Safety Evaluation Report

Related to the License Renewal 

of Callaway Plant, Unit 1

Docket Number 50-483

Union Electric Company (Ameren Missouri)

Office of Nuclear Reactor Regulation

NUREG-2172

 
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 20402–0001

Internet: bookstore.gpo.gov

Telephone: 202-512-1800

Fax: 202-512-2250 

2. The National Technical Information Service 

Springfield, VA 22161–0002

www.ntis.gov

1–800–553–6847 or, locally, 703–605–6000 

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.RESOURCE@NRC.GOV

Facsimile: 301–415–2289 

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, 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 at—

The NRC Technical Library

Two White Flint North

11545 Rockville Pike

Rockville, MD 20852–2738 

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, 

from—

American National Standards Institute

11 West 42nd Street

New York, NY 10036–8002

www.ansi.org

212–642–4900 

AVAILABILITY OF REFERENCE MATERIALS

IN NRC PUBLICATIONS

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 contractorprepared 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 

(NUREG–XXXX) or agency contractors (NUREG/CR–

XXXX), (2) proceedings of conferences (NUREG/CP–

XXXX), (3) reports resulting from international 

agreements (NUREG/IA–XXXX), (4) brochures 

(NUREG/BR–XXXX), 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 (NUREG–

0750).

DISCLAIMER: This report was prepared as an account 

of work sponsored by an agency of the U.S. 

Government. Neither the U.S. Government nor any 

agency thereof, nor any employee, makes any warranty, 

expressed or implied, or assumes any legal liability or 

responsibility for any third party’s use, or the results of 

such use, of any information, apparatus, product, or 

process disclosed in this publication, or represents that 

its use by such third party would not infringe privately 

owned rights.
Safety Evaluation Report

Related to the License Renewal 

of Callaway Plant, Unit 1

Docket Number 50-483

Union Electric Company (Ameren Missouri)

Manuscript Completed: November 2014

Date Published: March 2015

Office of Nuclear Reactor Regulation

NUREG-2172

 

iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Callaway Nuclear 

Plant, Unit 1 (Callaway), license renewal application (LRA) by the United States (U.S.) Nuclear 

Regulatory Commission (NRC) staff (the staff). By letter dated December 15, 2011, Union 

Electric Company, doing business as Ameren Missouri (Ameren Missouri or the applicant),

submitted the LRA in accordance with Title 10 of the Code of Federal Regulations (10 CFR) 

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

Missouri requests renewal of the Callaway operating license (Operating License No. NPF-30) 

for a period of 20 years beyond the current expiration at midnight October 18, 2024.

Callaway is located approximately 25 miles east-northeast of Jefferson City, Missouri. The NRC 

issued the Callaway construction permit on April 16, 1976, and operating license on 

October 18, 1984. Callaway is of a pressurized-water reactor design. Westinghouse Electric 

Corporation designed and supplied the nuclear steam supply system, and General Electric 

Company designed and supplied the turbine generator. The containment is a carbon 

steel-lined, concrete structure designed by Bechtel Power Corporation. The Callaway licensed 

power output is 3,565 megawatts thermal. 

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

submitted through June 20, 2014, the cutoff date for consideration in the SER. The five open 

items previously identified by the staff for the SER with Open Items, issued April 23, 2013, have 

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

final determination is reached by the staff on the LRA. 

v

TABLE OF CONTENTS

ABSTRACT...............................................................................................................................III

ABBREVIATIONS ...................................................................................................................XV

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

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

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

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

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

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

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

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

1.6 Summary of Confirmatory Items ......................................................................... 1-11

1.7 Summary of Proposed License Conditions ......................................................... 1-11

SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING 

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

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

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

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

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

2.1.3.1 Implementation Procedures and Documentation Sources 

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

2.1.3.2 Quality Controls Applied to License Renewal Application 

Development ........................................................................... 2-4

