

LRA Section 4.7.3 August 18, 2009 Hope Creek Letter LR-N10-0344 September 9, 2010 

53 Metal Fatigue of Reactor Coolant Pressure Boundary 

Environmental fatigue calculations for the Hope Creek Alloy 600 locations will use the data and the methodology that is described in NUREG/CR-6909 or later revisions/reports for Ni-Cr-Fe alloys in the determination of the Fen factor 

and fatigue usage. 

A.3.1.1 A.4.3.5 

Upon calculation revision/update 

Hope Creek Letter LR-N10-0344; RAI 4.3-07 September 9, 2010 

54 Metal Fatigue of Reactor Coolant Pressure Boundary 

PSEG will perform a review of design basis ASME Code 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 Hope Creek 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 any of the limiting locations consist of nickel alloy, NUREG/CR-6909 methodology for nickel alloy will be used in the evaluation. 

A.3.1.1 A.4.3.5 

Prior to the period of extended operation. 

Hope Creek Letter LR-N10-0440; CI 4.3.5.2-1 January 6, 2011 

 B-1 

APPENDIX B 

CHRONOLOGY 

This appendix contains a chronological listing of the routine correspondence between the staff 

of the U.S. Nuclear Regulatory Commission (NRC or the staff) and PSEG Nuclear, LLC (PSEG 

or the applicant), and other correspondence regarding the staff’s reviews of the Hope Creek 

Generating Station (HCGS), Docket Number 50-354, license renewal application (LRA). 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 1 

of 3. (Accession No. ML092430373) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 2 

of 3. (Accession No. ML092430374) 

August 18, 2009 Letter from C.J. Fricker, PSEG Nuclear, LLC: Hope Creek Generating 

Station Transmittal Letter, License Renewal Application. (Accession 

No. ML092430375) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 3 

Through Appendix A. (Accession No. ML092430384) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 3, 

Appendix B. (Accession No. ML092430386) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 3, 

Appendix C. (Accession No. ML092430387) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 3, 

Appendix D. (Accession No. ML092430388) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 3, 

Appendix E. (Acccession No. ML092430389) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 3, 

Appendix F. (Accession No. ML092430390) 

August 18, 2009 Hope Creek Generating Station, License Renewal Application, Volume 3 

of 3. (Accession No. ML092430484) 

August 27, 2009 Logistics Trip Report to Delaware Emergency Management Agency 

Regarding Salem-Hope Creek License Renewal. (Accession 

No. ML092360621) 

August 31,2009 Federal Register Notice: Notice of Receipt and Availability of Application 

for Renewal of Hope Creek Generating Station. (Accession 

No. ML092290801) 

August 31, 2009 Letter to T. Joyce, PSEG Nuclear, LLC: Receipt and Availability of the 

License Renewal Application for the Hope Creek Generating Station. 

(Accession No. ML092290793) 
Appendix B 

 B-2 

September 1, 2009 Press Release-09-144: NRC Announces Availability of License Renewal 

Applications for Salem and Hope Creek Nuclear Power Plants. 

(Accession No. ML092440653) 

September 3, 2009 Comment of W.R. Dunn on the Salem Nuclear Generating Station and 

Hope Creek Generating Station License Renewal Applications. 

(Accession No. ML092460442) 

September 3, 2009 Comment (7) of William R. Dunn, Supporting the Salem Nuclear 

Generating Station and Hope Creek Generating Station License Renewal 

Applications. (Accession No. ML102280561) 

September 7, 2009 Comment of S.J. Goodman on the Salem Nuclear Generating Station and 

Hope Creek Generating Station License Renewal Applications. 

(Accession No. ML092660174) 

September 7, 2009 Comment (2) of Sidney J. Goodman Opposing on License Renewal for 

the Salem Nuclear Generating Station and Hope Creek Generating 

Station (Accession No. ML102280556) 

September 8, 2009 Comment of F. Berryhill on the Salem Nuclear Generating Station and 

Hope Creek Generating Station License Renewal Applications. 

(Accession No. ML092650382) 

September 23, 2009 Comment of R. Panella on the Salem Nuclear Generating Station and 

Hope Creek Generating Station License Renewal Applications. 

(Accession No. ML092660447) 

October 8, 2009 Letter from C.M. Dolphin, State of New Jersey, Department of 

Environmental Protection: New Jersey Coastal Zone Management 

Consultation Response for Hope Creek License Renewal. (Accession 

No. ML101970076) 

October 15, 2009 Letter to T. Joyce, PSEG Nuclear, LLC. Determination of Acceptability 

and Sufficiency for Docketing, Proposed Review Schedule, and 

Opportunity for a Hearing Regarding the Application from PSEG Nuclear, 

LLC, for Renewal of the Operating License for Hope Creek Generating 

Station. (Accession No. ML092780127) 

October 15, 2009 Federal Register: Notice of Federal Acceptability for Docketing of the 

Application and Notice of Opportunity for Hearing Regarding Renewal of 

Facility Operating License No. NPF-57 for an Additional 20-Year Period, 

PSEG Nuclear, LLC, Hope Creek Nuclear Generating Station. 

(Accession No. ML092780147) 

October 15, 2009 Letter to T. Joyce, PSEG Nuclear, LLC: Notice of Intent to Prepare an 

Environmental Impact Statement and Conduct the Scoping Process for 

License Renewal for the Salem Nuclear Generating Station, Units 1 

and 2, and the Hope Creek Generating Station. (Accession 

No. ML092740412) 
Appendix B 

 B-3 

October 23, 2009 Notice of Meeting on November 5, 2009, to Discuss License Renewal 

Process and Environmental Scoping for Salem Nuclear Generating 

Station, Units 1 and 2, and Hope Creek Generating Station, License 

Renewal Application Review. (Accession No. ML092870635) 

October 24, 2009 Comment of D.O. Rickards on the Salem Nuclear Generating Station and 

Hope Creek Generating Station License Renewal Applications. 

(Accession No. ML100570265) 

November 3, 2009 Comment (5) of Ellen B. Pompper, on Behalf of Self, Supporting PSEG 

Nuclear’s License Renewal for Salem Nuclear Generating Station and 

Hope Creek Generating Station. (Accession No. ML102280559) 

November 5, 2009 Transcript of the Salem and Hope Creek License Renewal Public 

Meeting, November 5, 2009, Pages 1–79. (Accession 

No. ML093240195) 

November 5, 2009 Transcript of the Salem and Hope Creek License Renewal Process, 

Public Meeting: Evening Session November 5, 2009, Pages 1–63. 