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

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

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

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

of the Code of Federal Regulations ......................................... 2-6

2.1.4.2 Application of the Scoping Criteria in Title 10, Part 54.4(a)(2) 

of the Code of Federal Regulations ....................................... 2-10

2.1.4.3 Application of the Scoping Criteria in Title 10, Part 54.4(a)(3) 

of the Code of Federal Regulations ....................................... 2-14

2.1.4.4 Plant-Level Scoping of Systems and Structures .................... 2-16

2.1.4.5 Mechanical Component Scoping ........................................... 2-17

2.1.4.6 Structural Component Scoping .............................................. 2-18

2.1.4.7 Electrical Component Scoping............................................... 2-19

2.1.4.8 Conclusion for Scoping Methodology..................................... 2-20

2.1.5 Screening Methodology........................................................................ 2-21

2.1.5.1 General Screening Methodology............................................ 2-21

2.1.5.2 Mechanical Component Screening ........................................ 2-22

2.1.5.3 Structural Component Screening........................................... 2-23

2.1.5.4 Electrical Component Screening............................................ 2-24

2.1.5.5 Conclusion for Screening Methodology.................................. 2-25

2.1.6 Summary of Evaluation Findings.......................................................... 2-25

2.2 Plant-Level Scoping Results............................................................................... 2-25

2.2.1 Introduction .......................................................................................... 2-25

2.2.2 Summary of Technical Information in the Application ........................... 2-26

2.2.3 Staff Evaluation.................................................................................... 2-26

2.2.4 Conclusion ........................................................................................... 2-27

2.3 Scoping and Screening Results: Mechanical Systems....................................... 2-27
TABLE OF CONTENTS

vi

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ...................... 2-28

2.3.1.1 Reactor Vessel and Internals................................................. 2-28

2.3.1.2 Reactor Coolant System........................................................ 2-29

2.3.1.3 Pressurizer ............................................................................ 2-30

2.3.1.4 Steam Generators ................................................................. 2-31

2.3.1.5 Reactor Core ......................................................................... 2-32

2.3.2 Engineered Safety Features................................................................. 2-32

2.3.2.1 Containment Spray System ................................................... 2-33

2.3.2.2 Containment Integrated Leak Rate Testing System............... 2-34

2.3.2.3 Containment Hydrogen Control System................................. 2-34

2.3.2.4 Containment Purge System................................................... 2-35

2.3.2.5 High-Pressure Coolant Injection System................................ 2-36

2.3.2.6 Residual Heat Removal System ............................................ 2-37

2.3.3 Auxiliary Systems................................................................................. 2-38

2.3.3.1 Fuel Storage and Handling System ....................................... 2-39

2.3.3.2 Fuel Pool Cooling and Cleanup System................................. 2-39

2.3.3.3 Cranes, Hoists, and Elevators ............................................... 2-40

2.3.3.4 Essential Service Water System............................................ 2-41

2.3.3.5 Service Water System ........................................................... 2-42

2.3.3.6 Reactor Makeup Water System ............................................. 2-43

2.3.3.7 Component Cooling Water System........................................ 2-44

2.3.3.8 Compressed Air System ........................................................ 2-45

2.3.3.9 Nuclear Sampling System...................................................... 2-46

2.3.3.10 Chemical and Volume Control System................................. 2-47

2.3.3.11 Control Building HVAC System............................................ 2-48

2.3.3.12 Essential Service Water Pumphouse HVAC System ........... 2-49

2.3.3.13 Auxiliary Building HVAC System.......................................... 2-50

2.3.3.14 Fuel Building HVAC System ................................................ 2-51

2.3.3.15 Miscellaneous Building HVAC System................................. 2-51

2.3.3.16 Diesel Generator Building HVAC System ............................ 2-52

2.3.3.17 Radwaste Building HVAC System ....................................... 2-53

2.3.3.18 Turbine Building HVAC System ........................................... 2-53

2.3.3.19 Containment Cooling System .............................................. 2-54

2.3.3.20 Fire Protection System ........................................................ 2-54

2.3.3.21 Emergency Diesel Engine Fuel Oil Storage and Transfer 

System ................................................................................. 2-65

2.3.3.22 Standby Diesel Generator Engine System........................... 2-66

2.3.3.23 EOF and TSC Diesels, Security Building System................. 2-69

2.3.3.24 Liquid Radwaste System ..................................................... 2-70

2.3.3.25 Decontamination System..................................................... 2-70

2.3.3.26 Oily Waste System .............................................................. 2-71

2.3.3.27 Floor and Equipment Drainage System ............................... 2-72

2.3.3.28 Miscellaneous Systems In Scope ONLY for Criterion 

10 CFR 54.4(a)(2) ................................................................ 2-73

2.3.3.29 Circulating Water System .................................................... 2-75

2.3.4 Steam and Power Conversion Systems ............................................... 2-76

2.3.4.1 Main Turbine System............................................................. 2-77

2.3.4.2 Main Steam Supply System................................................... 2-78

2.3.4.3 Main Feedwater System ........................................................ 2-81

2.3.4.4 Steam Generator Blowdown System ..................................... 2-82

2.3.4.5 Auxiliary Feedwater System .................................................. 2-83
TABLE OF CONTENTS

vii

2.3.4.6 Condensate Storage and Transfer System ............................ 2-84

2.4 Scoping and Screening Results: Structures........................................................ 2-84

2.4.1 Reactor Building................................................................................... 2-85

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

2.4.1.2 Staff Evaluation ..................................................................... 2-86

2.4.1.3 Conclusion............................................................................. 2-86

2.4.2 Control Building.................................................................................... 2-86

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

2.4.2.2 Staff Evaluation ..................................................................... 2-87

2.4.2.3 Conclusion............................................................................. 2-87

2.4.3 Auxiliary Building.................................................................................. 2-87

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

2.4.3.2 Staff Evaluation ..................................................................... 2-88

2.4.3.3 Conclusion............................................................................. 2-88

2.4.4 Turbine Building ................................................................................... 2-88

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

2.4.4.2 Staff Evaluation ..................................................................... 2-88

2.4.4.3 Conclusion............................................................................. 2-89

2.4.5 Diesel Generator Building .................................................................... 2-89

2.4.5.1 Staff Evaluation Summary of Technical Information in the 

Application............................................................................. 2-89

2.4.5.2 Staff Evaluation ..................................................................... 2-89

2.4.5.3 Conclusion............................................................................. 2-89

2.4.6 Miscellaneous In-Scope Structures ...................................................... 2-90

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

2.4.6.2 Staff Evaluation ..................................................................... 2-90

2.4.6.3 Conclusion............................................................................. 2-91

2.4.7 In-Scope Tank Foundations and Structures ......................................... 2-91

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

2.4.7.2 Staff Evaluation ..................................................................... 2-91

2.4.7.3 Conclusion............................................................................. 2-92

2.4.8 Electrical Foundations and Structures.................................................. 2-92

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

2.4.8.2 Staff Evaluation ..................................................................... 2-93

2.4.8.3 Conclusion............................................................................. 2-93

2.4.9 Radwaste Building ............................................................................... 2-93

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

2.4.9.2 Staff Evaluation ..................................................................... 2-94

2.4.9.3 Conclusion............................................................................. 2-94

2.4.10 Fuel Building ...................................................................................... 2-94

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

2.4.10.2 Staff Evaluation ................................................................... 2-94

2.4.10.3 Conclusion........................................................................... 2-95

2.4.11 Essential Service Water Structures .................................................... 2-95

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

2.4.11.2 Staff Evaluation ................................................................... 2-95

2.4.11.3 Conclusion........................................................................... 2-95

2.4.12 Supports ............................................................................................ 2-95

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

2.4.12.2 Staff Evaluation ................................................................... 2-96

2.4.12.3 Conclusion........................................................................... 2-96
TABLE OF CONTENTS

viii

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems.............................................................................................................. 2-96

2.5.1 Electrical and Instrumentation and Controls Commodity Groups.......... 2-97

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

2.5.1.2 Staff Evaluation ..................................................................... 2-98

2.5.1.3 Conclusion............................................................................. 2-99

2.6 Conclusion for Scoping and Screening ............................................................... 2-99

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

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

3.0.2.3 FSAR Supplement................................................................... 3-7

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

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

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

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions 

or Enhancements ................................................................ 3-103

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL 

Report ................................................................................. 3-237

3.0.3.4 Aging Management Related to Loss of Coating Integrity 

for Internal Coatings on In-Scope Mechanical SSCs ........... 3-237

3.0.4 Quality Assurance Program Attributes Integral to Aging 

Management Programs ..................................................................... 3-247

3.0.4.1 Summary of Technical Information in the Application........... 3-247

3.0.4.2 Staff Evaluation ................................................................... 3-247

3.0.4.3 Conclusion........................................................................... 3-248

3.0.5 Operating Experience for Aging Management Programs.................... 3-248

3.0.5.1 Summary of Technical Information in Application ................ 3-248

3.0.5.2 Staff Evaluation ................................................................... 3-249

3.0.5.3 FSAR Supplement............................................................... 3-259

3.0.5.4 Conclusion........................................................................... 3-259

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant 

System.............................................................................................................. 3-260

3.1.1 Summary of Technical Information in the Application ......................... 3-260

3.1.2 Staff Evaluation.................................................................................. 3-260

3.1.2.1 AMR Results Consistent with the GALL Report ................... 3-283

3.1.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended................................... 3-304

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report ....................................................................... 3-324

3.1.3 Conclusion ......................................................................................... 3-328

3.2 Aging Management of Engineered Safety Features Systems ........................... 3-328

3.2.1 Summary of Technical Information in the Application ......................... 3-328

3.2.2 Staff Evaluation.................................................................................. 3-328

3.2.2.1 AMR Results Consistent with the GALL Report ................... 3-340

3.2.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended................................... 3-347
TABLE OF CONTENTS

ix

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL 

Report ................................................................................. 3-351

3.2.3 Conclusion ......................................................................................... 3-353

3.3 Aging Management of Auxiliary Systems.......................................................... 3-354

3.3.1 Summary of Technical Information in the Application ......................... 3-354

3.3.2 Staff Evaluation.................................................................................. 3-355

3.3.2.1 AMR Results Consistent with the GALL Report ................... 3-379

3.3.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended................................... 3-400

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report ....................................................................... 3-404

3.3.3 Conclusion ......................................................................................... 3-415

3.4 Aging Management of Steam and Power Conversion Systems ........................ 3-415

3.4.1 Summary of Technical Information in the Application ......................... 3-415

3.4.2 Staff Evaluation.................................................................................. 3-416

3.4.2.1 AMR Results Consistent with the GALL Report ................... 3-427

3.4.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended................................... 3-430

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report ....................................................................... 3-433

3.4.3 Conclusion ......................................................................................... 3-437

3.5 Aging Management of Containments, Structures, and Component Supports.... 3-437

3.5.1 Summary of Technical Information in the Application ......................... 3-438

3.5.2 Staff Evaluation.................................................................................. 3-438

3.5.2.1 AMR Results Consistent with the GALL Report ................... 3-457

3.5.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended................................... 3-465

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report ....................................................................... 3-480

3.5.3 Conclusion ......................................................................................... 3-486

3.6 Aging Management of Electrical and Instrumentation and Controls .................. 3-486

3.6.1 Summary of Technical Information in the Application ......................... 3-486

3.6.2 Staff Evaluation.................................................................................. 3-486

3.6.2.1 AMR Results Consistent with the GALL Report ................... 3-493

3.6.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended................................... 3-497

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report ....................................................................... 3-503

3.6.3 Conclusion ......................................................................................... 3-505

3.7 Conclusion for Aging Management Review Results.......................................... 3-505

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

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

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

4.1.1.1 Identification of Time-Limited Aging Analyses.......................... 4-2

4.1.1.2 Identification of Exemptions ..................................................... 4-2

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

4.1.2.1 Identification of TLAAs............................................................. 4-3

4.1.2.2 Identification of Exemptions in the LRA.................................... 4-8

4.1.3 Conclusion ............................................................................................. 4-9

4.2 Reactor Vessel Neutron Embrittlement Analysis................................................. 4-10

4.2.1 Neutron Fluence Values....................................................................... 4-10
TABLE OF CONTENTS

x

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

4.2.1.2 Staff Evaluation ..................................................................... 4-11

4.2.1.3 FSAR Supplement................................................................. 4-12

4.2.1.4 Conclusion............................................................................. 4-12

4.2.2 Charpy Upper-Shelf Energy ................................................................. 4-13

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

4.2.2.2 Staff Evaluation ..................................................................... 4-13

4.2.2.3 FSAR Supplement................................................................. 4-16

4.2.2.4 Conclusion............................................................................. 4-16

4.2.3 Pressurized Thermal Shock ................................................................. 4-16

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

4.2.3.2 Staff Evaluation ..................................................................... 4-17

4.2.3.3 FSAR Supplement................................................................. 4-19

4.2.3.4 Conclusion............................................................................. 4-19

4.2.4 Pressure-Temperature (P-T) Limits...................................................... 4-19

4.2.4.1 Summary of Technical Information in the Application............. 4-19

4.2.4.2 Staff Evaluation ..................................................................... 4-20

4.2.4.3 FSAR Supplement................................................................. 4-24

4.2.4.4 Conclusion............................................................................. 4-24

4.2.5 Low-Temperature Overpressure Protection.......................................... 4-24

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

4.2.5.2 Staff Evaluation ..................................................................... 4-25

4.2.5.3 FSAR Supplement................................................................. 4-26

4.2.5.4 Conclusion............................................................................. 4-26

4.3 Metal Fatigue...................................................................................................... 4-26

4.3.1 Fatigue Monitoring Program................................................................. 4-26

4.3.1.1 Fatigue Monitoring Methods .................................................. 4-27

4.3.1.2 Projected Status of Monitored Transients .............................. 4-29

4.3.2 ASME Section III Class I Fatigue Analysis of Vessels, Piping, and 

Components ........................................................................................ 4-36