(Accession No. ML100471177) 

November 12, 2009 Letter to J. Douglas, Delaware Tribe of Indians: Salem Nuclear 

Generating Station, Units 1 and 2, and Hope Creek Nuclear Generating 

Station, Unit 1, License Renewal Applications. (Accession 

No. ML093090124) 

November 24, 2009 Letter to J. Cutler, Deputy State Historic Preservation Officer (SHPO), 

Pennsylvania Bureau for Historic Preservation; J.R. Little, Director and 

SHPO, Maryland Historical Trust; D. Saunders, Deputy SHPO, New 

Jersey Historic Preservation Office; and T.A. Slavin, SHPO, Delaware 

Division of Historical and Cultural Affairs: Salem Nuclear Generating 

Station and Hope Creek Generation Station License Renewal 

Applications Review. (Accession No. ML093160444) 

December 22, 2009 Letter from T.A. Slavin, State of Delaware Historical and Cultural Affairs: 

Delaware SHPO Finding of No Adverse Impact Consultation Response 

for the Salem and Hope Creek License Renewal. (Accession 

No. ML101970071) 

December 23, 2009 Letter to A.E. Scherer, U.S. Fish and Wildlife Service: Request for List of 

Protected Species and Water Usage Impacts Within the Area Under 

Evaluation for the Salem and Hope Creek Nuclear Generating Stations 

License Renewal Application Review. (Accession No. ML093350019) 

December 23, 2009 Letter to P.A. Kurkul, National Marine Fisheries Service: Request for List 

of Protected Species Within the Area Under Evaluation for the Salem and 

Hope Creek Nuclear Generating Stations License Renewal Application 

Review. (Accession No. ML093500057) 

February 11, 2010 Letter from M.A. Colligan, National Marine Fisheries Service: NMFS 

Consultation Response for the Salem and Hope Creek License Renewal 

Project. (Accession No. ML101970073) 
Appendix B 

 B-4 

February 23, 2010 Letter from S.W. Gorski, National Marine Fisheries Service: NMFS 

Habitat Conservation Division Consultation Response for the Salem and 

Hope Creek License Renewal Project. (Accession No. ML101970072) 

March 22, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Section 2.3.2, Containment for the Hope Creek 

Generating Station. (Accession No. ML100630287) 

March 29, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Corrections to the Hope 

Creek Generating Station License Renewal Application. (Accession 

No. ML100910160) 

March 31, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Section 2.4, Scoping and Screening Results: 

Structures (TAC No. ME1832). (Accession No. ML100750328) 

April 6, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Project Manager Change for the 

License Renewal of Hope Creek Generating Station (TAC No. ME1832). 

(Accession No. ML100850462) 

April 6, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Corrections to the Hope 

Creek Generating Station License Renewal Application Environmental 

Report. (Accession No. ML100980029) 

April 6, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated March 22, 2010, Related to 

Section 2.3 of the License Renewal Application. (Accession 

No. ML100980043) 

April 6, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated March 22, 2010, Related to 

Section 2.3.3.10 of the License Renewal Application. (Accession 

No. ML100990236) 

April 14, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Section 2.2.5, Boral Monitoring Program (TAC 

No. ME1832). (Accession No. ML100970350) 

April 16, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the License Renewal Application for Salem 

Nuclear Generating Station, Units 1 and 2, and Hope Creek Generating 

Station. (Accession No. ML100910367) 

April 22, 2010 Letter from P.J. Davidson, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information dated March 31, 2010, Related to 

Section 2.4 of the License Renewal Application. (Accession 

No. ML101160398) 
Appendix B 

 B-5 

April 27, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Section 2.1, Scoping and Screening Methodology 

(TAC No. ME1832). (Accession No. ML101020511) 

April 29, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated April 16, 2010, Related to the 

Environmental Review, License Renewal Application. (Accession 

No. ML101440272) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Post Audit Information, Question # GEN-4. (Accession 

No. ML101440273) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Cultural Resources. (Accession No. ML101440276) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Ecology. (Accession No. ML101440278) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Ecology, Chapter 7: Marsh Restoration Project, Fish 

Assemblage Structure. (Accession No. ML101440279) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Ecology, Question # ECO-7. (Accession No. ML101440280) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Ecology, Appendix E. (Accession No. ML101440281) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Ecology, Appendix E, Attachment E-2. (Accession 

No. ML101440283) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Ecology, Appendix F. (Accession No. ML101440285) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Ecology, Appendix F, Attachment 5. (Accession 

No. ML101440286) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Land Use and Socioeconomics. (Accession 

No. ML101440287) 
Appendix B 

 B-6 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Threatened and Endangered Species. (Accession 

No. ML101440288) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Water/Groundwater. (Accession No. ML101440289) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Waste. (Accession No. ML101440292) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Air. (Accession No. ML101440293) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Alternatives. (Accession No. ML101440294) 

April 29, 2010 Response to NRC Request for Additional Information, dated April 16, 

2010, Related to the Environmental Review, License Renewal 

Application, Fact Sheet for a Draft NJPDES Permit. (Accession 

No. ML101440297) 

May 11, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated April 15, 2010, Related to 

Scoping and Screening Results, Section 2.3 of the License Renewal 

Application. (Accession No. ML101340110) 

May 11, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated April 14, 2010, Related to 

Section B.2.2.5 of the License Renewal Application. (Accession 

No. ML101340117) 

May 14, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application Identified During the Audit (TAC No. ME1832). 

(Accession No. ML101060155) 

May 20, 2010 Division of License Renewal’s Transition from Paper Distribution to 

Electronic Distribution of Outgoing Correspondence. (Accession 

No. ML101310138) 

May 24, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated April 27, 2010, Related to 

Section 2.1, Scoping and Screening Methodology, of the License 

Renewal Application. (Accession No. ML101480130) 

May 28, 2010 Summary of Telephone Conference Call Held on March 4, 2010, Between 

the NRC and PSEG Nuclear, LLC Concerning Draft REI’s Pertaining to 

the Hope Creek Generating Station, License Renewal Application. 

(Accession No. ML101340462) 
Appendix B 

 B-7 

June 1, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Section 3.3.2 (TAC No. ME1832). (Accession 

No. ML101380316) 

June 1, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Sections 4.6 and 4.7 (TAC No. ME1832). 