4.3.2.A Summary of Technical Information........................................ 4-36

4.3.2.B Staff Evaluation..................................................................... 4-37

4.3.2.C FSAR Supplement ................................................................ 4-38

4.3.2.D Conclusion ............................................................................ 4-38

4.3.2.1 Reactor Coolant Pump Thermal Barrier Flange ..................... 4-38

4.3.2.2 Pressurizer Insurge-Outsurge Transients .............................. 4-42

4.3.2.3 Steam Generator ASME Section III Class 1, Class 2 

Secondary Side, and Feedwater Nozzle Fatigue Analyses.... 4-47

4.3.2.4 NRC Bulletin 88-11 Revised Fatigue Analysis of the Pressurizer 

Surge Line for Thermal Cycling and Stratification.................. 4-48

4.3.3 ASME Section III, Subsection NG, Fatigue Analysis of Reactor 

Pressure Vessel Internals .................................................................... 4-51

4.3.3.1 Summary of Technical Information in the Application............. 4-51

4.3.3.2 Staff Evaluation ..................................................................... 4-52

4.3.3.3 FSAR Supplement................................................................. 4-53

4.3.3.4 Conclusion............................................................................. 4-53

4.3.4 Effects of Reactor Coolant System Environment on Fatigue Life of Piping 

and Components (Generic Safety Issue 190) ...................................... 4-54

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

4.3.4.2 Staff Evaluation ..................................................................... 4-54

4.3.4.3 FSAR Supplement................................................................. 4-71
TABLE OF CONTENTS

xi

4.3.4.4 Conclusion............................................................................. 4-72

4.3.5 Assumed Thermal Cycle Count for Allowable Secondary Stress 

Range Reduction Factor in ANSI B31.1 and ASME Section III Class... 4-72

4.3.5.1 Summary of Technical Information in the Application............. 4-72

4.3.5.2 Staff Evaluation ..................................................................... 4-73

4.3.5.3 FSAR Supplement................................................................. 4-75

4.3.5.4 Conclusion............................................................................. 4-75

4.3.6 Fatigue Design of Spent Fuel Pool Liner and Racks for Seismic 

Events ................................................................................................. 4-75

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

4.3.6.2 Staff Evaluation ..................................................................... 4-76

4.3.6.3 FSAR Supplement................................................................. 4-77

4.3.6.4 Conclusion............................................................................. 4-77

4.3.7 Fatigue Design and Analysis of Class 1E Electrical Raceway Support 

Angle Fittings for Seismic Events......................................................... 4-77

4.3.7.1 Summary of Technical Information in the Application............. 4-77

4.3.7.2 Staff Evaluation ..................................................................... 4-77

4.3.7.3 FSAR Supplement................................................................. 4-78

4.3.7.4 Conclusion.............................................................................. 4-79

4.3.8 Fatigue Analyses of Class 2 Heat Exchangers..................................... 4-79

4.3.8.1 Summary of Technical Information in the Application............. 4-79

4.3.8.2 Staff Evaluation ..................................................................... 4-80

4.3.8.3 FSAR Supplement................................................................. 4-90

4.3.8.4 Conclusion............................................................................. 4-91

4.4 Environmental Qualification (EQ) of Electric Equipment ..................................... 4-91

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

4.4.2 Staff Evaluation.................................................................................... 4-91

4.4.3 FSAR Supplement ............................................................................... 4-94

4.4.4 Conclusion ........................................................................................... 4-94

4.5 Concrete Containment Tendon Prestress........................................................... 4-94

4.5.1 Summary of Technical Information in the Application ........................... 4-94

4.5.2 Staff Evaluation.................................................................................... 4-96

4.5.3 FSAR Supplement ............................................................................... 4-98

4.5.4 Conclusion ........................................................................................... 4-99

4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analyses ............................................................................................................ 4-99

4.6.1 Design Cycles for the Main Steam Line and Feedwater Penetrations .. 4-99

4.6.1.1 Summary of Technical Information in the Application............. 4-99

4.6.1.2 Staff Evaluation ................................................................... 4-100

4.6.1.3 FSAR Supplement............................................................... 4-101

4.6.1.4 Conclusion........................................................................... 4-102

4.6.2 Fatigue Waiver Evaluations for the Access Hatches and Leak Chase 

Channels ........................................................................................... 4-102

4.6.2.1 Summary of Technical Information in the Application........... 4-102

4.6.2.2 Staff Evaluation ................................................................... 4-103

4.6.2.3 FSAR Supplement............................................................... 4-104

4.6.2.4 Conclusion........................................................................... 4-104

4.7 Other Plant-Specific Time-Limited Aging Analyses ........................................... 4-104

4.7.1 Containment Polar Crane, Fuel Building Cask Handling Crane, 

Spent Fuel Pool Bridge Crane, and Refueling Machine CMAA 70 Load 

Cycle Limits ....................................................................................... 4-104
TABLE OF CONTENTS

xii

4.7.1.1 Summary of Technical Information in the Application........... 4-104

4.7.1.2 Staff Evaluation ................................................................... 4-106

4.7.1.3 FSAR Supplement............................................................... 4-107

4.7.1.4 Conclusion........................................................................... 4-107

4.7.2 Inservice Flaw Analyses that Demonstrate Structural Integrity for 40 

Years ................................................................................................. 4-108