(Accession No. ML101380620) 

June 1, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated April 20, 2010, Related to the 

Severe Accident Mitigation Alternatives Review Associated with the 

License Renewal Application. (Accession No. ML101550149) 

June 3, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application (TAC No. ME1832). (Accession No. ML101450179) 

June 7, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application for Section 3.5 (TAC No. ME1832). (Accession 

No. ML101380149) 

June 14, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application (TAC No. ME1832). (Accession No. ML101370761) 

June 14, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated May 14, 2010, Related to the 

Aging Management Program Audit Associated with the License Renewal 

Application. (Accession No. ML101680503) 

June 22, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Fire Protection (TAC No. ME1832). (Accession 

No. ML101610448) 

June 24, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information Related to Sections 4.6 and 4.7 of the 

License Renewal Application. (Accession No. ML101810072) 

June 24, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: 10 CFR 54.21(b) Review 

to Identify any Current Licensing Basis (CLB) Changes Made Since the 

Submittal of the License Renewal Application. (Accession 

No. ML101810073) 

June 24, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated June 1, 2010, Related to 

Section 3.3.2 of the License Renewal Application. (Accession 

No. ML101820089) 
Appendix B 

 B-8 

June 25, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Section 4.3. (Accession No. ML101590675) 

June 25, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Open-Cycle Cooling Water System Program and 

Structures (TAC No. ME1832). (Accession No. ML101660150) 

June 29, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application for Fiberglass Doors (TAC No. ME1832). 

(Accession No. ML101750024) 

June 29, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Response to NRC Request 

for Additional Information, dated June 7, 2010, Related to Section 3.5 of 

the License Renewal Application. (Accession No. ML101820580) 

June 29, 2010 Letter from R. Popowski, U.S. Fish and Wildlife Service: Fish and Wildlife 

Consultation Response for the Salem and Hope Creek License Renewal 

Project. (Accession No. ML101970077) 

June 30, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Metal Fatigue of Reactor Coolant Pressure 

Boundary Program (TAC No. ME1832). (Accession No. ML101580481) 

June 30, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Response to NRC Request 

for Additional Information, dated June 3, 2010, Related to Sections 3.2.2, 

3.3.2, and B.2.2.2 of the License Renewal Application. (Accession 

No. ML101830410) 

July 6, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated June 9, 2010, Related to 

Sections 3.1.2 and 3.3.2 of the License Renewal Application. (Accession 

No. ML101900006) 

July 12, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Compressed Air Monitoring (TAC No. ME1832). 

(Accession No. ML101810239) 

July 12, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated June 14, 2010, Related to 

Section 3 of the License Renewal Application. (Accession 

No. ML101950358) 

July 20, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Response to NRC Request 

for Additional Information, dated June 25, 2010, Related to Open-Cycle 

Cooling Water System Program and Structures of the License Renewal 

Application. (Accession No. ML102040513) 
Appendix B 

 B-9 

July 22, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Response to NRC Request 

for Additional Information, dated June 25, 2010, Related to Section 4.3 of 

the License Renewal Application. (Accession No. ML102070550) 

July 22, 2010 Letter from P. J.Davidson, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated June 22, 2010, Related to Fire 

Protection License Renewal Application. (Accession No. ML102030259) 

July 26, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Response to NRC Request 

for Additional Information, dated June 30, 2010, Related to Metal Fatigue 

Reactor Coolant Pressure Boundary Program; Fiberglass Doors; and 

Compressed Air Monitoring of the License Renewal Application. 

(Accession No. ML102110044) 

August 3, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Bolting and Flow Element (TAC No. ME1832). 

(Accession No. ML102000293) 

August 6, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application, Buried Piping Inspection Program (TAC 

No. ME1832). (Accession No. ML101540054) 

August 9, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Supplement to PSEG 

Response to Requests for Additional Information (RAIs) B.2.1.28-01, 

B.2.1.37-01, and B.2.1.37-02 Associated with the Hope Creek Generating 

Station License Renewal Application. (Accession No. ML102240095) 

August 13, 2010 Summary of Telephone Conference Call Held on July 29, 2010, Between 

the U.S. NRC and PSEG Nuclear LLC, Concerning Follow-Up Questions 

Pertaining to the Salem Nuclear Generating Station, Units 1 and 2, and 

Hope Creek Generating Station License Renewal Environmental Review. 

(Accession No. ML102220012) 

August 18, 2010 Request for Additional Information for the Review of the Hope Creek 

Generating Station License Renewal Application, Primary Containment 

Valve Material. (Accession No. ML102030398) 

August 18, 2010 Summary of Telephone Conference Call Held on August 4, 2010, 

Between the U.S. NRC and PSEG Nuclear, LLC, Concerning Draft 

Requests for Additional Information Pertaining to the Hope Creek 

Generating Station License Renewal Application. (Accession 

No. ML102220476) 

August 18, 2010 Letter from C.T. Neely, PSEG Nuclear, LLC: Supplement to RAI 

Responses Submitted in PSEG Letter LR-N10-0181, dated June 1, 2010, 

Related to the Severe Accident Mitigation Alternatives Review. 

(Accession No. ML102320212) 

August 19, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Scoping and Screening Audit 

Summary Regarding the Hope Creek Generating Station License 

Renewal Application. (Accession No. ML102100544) 
Appendix B 

 B-10 

August 26, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Supplement to Hope 

Creek License Renewal Application Related to the Selective Leaching 

Program. (Accession No. ML 102330677) 

August 26, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Response to NRC 

Request for Additional Information, dated August 3, 2010, Related to 

Bolting and Flow Element, and Update to PSEG July 6, 2010, Response 

to NRC Request for Additional Information Associated with the RPV Leak 

Detection Line, License Renewal Application. (Accession No. 

ML102330678) 

September 1, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Updated Response to NRC 

Request for Additional Information 3.5.2.1.4 and Responses to NRC 

Request for Additioinal Information 3.2.1.20-01 Associated with Renewal 

Application. (Accession No. ML102500118) 

September 1, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Response to NRC Request 

for Additional Information, dated August 6, 2010, Related to the Buried 

Piping Inspection Program Associated with the License Renewal 

Application. (Accession No. ML102500101) 

September 2, 2010 Letter to C. Fricker, PSEG Nuclear, LLC: Revised Review Schedule 

Regarding the Application from PSEG Nuclear, LLC for Renewal of the 

Operating Licenses for Salem Nuclear Generating Station, Units 1 and 2, 

and Hope Creek Generating Station (TAC Nos. ME1835, ME1833, and 

ME1831). (Accession No. ML102360221) 

September 2, 2010 Summary of Telephone Conference Call Held on June 21, 2010, Between 

the NRC and PSEG Nuclear, LLC Concerning Responses to Requests for 

Additional Information Pertaining to the Hope Creek Generating Station, 

License Renewal Application. (Accession No. ML102320179) 

September 3, 2010 Letter to T. Joyce, PSEG Nuclear, LLC: Regarding Audit Report of the 

Hope Creek Generating Station License Renewal Application. 

(Accession No. ML101660452) 

September 3, 2010 Summary of Telephone Conference Call Held on August 16, 2010, 

Between the NRC and PSEG Nuclear, LLC Concerning Draft Request for 

Additional Information Pertaining to the Hope Creek Generating Station, 

License Renewal Application. (Accession No. ML102320178) 

September 7, 2010 Letter from R.C. Braun, PSEG Nuclear LLC: Supplement to License 

Renewal Application to include Low Voltage Power Cables in the Scope 

of the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements (E-3) Program. (Accession 

No. ML102530452) 

September 20, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Hope Creek Revised 

RAI 4.3-01 Response Associated with the License Renewal Application. 

(Accession No. ML102660024) 

September 29, 2010 Letter to T.P. Joyce, PSEG Nuclear, LLC: Environmental Project Manager 

Change for the License Renewal of Hope Creek Generating Station (TAC 

No. ME1831). (Accession No. ML102600324) 
Appendix B 

 B-11 

September 29, 2010 Federal Register: Notice Regarding the ACRS Subcommittee Meeting on 

Plant License Renewal (Hope Creek), November 3, 2010. (Accession 

No. ML102720723) 

September 30, 2010 Letter to T.P. Joyce, PSEG Nuclear, LLC: Safety Evaluation Report 

Related to the License Renewal of Hope Creek Generating Station. 

(Accession No. ML102660148) 

September 30, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: Hope Creek - Supplement 

Response to RAIs B.2.1.37-01 and B.2.1.37-02 to License Renewal 

Application to Revise the Maximum Cable Testing and Cable Vault 

Inspection Frequencies and Clarify Related Information in Inaccessible 

Medium Voltage Cables. (Accession No. ML102790058) 

September 30, 2010 Memoranda from B.M. Pham to E.M. Hackett: Advisory Committee on 

Reactor Safeguards Review of the Hope Creek Generating Station 

License Renewal Application - Safety Evaluation Report with Open Items. 

(Accession No. ML102710067) 

October 1, 2010 Letter from R.J. Conte to T.P. Joyce, PSEG Nuclear, LLC: IR 05000272, 

05000311, 05000354-10-010; June 7-10, 21-24, August 9 -12, 26, 2010; 

Salem Nuclear Generating Station, Units 1 and 2, and Hope Creek 

Generating Station; License Renewal Inspection Report of the Scoping of 

Non-Safety Systems and the Proposed Aging Management. (Accession 

No. ML102740350) 

October 12, 2010 Letter to T.P. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application for Buried Piping (TAC No. ME1832). (Accession 

No. ML102780422) 

October 14, 2010 Letter from R.J. Conte to T.P. Joyce, PSEG Nuclear, LLC: IR 05000272-

10-006, 05000311-10-006, 05000354-10-006 on 6/7/10 - 06/10/10, 

06/21/10 - 06/24/10 and 8/9/10 - 08/12/10 for Salem Nuclear Generating 

Station, Units 1 and 2, and Hope Creek Generating Station; License 

Renewal Inspection Report - Errata. (Accession No. ML102871030) 

October 21, 2010 Letter to C. Fricker, PSEG Nuclear, LLC: Issuance of the Environmental 

Scoping Summary Report for the Staff’s Review of the License Renewal 

Application for Salem Nuclear Generating Station, Units 1 and 2, and 

Hope Creek Generating Station. (Accession No. ML102350315) 

October 21, 2010 Letter from B.M. Pham to U.S. Environmental Protection Agency, Office 

of Federal Activities: Notice of Availability of the Draft Plant-Specific 

Supplement 45 to the Generic Environmental Impact Statement for 

License Renewal of Nuclear Plants Regarding the Hope Creek 

Generating Station and Salem Nuclear Generating Station, Units 1 and 2. 

(Accession No. ML102930322) 

October 21, 2010 Federal Register: Notice of Availability of the Draft Supplement 45 to the 

Generic Environmental Impact Statement for the License Renewal of 

Salem Nuclear Generating Station, Units 1 and 2, and Hope Creek 

Generating Station. (Accession No. ML102780678) 
Appendix B 

 B-12 

October 21, 2010 Federal Register: Notice of Availability of Draft Plant-Specific Supplement 

45 to the Generic Environmental Impact Statement for License Renewal 

of Nuclear Plants Regarding the Salem Nuclear Generating Station, Units 

1 and 2, and the Hope Creek Generating Station. (Accession No. 

ML102790646) 

October 28, 2010 Notice of Meeting on November 17, 2010, to Discuss the Draft 

Supplemental Environmental Impact Statement for the License Renewal 

of Hope Creek Generating Station and Salem Nuclear Generating Station 

Units 1 and 2. (Accession No. ML102950006) 

October 29, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Hope Creek - Response to 

NRC Request for Additional Information, dated October 12, 2010, Related 

to Buried Piping Inspection Program License Renewal Application. 

(Accession No. ML103070480) 

October 31, 2010 NUREG-1437, Supplement 45, Volume 1, “Generic Environmental Impact 

Statement for License Renewal of Nuclear Plants Regarding Hope Creek 

Generating Station and Salem Nuclear Generating Station, Units 1 and 

2,” Main Report (Draft for Comment). (Accession No. ML102940169) 

October 31, 2010 NUREG-1437, Supplement 45, Volume 2, “Generic Environmental Impact 

Statement for License Renewal of Nuclear Plants Regarding Hope Creek 

Generating Station and Salem Nuclear Generating Station, Units 1 and 

2,” Appendices (Draft for Comment). (Accession No. ML102940267) 

November 2, 2010 Summary of Telephone Conference Call Held on September 9, 2010, 

Between NRC and PSEG Concerning an LRA Supplement Pertaining to 

the Hope Creek Generating Station, License Renewal Application. 