4.7.2.1 Summary of Technical Information in the Application........... 4-108

4.7.2.2 Staff Evaluation ................................................................... 4-108

4.7.2.3 FSAR Supplement............................................................... 4-111

4.7.2.4 Conclusion........................................................................... 4-111

4.7.3 Corrosion Analysis of the Reactor Vessel Cladding Indications.......... 4-112

4.7.3.1 Summary of Technical Information in the Application........... 4-112

4.7.3.2 Staff Evaluation ................................................................... 4-112

4.7.3.3 FSAR Supplement............................................................... 4-116

4.7.3.4 Conclusion........................................................................... 4-117

4.7.4 Reactor Vessel Underclad Cracking Analyses ................................... 4-117

4.7.4.1 Summary of Technical Information in the Application........... 4-117

4.7.4.2 Staff Evaluation ................................................................... 4-117

4.7.4.3 FSAR Supplement............................................................... 4-119

4.7.4.4 Conclusion........................................................................... 4-119

4.7.5 Reactor Coolant Pump Flywheel Fatigue Crack Growth Analysis....... 4-119

4.7.5.1 Summary of Technical Information in the Application........... 4-119

4.7.5.2 Staff Evaluation ................................................................... 4-119

4.7.5.3 FSAR Supplement............................................................... 4-120

4.7.5.4 Conclusion........................................................................... 4-120

4.7.6 High-Energy Line Break Postulation Based on Fatigue Cumulative 

Usage Factors ................................................................................... 4-120

4.7.6.1 Summary of Technical Information in the Application........... 4-120

4.7.6.2 Staff Evaluation ................................................................... 4-121

4.7.6.3 FSAR Supplement............................................................... 4-122

4.7.6.4 Conclusion........................................................................... 4-122

4.7.7 Fatigue Crack Growth Assessment in Support of a Fracture 

Mechanics Analysis for the Leak-Before-Break Elimination of 

Dynamic Effects of Piping Failures..................................................... 4-122

4.7.7.1 Summary of Technical Information in the Application........... 4-122

4.7.7.2 Staff Evaluation ................................................................... 4-123

4.7.7.3 FSAR Supplement............................................................... 4-125

4.7.7.4 Conclusion........................................................................... 4-125

4.7.8 Replacement Class 3 Buried Piping ................................................... 4-125

4.7.8.1 Summary of Technical Information in the Application........... 4-125

4.7.8.2 Staff Evaluation ................................................................... 4-126

4.7.8.3 FSAR Supplement............................................................... 4-128

4.7.8.4 Conclusion........................................................................... 4-128

4.7.9 Replacement Steam Generator Tube Wear ....................................... 4-128

4.7.9.1 Summary of Technical Information in the Application........... 4-128

4.7.9.2 Staff Evaluation ................................................................... 4-128

4.7.9.3 FSAR Supplement............................................................... 4-132

4.7.9.4 Conclusion........................................................................... 4-132

4.7.10 Mechanical Environmental Qualification........................................... 4-132

4.7.10.1 Summary of Technical Information in the Application......... 4-132

4.7.10.2 Staff Evaluation ................................................................. 4-133
TABLE OF CONTENTS

xiii

4.7.10.3 FSAR Supplement............................................................. 4-134

4.7.10.4 Conclusion......................................................................... 4-135

4.8 Conclusion........................................................................................................ 4-135

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

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

Appendices

APPENDIX A CALLAWAY PLANT UNIT 1 LICENSE RENEWAL COMMITMENTS...............A-1

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

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

APPENDIX D REFERENCES................................................................................................D-1
TABLE OF CONTENTS

xiv

List of Tables

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

Table 2.3-1 Fire Water Systems or Components Not within the Scope of License 

Renewal............................................................................................................ 2-56

Table 3.0-1 Callaway Aging Management Programs.............................................................. 3-8

Table 3.1-1 Staff Evaluation for Reactor Vessel, RVIs, RCS Components in the 

GALL Report................................................................................................... 3-261

Table 3.2-1 Staff Evaluation for ESF Systems Components in the GALL Report ............... 3-329

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report......... 3-356

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

the GALL Report............................................................................................. 3-417

Table 3.5-1 Staff Evaluation for Containment, Structures, and Component Supports 

Components in the GALL Report .................................................................... 3-439

Table 3.6-1 Staff Evaluation for Electrical and I&C in the GALL Report.............................. 3-488
xv