(Accession No. ML102590383) 

November 3, 2010 Letter to M.A. Colligan, U.S. Department of Commerce, National Marine 

Fisheries Service: Notice of Availability of the Draft Plant-Specific 

Supplement 45 to the Generic Environmental Impact Statement for 

License Renewal of Nuclear Plants Regarding Hope Creek Generating 

Station and Salem Nuclear Generating Station, Units 1 and 2. (Accession 

No. ML103000444) 

November 3, 2010 Letter to S.W. Gorski, U.S. Department of Commerce, National Marine 

Fisheries Service: Notice of Availability of the Draft Plant-Specific 

Supplement 45 to the Generic Environmental Impact Statement for 

License Renewal of Nuclear Plants Regarding Hope Creek Generating 

Station and Salem Nuclear Generating Station, Units 1 and 2. (Accession 

No. ML103000462) 

November 5, 2010 Letter to D. Saunders, T.A. Slavin, State of New Jersey, Historic 

Preservation Office: Hope Creek and Salem Station License Renewal 

Application Review. (Accession No. ML103000463) 
Appendix B 

 B-13 

November 5, 2010 Letter to A.E. Scherer, U.S. Department of Interior, Fish and Wildlife 

Service: Notice of Availability of the Draft Plant-Specific Supplement 45 to 

the Generic Environmental Impact Statement for License Renewal of 

Nuclear Plants Regarding Hope Creek Generating Station and Salem 

Nuclear Generating Station, Units 1 and 2. (Accession No. 

ML103020133) 

November 8, 2010 Letter from B.M. Pham, to J. Douglas (similar letters sent to 18 tribes): 

Notice of Availability of the Draft Plant-Specific Supplement 45 to the 

Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants Regarding the Hope Creek Generating Station and Salem Nuclear 

Generating Statioin, Units 1 and 2. (Accession No. ML103050427) 

November 9, 2010 Press Release-I-10-046: NRC to Seek Public Input on Nov. 17 on Draft 

Environmental Reports for Salem, Hope Creek Nuclear Plant License 

Renewal Applications. (Accession No. ML103130288) 

November 15, 2010 Letter from P.J. Davison, PSEG Nuclear, LLC: PSEG Nuclear, LLC 

Review of the Safety Evaluation Report with Open Items Associated with 

the Hope Creek Generating Station License Renewal Application. 

(Accession No. ML103220259) 

November 17, 2010 Transcript of Public Meetings Conducted to Discuss the Draft 

Supplemental Environmental Impact Statement Related to the Review of 

the Hope Creek Generating Station and Salem Nuclear Generating 

Station, Units 1 and 2, License Renewal Application. (Accession No. 

ML103400276) 

November 17, 2010 Transcript of Public Meetings Conducted to Discuss the Draft 

Supplemental Environmental Impact Statement Related to the Review of 

the Hope Creek Generating Station and Salem Nuclear Generating 

Station, Units 1 and 2, License Renewal Application. (Accession No. 

ML103400279) 

November 19, 2010 Summary of Telephone Conference Call Held on October 21, 2010, 

Between the NRC and PSEG Nuclear, LLC Concerning Hope Creek 

Generating Station, License Renewal Application, Environmentally 

Assisted Fatigue Analysis. (Accession No. ML103190745) 

December 9, 2010 Letter to T.P. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application for Small-Bore Class 1 Piping Inspection Program 

(TAC No. ME4808). (Accession No. ML103210244) 

December 9, 2010 Memoranda from L.T. Perkins, to B.M. Pham, NRC/NRR/DLR/RPB1: 

Summary of Public Meetings Conducted to Discuss the Draft 

Supplemental Environmental Impact Statement Related to the Review of 

the Hope Creek Generating Station and Salem Nuclear Generating 

Station, Units 1 and 2, License Renewal Application. (Accession No. 

ML103280577) 
Appendix B 

 B-14 

December 13, 2010 Letter to T.P. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application for One Time Inspection and Selective Leaching 

(TAC No. ME1832). (Accession No. ML103280574) 

December 13, 2010 Letter to M.A. Colligan, U.S. Department of Commerce, National Marine 

Fisheries Service: Biological Assessment for License Renewal of the 

Hope Creek Generating Station, Unit 1, and Salem Nuclear Generating 

Station, Units 1 and 2. (Accession No. ML103350271) 

December 15, 2010 Letter from R.C. Braun, PSEG Nuclear, LLC: Hope Creek Response to 

NRC Request for Additional Information, dated December 9, 2010, 

Related to the Small-Bore Class 1 Piping Program Associated with Hope 

Creek License Renewal Application. (Accession No. ML103550230) 

December 16, 2010 Comment (3) of Robert K. Marshall, on Behalf of New Jersey Energy 

Coalition, on NRC Generic Environmental Impact Statement for License 

Renewal Regarding Hope Creek Generating Station and Salem 

Generating Station, Units 1 and 2. (Accession No. ML103560019) 

December 16, 2010 Comment (4) of Robert C. Braun on Behalf of PSEG Nuclear, LLC, on 

NRC Generic Environmental Impact Statement for License Renewal 

Regarding Hope Creek and Salem Generating Station, Units 1 and 2. 

(Accession No. ML110030699) 

December 16, 2010 Comment (5) of Grace Musumeci, on Behalf of U.S. Environmental 

Protection Agency, Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants, Draft Supplement 45 Regarding Hope Creek 

and Salem Units 1 and 2. (Accession No. ML110060287) 

December 17, 2010 Comment (6) of S. Brubaker on Behalf of State of New Jersey, 

Department of Environmental Protection on Draft Supplemental 

Environmental Impact Statement for the Salem and Hope Creek License 

Renewal. (Accession No. ML110060284) 

January 3, 2011 Letter to T.P. Joyce, PSEG Nuclear, LLC: Request for Additional 

Information for the Review of the Hope Creek Generating Station License 

Renewal Application for Drywell Shell. (Accession No. ML103440599) 

January 6, 2011 Letter from P. Davison, PSEG Nuclear, LLC: Hope Creek, Response to 

Confirmatory Item CI 4.3.5.2-1 Associated with NRC Safety Evaluation 

Report, Related to License Renewal Application. (Accession No. 