ABBREVIATIONS

°C degree Celsius

°F degree Fahrenheit

ΔT temperature change

σ standard deviation

3SM primary plus secondary stress intensity

A/LAIs applicant or licensee action item

ACI American Concrete Institute

ACSR aluminum conductors, steel reinforced

ADAMS Agencywide Documents Access and Management System

AERM aging effect requiring management

AISC American Institute of Steel Construction

AMP Aging Management Program

AMR Aging Management Review

ANS American Nuclear Society

ANSI American National Standards Institute

ASCE American Society of Civil Engineers

ASI accumulator safety injection

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

AVB anti-vibration bar

B&PV boiler and pressure vessel

B&W Babcock and Wilcox

BMI bottom-mounted instrument

BRWS borated refuel water storage

BTR boron thermal regeneration

CAP Corrective Action Program

CAR Callaway Action Request

CASS cast austenitic stainless steel

CBF cycle-based fatigue

CCW component cooling water

CEL Callaway Equipment List

CETNA core exit thermocouple nozzle assembly

CF chemistry factor

CFR Code of Federal Regulations

CLB current licensing basis

CMMA Crane Manufacturers Association of America

CMTR certified materials test report

COMS cold overpressure mitigation system

CRDM control rod drive mechanism

CRGT control rod guide tube

CST condensate storage tank

Cu copper

CUF cumulative usage factor
ABBREVIATIONS

xvi

CUFen environmentally adjusted fatigue usage factor

CVC chemical and volume control

CVCS chemical and volume control system

DBE design-basis event

EAF environmentally assisted fatigue

ECC emergency core cooling

EDG emergency diesel generator

EFPY effective full power year

EMA equivalent margins analysis

EOF emergency operations facility

EOL end-of-life

EOLE end-of-life-extended

EPRI Electric Power Research Institute

ESF engineered safety features

ESW essential service water

EQ environmental qualification

Fen environmental adjustment factor

FAC flow-accelerated corrosion

FMECA failure modes, effects, and criticality analysis

FSAR final safety analysis report

FWST fire water storage tank

GALL generic aging lessons learned

GL generic letter

gpm gallon per minute

GSI generic safety issue

GTAW gas tungsten arc weld

HDPE high-density polyethylene

HELB high-energy line break

HPCI high-pressure coolant injection

HVAC heating, ventilation, and air-conditioning

I&C instrumentation and controls

IASCC irradiated-assisted stress-corrosion cracking

ICI incore instrumentation

IEEE Institute of Electrical and Electronic Engineers

ILRT integrated leak rate test

IN information notice

IPA integrated plant assessment

ISI inservice inspection

KIA crack arrest fracture toughness parameter

KIC static crack initiation fracture toughness parameter

La allowable leakage rate

LAR license amendment request

LBB leak-before-break
ABBREVIATIONS

xvii

LCO limiting condition of operation

LERF large early release frequency

LLRT local leak rate tests

LOCA loss-of-coolant accident

LRA license renewal application

LTOP low-temperature overpressure protection

MC metal containment

MeV million electron volts

MIC microbiologically influenced corrosion

MOP modified operating procedure

MRP Materials Reliability Program

MRV minimum required value

mV millivolt

MXPLR maximum path leakage rate

NACE National Association of Corrosion Engineers

NDE nondestructive evaluation

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

Ni nickel

NPS nominal pipe size

NRC U.S. Nuclear Regulatory Commission

OBE operating basis earthquake

ORNL Oak Ridge National Laboratory

P-T pressure-temperature

PLL predicted lower limit

PORV power operated relief valve

ppb parts per billion

ppm parts per million

PTLR P-T Limits Report

PTS pressurized thermal shock

PVC polyvinyl chloride

PWR pressurized water reactor

PWSCC primary water stress-corrosion cracking

QA quality assurance

RAI request for additional information

RCCA rod cluster control assembly

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RFO refueling outage

RG Regulatory Guide

RHR residual heat removal

RI-ISI risk-informed inservice inspection

RIS regulatory issue summary

RPV Reactor pressure vessel

RSG replacement steam generator
ABBREVIATIONS

xviii

RTNDT nil-ductility reference temperature 

RTPTS reference temperature for PTS

RVI reactor vessel internal

RVID RVI database

RWST refueling water storage tank

Sa alternating stress intensity

SA site addendum

SAC stranded aluminum conductor

SAW submerged arc welding

SBF stress-based fatigue

SBO station blackout

SC structure and component

SCC stress-corrosion cracking

SCCM standard cubic centimeters per minute

SE safety evaluation

SER safety evaluation report

SMAW shielded metal arc welding

SNUPPS standardized nuclear unit power plant system

SP standard plant

SRP-LR standard review plan—license renewal

SSC structure, system, and component

SSE safe-shutdown earthquake

SWOL structural weld overlay

TLAA time-limited aging analysis

TS technical specification

TSC technical support center

TSP tube support plate

UHS ultimate heat sink

UPA upper plenum anomaly

USE upper-shelf energy

UT ultrasonic test

V volt

WCAP Westinghouse Commercial Atomic Power
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 

Callaway Plant, Unit 1 (Callaway), as filed by Union Electric Company, doing business as 

Ameren Missouri (Ameren Missouri or the applicant). By letter dated December 15, 2011, 

Ameren Missouri submitted its application to the U.S. Nuclear Regulatory Commission (NRC) 

for renewal of Callaway’s 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 John Daily. Mr. Daily may be contacted by telephone at 301-415-3873 or by 

email at John.Daily@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: John Daily, Mail Stop O11F1

In its December 15, 2011, submission letter, the applicant requested renewal of the operating 

license issued under Section 103 (Operating License No. NPF-30) of the Atomic Energy Act 

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

midnight October 18, 2024. Callaway is located approximately 25 miles east-northeast of 

Jefferson City, MO. The NRC issued the Callaway construction permit on April 16, 1976, and 

operating license on October 18, 1984. Callaway is a pressurized-water reactor (PWR) design. 

Westinghouse Electric Corporation designed and supplied the nuclear steam supply system,

and General Electric Company designed and supplied the turbine generator. The containment 

is a carbon steel-lined, concrete structure designed by Bechtel Power Corporation. The 

Callaway licensed power output is 3,565 megawatts thermal. The final safety analysis report 

(FSAR) 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 Callaway license renewal is based on the applicant’s LRA and responses to the staff’s 

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

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

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

submitted through June 20, 2014. The staff reviewed information received after this date 

depending on the stage of the safety review and the volume and complexity of the information. 

The public may view the LRA and all pertinent information and materials, including the FSAR, 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 the 

Callaway County Public Library, 710 Court Street, Fulton, MO 65251. In addition, the public 
INTRODUCTION AND GENERAL DISCUSSION

1-2

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

website at http://www.nrc.gov.

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

technical details considered in evaluating the safety aspects of Callaway’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 2, 

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

(SRP-LR), dated December 2010.

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

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

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

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

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, the staff is preparing 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 will discuss the 

environmental considerations for the license renewal of Callaway. The staff plans to issue a 

draft and final plant-specific GEIS Supplement.

1.2 License Renewal Background 

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

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

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

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

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

service life.

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

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

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

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

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

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

license renewal for nuclear power plants.

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

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

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

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

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

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

effects on plant systems and components are managed during the 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 
INTRODUCTION AND GENERAL DISCUSSION

1-3

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

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

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

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

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

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

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

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

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

components (SCs).

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

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

impacts of license renewal in order to fulfill NRC responsibilities under the National 

Environmental Policy Act of 1969.

1.2.1 Safety Review 

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

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

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

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

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

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

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

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

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

functions in the event of failure, or (3) are relied on to demonstrate compliance with the NRC’s 

regulations for fire protection, environmental qualification, pressurized thermal shock, 

anticipated transient without scram, and station blackout.

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

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

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

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

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

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

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

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

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

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

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

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

required throughout the period of extended operation.