ML110110426) 

January 6, 2011 Letter from P. Davison, PSEG Nuclear, LLC: Hope Creek, Response to 

NRC Request for Additional Information, dated December 13, 2010, 

Related to One-Time Inspection and Selective Leaching of Materials 

Aging Management Programs Associated with License Renewal 

Application. (Accession No. ML110110427) 

January 10, 2011 Letter from S.W. Gorski, U.S. Department of Commerce, National Marine 

Fisheries Service Habitat Conservation Division Consultation Regarding 

the Draft Supplemental Environmental Impact Statement for Salem and 

Hope Creek License Renewal. (Accession No. ML110330351) 
Appendix B 

 B-15 

January 12, 2011 Letter from V. Maresca, State of New Jersey, Department of 

Environmental Protection, Salem and Hope Creek License Renewal 

Review. (Accession No. ML110120502) 

January 14, 2011 Letter from A.L. Raddant, U.S. Department of Interior, Draft 

Environmental Impact Statement for License Renewal of Nuclear Plants, 

Regarding Hope Creek Generating Station and Salem Nuclear 

Generating Station, Units 1 and 2, Supplement 45 to NUREG-1437. 

(Accession No. ML110390454) 

January 19, 2011 Letter from P. Davison, PSEG Nuclear, LLC: Hope Creek, Response to 

NRC Request for Additional Information RAI B.2.1.28-3, dated January 3, 

2011, and Other Updates to Aging Management Program Operating 

Experience Information from 2010 Refueling Outage. (Accession No. 

ML110210677) 

February 9, 2011 Meeting Summary, from B.M. Brady, Summary of Telephone Conference 

Call Held on September 15, 2010, Between the NRC and PSEG Nuclear, 

LLC, Concerning Questions Pertaining to the Hope Creek Generating 

Station License Renewal Application. (Accession No. ML110050159) 

February 9, 2011 Meeting Summary, from B.M. Brady, Summary of Telephone Conference 

Call Held on November 18, 2010, Between the U.S. Nuclear Regulatory 

Commission and PSEG Nuclear, LLC, Concerning Findings on the Hope 

Creek Generating Station Recent Outage. (Accession 

No. ML103490929) 

February 11, 2011 Letter from B.M. Pham to S.W. Gorski, U.S. Department of Commerce, 

National Marine Fisheries Service, Essential Fish Habitat Assessment for 

License Renewal of the Hope Creek Generating Station and Salem 

Nuclear Generating Station, Units 1 and 2. (Accession No. 

ML110320664) 

March 1, 2011 Minutes of the Meeting of the Subcommittee on Plant License Renewal 

Regarding Hope Creek Generating Station on November 3, 2010, in 

Rockville, Maryland. (Accession No. ML110600557) 

March 9, 2011 Letter to T.P. Joyce, PSEG Nuclear, LLC: Safety Evaluation Report 

Related to the License Renewal of Hope Creek Generating Station. 

(Accession No. ML103510552) 

March 9, 2011 Safety Evaluation Report Related to the License Renewal of Hope Creek 

Generating Station. (Accession No. ML110690244) 

March 25, 2011 Summary of Telephone Conference Call Held on August 30, 2010, 

Between the U.S. Nuclear Regulatory Commission and PSEG Nuclear, 

LLC, Concerning Questions Pertaining to the Hope Creek Generating 

Station License Renewal Application. (Accession No. ML110070030) 

March 30, 2011 Notice of Availability of the Final Plant-Specific Supplement 45 to the 

Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants Regarding Hope Creek Generating Station and Salem Nuclear 

Generating Station Units 1 and 2 -FRN. (Accession No. ML110770320) 
Appendix B 

 B-16 

March 31, 2011 NUREG-1437, Supplement 45, "Generic Environmental Impact Statement 

for License Renewal of Nuclear Plants Regarding Hope Creek Generating 

Station and Salem Nuclear Generating Station, Units 1 and 2" (Final 

Report). (Accession No. ML11089A021) 

April 20, 2011 Notice of Meeting (583rd) of the Advisory Committee on Reactor 

Safeguards - Federal Register Notice -FRN. (Accession 

No. ML111220012) 

May 4, 2011 Summary of Telephone Conference Call Held on March 25, 2011, 

Between the U.S. Nuclear Regulatory Commission and PSEG Nuclear, 

LLC, Concerning Findings on the Hope Creek Generating Station Gas 

Turbine. (Accession No. ML11105A037) 

May 5, 2011 Letter to T.P. Joyce, PSEG Nuclear, LLC: Project Manager Change for 

the License Renewal of Hope Creek Generating Station (TAC No. 

ME1832). (Accession No. ML111090416) 

May 13, 2011 E-mail from A. D. Cunanan, USNRC: Hope Creek revised draft Request 

for Additional Information B.2.1.28-4 related to the ASME Section Xl 

Subsection IWE Aging Management Program Associated with the 

License Renewal Application. (Accession No. ML11139A435) 

May 19, 2011 Letter from P. Davison, PSEG Nuclear, LLC: Hope Creek, Response to 

NRC Draft Request for Additional Information B.2.1.28-4 related to the 

ASME Section Xl Subsection IWE Aging Management Program 

Associated with the License Renewal Application. (Accession No. 

ML11144A016) 

June 2, 2011 Summary of Telephone Conference Call Held on May 11, 2011, Between 

the U.S. Nuclear Regulatory Commission and PSEG Nuclear, LLC, 

Concerning the Hope Creek License Condition for the Drywell. 

(Accession No. ML11137A076) 

June 8, 2011 Summary of Telephone Conference Call Held on May 9, 2011, Between 

the U.S. Nuclear Regulatory Commission and PSEG Nuclear, LLC, 

Concerning Status of Hope Creek Drywell Air Gap Drains. (Accession 

No. ML11138A321) 

June 10, 2011 Letter to T.P. Joyce, PSEG Nuclear, LLC: Revised Safety Evaluation 

Report and Revised Schedule Related to the License Renewal of Hope 

Creek Generating Station. (Accession No. ML11144A245) 

June 10, 2011 Safety Evaluation Report Related to the License Renewal of Hope Creek 

Generating Station. (Accession No. ML11161A105) 

June 16, 2011 Letter to Gregory B. Jaczko, Chairman, USNRC: Report on the Safety 

Aspects of the License Renewal Application for the Hope Creek 

Generating Station. (Accession No. ML11164A049) 
 C-1 

APPENDIX C 

PRINCIPAL CONTRIBUTORS 

This appendix lists the principal contributors for the development of this safety evaluation report 

(SER) and their areas of responsibility. 

APPENDIX C: PRINCIPAL CONTRIBUTORS 

Name Responsibility 

A. Cunanan Project Management 

A. Hiser Management Oversight 

A. Johnson Reviewer—Mechanical 

A. Klein Management Oversight 

A. Prinaris Reviewer—Mechanical 

A. Sheikh Reviewer—Structural 

A. Ulses Management Oversight 

A. Wong Reviewer—Mechanical 

B. Brady Project Management 

B. Elliot Reviewer—Mechanical 

B. Fu Reviewer—Mechanical 

B. Holian Management Oversight 

B. Lehman Reviewer—Structural 

B. Parks Reviewer—Mechanical 

B. Pham Management Oversight 

B. Rogers Reviewer—Scoping and Screening Methodology 

C. Doutt Reviewer—Electrical 

C. Nickell Reviewer—Mechanical 

D. Alley Reviewer—Mechanical 

D. Ashley Project Management 

D. Cunanan Reviewer—Mechanical 
Appendix C 

 C-2 

APPENDIX C: PRINCIPAL CONTRIBUTORS 

Name Responsibility 

D. Hoang Reviewer—Structural 

D. Nguyen Reviewer—Electrical 

D. Pelton Management Oversight 

E. Davidson Reviewer—Balance of Plant 

E. Smith Reviewer—Scoping and Screening Methodology 

E. Wong Reviewer—Chemical 

F. Farzam Reviewer—Structural 

G. Cheruvenki Reviewer—Mechanical 

G. Casto Management Oversight 

G. Cranston Management Oversight 

G. Shukla Management Oversight 

G. Wilson Management Oversight 

H. Walker Reviewer—Mechanical 

J. Dozier Management Oversight 

J. Gavula Reviewer—Mechanical 

J. Robinson Management Oversight 

K. Green Project Management 

K. Miller Reviewer—Electrical 

J. Medoff Reviewer—Mechanical 

L. Perkins Project Management 

M. Cunningham Management Oversight 

M. Evans Management Oversight 

M. Galloway Management Oversight 

M. Khana Management Oversight 

M. Kichline Reviewer—Mechanical 

M. Mitchell Management Oversight 
Appendix C 

 C-3 

APPENDIX C: PRINCIPAL CONTRIBUTORS 

Name Responsibility 

M. Modes Management Oversight 

N. Iqbal Reviewer—Fire Protection 

N. Nguyen Project Management 

O. Yee Reviewer—Mechanical 

P. Purtscher Reviewer—Mechanical 

R. Auluck Management Oversight 

R. Dennig Management Oversight 

R. Li Reviewer—Electrical 

R. Kalikian Reviewer—Mechanical 

R. Karipenini Management Oversight 

R. Mathew Management Oversight 

R. Sun Reviewer—Mechanical 

R. Taylor Management Oversight 

S. Cuadrado-de Jesus Project Management 

S. Min Reviewer—Mechanical 

S. Ray Reviewer—Electrical 

S. Sheng Reviewer - Mechanical 

W. Holston Reviewer - Mechanical 

W. Ruland Management Oversight 

W. Smith Reviewer—Mechanical 

APPENDIX C: PRINICPAL CONTRIBUTORS 

Contract Support 

Name Responsibility 

Advanced Technologies and Laboratories International, 

Inc. 

Technical Review 

Center for Nuclear Regulatory Analysis Technical Review 

Oak Ridge National Laboratories Technical Review 
Appendix C 

 C-4 

APPENDIX C: PRINCIPAL CONTRIBUTORS 

Name Responsibility 

Pacific Northwest National Laboratory Technical Review 

Thomas Associates, Inc. SER Support 
 D-1 

APPENDIX D 

REFERENCES 

This appendix contains a listing of the references used in the preparation of the Safety 

Evaluation Report (SER) prepared during the review of the license renewal application (LRA) for 

Hope Creek Generating Station (HCGS), Docket Number 50-354. 

APPENDIX D: REFERENCES

10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities.” 

10 CFR Part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory 

Functions.” 

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

American Concrete Institute (ACI) 201.2R, “Guide to Durable Concrete.” 

ACI 301-72, “Specifications for Structural Concrete for Buildings.” 

ACI 318-71, “Building Code Requirements for Reinforced Concrete.” 

ACI 349.3R-96, “Evaluation of Existing Nuclear Safety-Related Concrete Structures.” 

ACI 349-85, “Code Requirements for Nuclear Safety Related Concrete.” 

American National Standards Institute (ANSI) B.30.10, “Hooks.” 

ANSI B30.11, “Monorails and Underhung Cranes.” 

ANSI B30.16, “Overhead Hoist (Underhung) Inspection.” 

ANSI B30.2, “Overhead and Gantry Cranes - Top Running Bridge, Single or Multiple Girder, Top Running Trolley 

Hoist.” 

ANSI B31.1, “Power Piping.” 

American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section III. 

ASME Boiler & Pressure Vessel Code, Section XI. 

American Society of Metals, Metals Handbook, Volume 13, 9th Edition. 

American Society for Testing and Materials (ASTM) C-33, “Standard Specification for Concrete Aggregates.” 

ASTM C150, “Standard Specification for Portland Cement.” 

ASTM C227-50, “Standard Test Method for Potential Alkali Reactivity of Cement-Aggregates Combinations.” 

ASTM C289-64, “Standard Test Method for Potential Alkali-Silica Reactivity of Cement-Aggregates (Chemical 

Method).” 

ASTM C295-54, “Standard Guide for Petrographic Examination of Aggregates for Concrete.” 

ASTM D2709, “Standard Test Method for Water and Sediment in Middle Distillate Fuels by Centrifuge.” 
Appendix D 

 D-2 

APPENDIX D: REFERENCES

ASTM D2276, “Standard Test Method for Particulate Contaminant in Aviation Fuel by Line Sampling.” 

ASTM D4057-95, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products.” 

ASTM D5163, “Standard Guide for Establishing a Program for Condition Assessment of Coating Service Level I 

Coating Systems in Nuclear Power Plants.” 

ASTM D6224-98, “Standard Practice for In-Service Monitoring for Lubricating Oil for Auxiliary Power Plant 

Equipment.” 

BWRVIP-05, “Reactor Vessel Shell Weld Inspection Guidelines.” 

BWRVIP-18-A, “BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and Flaw Evaluation 

Guidelines.” 

BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-29, “BWR Water Chemistry Guidelines-1996 Revision.” EPRI TR-103515 

BWRVIP-38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines.” EPRI TR-108823 

BWRVIP-41, “BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-42-A, “BWR Vessel and Internals Project Boiling Water Reactor Low Pressure Coolant Injection and 

Flaw Evaluation Guidelines.” 

BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-48-A, “Vessel ID Attachment weld Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-49-A, “Instrument Penetration Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-74-A, “Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-75-A, “Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules.” 

BWRVIP-86-A, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan.” 