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

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

an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.
INTRODUCTION AND GENERAL DISCUSSION

1-4

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

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

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

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

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

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

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

Applications to Renew Nuclear Power Plant Operating Licenses.” This RG endorses Nuclear 

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

of 10 CFR Part 54—The License Renewal Rule,” issued in June 2005. NEI 95-10 details an 

acceptable method of implementing 10 CFR Part 54. The staff also used the SRP-LR to review 

the LRA.

In the LRA, the applicant made full use of the process defined in NUREG-1801, Revision 2, 

“Generic Aging Lessons Learned (GALL) Report,” dated December 2010. The GALL Report 

summarizes staff-approved aging management programs (AMPs) for many SCs subject to an 

AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and 

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

the license renewal review process. The GALL Report summarizes the aging management 

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

throughout the industry. The report is also a quick reference for both applicants and staff 

reviewers to AMPs and activities that can adequately manage aging during the period of 

extended operation.

1.2.2 Environmental Review 

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

staff revised the environmental protection regulations to facilitate the environmental review for 

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

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

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

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

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

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

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

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

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

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

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

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

the staff held a public meeting on March 14, 2012, at Fulton City Hall, to identify plant-specific 

environmental issues. The draft, plant-specific GEIS Supplement 51, issued in February, 2014, 

documents the results of the environmental review and makes a preliminary recommendation as 

to the license renewal action. Another public meeting was held on March 19, 2014, in Fulton, 

MO, to discuss the draft, plant-specific GEIS Supplement. The staff plans to publish the final, 

plant-specific GEIS Supplement 51 separately from this report, after considering comments on 

the draft.
INTRODUCTION AND GENERAL DISCUSSION

1-5

1.3 Principal Review Matters 

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

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

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

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

the staff’s safety review.

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

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

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

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

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

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

LRA:

10 CFR 54.19(b) requires that License Renewal applications include, 

“...conforming changes to the standard indemnity agreement, 10 CFR 140.92, 

Appendix B, to account for the expiration term of the proposed renewed license.” 

The current indemnity agreement B-93 between Ameren Missouri and the NRC 

(“Indemnity Agreement”) in Article VII states “The term of this agreement shall 

commence ... and 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...” Item 3 of the Attachment to the Indemnity Agreement, as amended, 

lists license numbers SNM-1901, NPF-25, and NPF-30. 

Ameren Missouri requests that conforming changes be made to the Indemnity 

Agreement, as amended, and/or the Attachment to said agreement, as required, 

to ensure that the Indemnity Agreement continues to apply during both the terms 

of the current licenses and the terms of the renewed licenses. Based on the 

current language contained in the Indemnity Agreement that is cited above, 

Ameren Missouri believes that no changes are necessary for this purpose if the 

current license number is retained.

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.

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

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

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

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

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

10 CFR 54.21(d).

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

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

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

contents of the LRA, including the FSAR supplement. By letters dated December 19, 2012, and 

December 20, 2013, the applicant submitted LRA updates which together summarize CLB 
INTRODUCTION AND GENERAL DISCUSSION

1-6

changes that have occurred during the staff’s review of the LRA. These submissions satisfy

10 CFR 54.21(b) requirements.

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

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

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

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

issuance of the renewed Callaway operating license. This statement adequately addresses the 

10 CFR 54.22 requirement.

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

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

the staff’s evaluation of the LRA technical information.

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

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

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

findings required by 10 CFR 54.29.

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 help 

the staff work toward its performance goals of maintaining safety, improving effectiveness and 

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

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

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

GALL Report.

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

addresses them.
INTRODUCTION AND GENERAL DISCUSSION

1-7

Table 1.4-1 Current Interim Staff Guidance

ISG Issue

(Approved ISG Number)

Purpose SER Section

“Aging Management of Internal 

Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and 

Corrosion Under Insulation” 

(LR-ISG-2012-02)

This LR-ISG gives guidance on aging 

management for internal surfaces, 

fire water system, atmospheric 

storage tanks, and corrosion under 

insulation.

SER Sections 3.0.2.2.9, 3.2.2.3.6, 

3.3.2.1.4, 3.3.2.2.8, 3.3.2.3.4, 

3.3.2.3.10, 3.3.2.3.26, 3.4.2.2.1, 

3.4.2.2.6, and 3.4.2.3.2

“Wall Thinning Due to Erosion 

Mechanisms” 

(LR-ISG-2012-01)

This LR-ISG modifies the guidance 

provided in GALL Report 

AMP XI.M17 by allowing the 

Flow-Accelerated Corrosion 

program to also manage wall 

thinning due to erosion mechanisms 

if these mechanisms are not being 

managed through another program.

SER Sections 3.2.2.1.1, 3.3.2.1.17, 

and 3.4.2.1.1

“Ongoing Review of Operating 

Experience” 

(LR-ISG-2011-05)

This LR-ISG clarifies the staff’s 

existing position in the SRP-LR that 

acceptable license renewal AMPs 

should be informed and enhanced 

when necessary, based on the 

ongoing review of both plant-specific 

and industry operating experience.

SER Section 3.0.5

“Updated Aging Management Criteria 

for Reactor Vessel Internal 

Components of Pressurized Water 

Reactors” 

(LR-ISG-2011-04)

This LR-ISG provides guidance to 

assist PWR license renewal 

applicants in adequately addressing 

MRP-227-A recommendations 

related to aging management of 

reactor vessel internal components 

during the term of the renewed 

license.

SER Section 3.0.3.1.5

“Changes to the Generic Aging 

Lessons Learned (GALL) Report 

Revision 2 Aging Management 

Program (AMP) XI.M41, ‘Buried and 

Underground Piping and Tanks’”

(LR-ISG-2011-03)

This LR-ISG provides changes to 

GALL Report AMP XI.M41. The 

AMP, as modified in this LR-ISG, 

provides one acceptable approach 

for managing the effects of aging of 

buried and underground piping and 

tanks within the scope of the License 

Renewal Rule.

SER Section 3.0.3.2.14

“Aging Management Program for 

Steam Generators” 

(LR-ISG-2011-02) 

This guidance evaluates the 

suitability of using Revision 3 of 

NEI 97-06 for implementing an 

applicant’s steam generator aging 

management program (AMP). 