BWRVIP-114, -115, -117, and -121, “RAMA Fluence Methodology Procedures Manual.” 

BWRVIP-116, “Integrated Surveillance Program.” 

BWRVIP-130, “BWR Water Chemistry Guidelines-2004 Revisions.” EPRI 1008192 

BWRVIP-139, “Steam Dryer Inspection and Flaw Evaluation Guidelines.” 

BWRVIP-190, “BWR Water Chemistry Guidelines-2008 Revisions.” 

Electric Power Research Institute (EPRI) Handbook of Neutron Absorber Materials for Spent Nuclear Fuel 

Transportation and Storage, 2006 Edition. 

EPRI 1003471, “Electrical Connector Application Guideline,” December 2002. 

EPRI 1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,” Revision 4, 

January 2006. 

EPRI 1013475, “Plant Support Engineering: License Renewal Electrical Handbook,” February 2007. 
Appendix D 

 D-3 

APPENDIX D: REFERENCES

EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, April 1988. 

EPRI NSAC-202L-R2, “Recommendations for an Effective Flow-Accelerated Corrosion Program.” 

EPRI NSAC-202L-R3, “Recommendations for an Effective Flow-Accelerated Corrosion Program.” 

EPRI TR-1007820, “Closed Cooling Water Chemistry Guideline.” 

EPRI TR-104213, “Bolted Joint Maintenance & Applications Guide,” December 1, 1995. 

EPRI TR-107396, “Closed Cooling Water Chemistry Guideline.” 

EPRI TR 112657, “Revised Risk-Informed Inservice Inspection Evaluation Procedure.” 

Generic Letter (GL) 88-01, “NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic 

Stainless Steel Piping.” 

GL-89-13, “Service Water System Problems Affecting Safety-Related Equipment.” 

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.” 

GL 2007-01, “Inaccessible Or Underground Power Cable Failures That Disable Accident Mitigation Systems Or 

Cause Plant Transients.” 

HCGS, Updated Final Safety Analysis Report (UFSAR). 

Information Notice (IN) 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response to IE 

Bulletin 80-11.” 

IN 94-63, “Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks.” 

IN 2004-08, “Reactor Coolant Pressure Boundary Leakage Attributable to Propagation of Cracking in Reactor 

Vessel Nozzle Welds.” 

LRA, HCGS, dated August 18, 2009. 

NEI 95-10, Revision 6, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License 

Renewal Rule,” June 2005. 

NFPA 25 Standard for Inspection, Testing and Maintenance of Water-Based Fire Protection Systems 

NUREG-0313, “Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure 

Boundary Piping.” 

NUREG-0554, “Single Failure-Proof Cranes for Nuclear Power Plants.” 

NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants,” July 1980. 

NUREG-0619, “BWR Feedwater Nozzle and Control Rod Driven Return Line Nozzle Cracking.” 

NUREG-1048, “Hope Creek Safety Evaluation Report dated 10/1984 and Supplements 2, 5, and 6 dated 8/85, 

4/86 and 7/86 respectively.” 

NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants.” 

NUREG-1437, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS).” 
Appendix D 

 D-4 

APPENDIX D: REFERENCES

NUREG-1557, “Summary of Technical Information and Agreements from Nuclear Management and Resources 

Counci1 Industry Reports Addressing License Renewal,” October 1996. 

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-1924, “Electrical Raceway Fire Barrier Systems in US Plants.” 

NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless 

Steels.” 

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant 

Components.” 

NUREG/CR-6583, “Effects of LWR Coolant Environments on Fatigue Curves of Carbon and Low-Alloy Steels.” 

NUREG/CR-6909, “Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials.” 

Regulatory Guide (RG) 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants.” 

RG 1.147, “Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1.” 

RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.” 

RG 1.183, “Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power 

Reactors.”

RG 1.45, “Guidance on Monitoring and Responding to Reactor Coolant System Leakage.” 

RG 1.54, “Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants.”

RG 1.65, “Materials and Inspections for Reactor Vessel Closure Studs.” 

RG 1.99, “Radiation Embrittlement of Reactor Vessel Materials.” 
BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse)

NRC FORM 335

(12-2010)

NRCMD 3.7

U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

 (Assigned by NRC, Add Vol., Supp., Rev.,

 and Addendum Numbers, if any.)

NUREG-2102

3. DATE REPORT PUBLISHED

MONTH

June

YEAR

2011

4. FIN OR GRANT NUMBER

2. TITLE AND SUBTITLE

Safety Evaluation Report Related to the License Renewal of Hope Creek Generating Station

5. AUTHOR(S)

See SER Appendix C

6. TYPE OF REPORT

7. PERIOD COVERED (Inclusive Dates)

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor,

Division of License Renewal

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, 

Same as above

provide name and mailing address.)

and mailing address.)

10. SUPPLEMENTARY NOTES

Arthur Cunanan, NRC Project Manager

11. ABSTRACT (200 words or less)

This safety evaluation report (SER) documents the technical review of the Hope Creek Generating Station (HCGS), license

renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated August 18, 2009,

PSEG Nuclear, LLC (PSEG or 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." PSEG requests renewal of the

operating license (Facility Operating License Number NPF-57) for a period of 20 years beyond the current expiration at midnight

April 11, 2026.

HCGS is located approximately 40 miles from Philadelphia, Pennsylvania, and 8 miles from Salem, New Jersey. The NRC

issued the construction permit on November 4, 1974, and the operating license on July 25, 1986. The unit is a Mark I

boiling-water reactor design. The licensed power output of the unit is 3,840 megawatt thermal with a gross electrical output of

approximately 1,268 megawatt electric.

This SER presents the status of the staff's review of information submitted through May 19, 2011, the cutoff date for

consideration in this SER. The one open item previously identified by the staff for the SER with open items have been closed

(see SER Section 1.5); the staff did not identify any open items before the staff made a final determination. SER Section 6.0

provides the staff's final conclusion of the LRA review.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.)

Hope Creek Generating Station

PSEG Nuclear, LLC

License renewal

Nuclear power plant

10 CFR Part 54

Docket No. 50-354

Aging Management

Scoping and Screening

Time-limited aging analysis

14. SECURITY CLASSIFICATION

13. AVAILABILITY STATEMENT

unlimited

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (12-2010)

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001


NUREG

-2102 Safety Evaluation Report Related to the License Renewal of 

Hope Creek Generating Station 
UNITED STATES 

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

--------------------

OFFICIAL BUSINESS