SER Section 3.0.3.1.7

“Aging Management of Stainless 

Steel Structures and Components in 

Treated Borated Water”

(LR-ISG-2011-01)

This LR-ISG provides guidance as

one acceptable approach for 

managing the effects of aging during 

the period of extended operation for 

stainless steel structures and 

components exposed to treated 

borated water within the scope of the 

License Renewal Rule.

SER Sections 3.2.2.1.1, 3.2.2.1.2, 

3.2.2.1.3, 3.3.2.1.1, 3.3.2.1.2, 

3.3.2.1.3, and 3.3.2.1.16
INTRODUCTION AND GENERAL DISCUSSION

1-8

1.5 Summary of Open Items 

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

June 20, 2014, the staff closed the following open items previously identified in the “Safety 

Evaluation Report with Open Items Related to the License Renewal of Callaway Plant, Unit 1,” 

dated April 2013 (ADAMS Accession No. ML13086A224). The staff has identified no other 

open items (OIs). An item is considered open if the staff has not made a finding under 

10 CFR 54.29, “Standards for issuance of a renewed license,” with respect to that particular 

item. A summary of each closed OI is presented here.

Open Item 2.3.3.20-1 Scoping of Fire Protection SSCs

As parts of its evaluation of the applicant’s compliance with 10 CFR 50.48, “Fire protection,” the 

staff reviewed the following fire protection documents cited in the CLB listed in Callaway 

Operating License Condition 2.C(5):

• NUREG-0830, “Safety Evaluation Report Related to the Operation of Callaway Plant, 

Unit No 1,” October 1981

• NUREG-0830, Supplement No 3, “Safety Evaluation Report Related to the Operation of 

Callaway Plant, Unit No. 1,” May 1984

By letter dated June 11, 2012, the staff issued RAI 2.3.3.20-1 requesting, in part, that the 

applicant confirm if the fire suppression SSCs in (a) the auxiliary boiler room; (b) the turbine 

building north area below turbine at Elevations 2000’-0’’ and 2033’-0’’ and south area below 

turbine at Elevations 2000’-0’’ and 2033’-0’’; and (c) the turbine generator bearing, condenser 

pit, and hydrogen seal oil unit are within the scope of license renewal in accordance with 

10 CFR 54.4(a). If water systems and components were excluded from the scope of license 

renewal and not subject to an AMR, the staff requested that the applicant provide justification for 

the exclusion. 

The applicant responded to the RAI by stating that the above fire suppression SSCs are not 

within the scope of license renewal because they are not required to function to suppress a fire 

or are not required for compliance with 10 CFR 50.48. 

The staff disagrees with excluding the above fire suppression SSCs from the scope of license 

renewal and disagrees with the applicant’s basis (that they are not required to function to 

suppress a fire or are not required for compliance with 10 CFR 50.48). This exclusion is 

contrary to the FSAR, which includes the original Callaway fire protection safety evaluation, 

NUREG-0830, “Safety Evaluation Report related to the Operation of Callaway Plant, Unit No. 1,” 

dated October 1981, as the CLB. 

In addition, by letter dated August 29, 2011, the applicant submitted a license amendment 

request (LAR) to transition the existing Fire Protection Program for Callaway to a risk-informed, 

performance-based program based on National Fire Protection Association Standard

(NFPA) 805, “Performance-Based Standard for Fire Protection for Light Water Reactor Electric 

Generating Plants,” 2001 Edition, in accordance with 10 CFR 50.48(c). Following the 

NFPA 805 LAR, the applicant submitted to the staff, by letter dated December 15, 2011, an LRA

for renewal of Operating License NPF-30 for Callaway.

It is unclear to the staff what are the Fire Protection Program plant modifications planned for 

transition to NFPA 805 that may affect the existing Fire Protection Program SSCs within the 
INTRODUCTION AND GENERAL DISCUSSION

1-9

scope for license renewal. Therefore, the staff requested the applicant to identify and discuss 

the changes associated with the NFPA 805 transition, provide a gap analysis of the LRA 

Tables 2.3.3-20 and 3.3.2-20 identifying any differences between the existing plant configuration 

and NFPA 805 post-transition configuration, and provide a list of the fire protection SSCs which

will be added to or removed from, based on the NFPA 805 transition, the scope of license 

renewal in accordance with 10 CFR 54.4(a). The applicant stated that the Callaway NFPA 805 

LAR is presently under the staff’s review and is subject to change as a result of those reviews.

The applicant committed (Commitment No. 39) to perform the requested gap analysis upon 

issuance of the draft NFPA 805 SER. The staff finds that the applicant should not perform a 

gap analysis of LRA Tables 2.3.3-20 and 3.3.2-20 based on a draft NFPA 805 LAR SER. The 

staff finds that the gap analysis should be based on a final NFPA 805 LAR SER. 

By letters dated April 29, 2013, February 14, 2014, and April 15, 2014, the applicant submitted 

the requested information to close this OI. The staff’s evaluation and closure of this open item 

is documented in SER Section 2.3.3.20.

Open Item B2.1.3-1 Reactor Head Closure Studs

On multiple occasions the applicant’s closure studs became stuck during stud installation or 

removal activities. Stuck stud removal operations resulted in damage to some of the 

corresponding reactor pressure vessel (RPV) flange hole threads. In addition, during refueling 

outage No. 8 (fall 1996), stud No. 18 became stuck with only partial RPV flange hole thread 

engagement and was left in place. The applicant proposes to use its existing Reactor Head 

Closure Stud Bolting Program and stated that the program is consistent with GALL Report AMP 

XI.M3, “Reactor Head Closure Stud Bolting.” Due to its plant-specific operating experience, the 

staff issued multiple RAIs expressing concerns related to the adequacy of the applicant’s 

existing program to manage the effects of aging of the closure studs. 

Because the extent and rate of degradation were unknown, the staff was concerned that the 

existing Reactor Head Closure Stud Bolting Program may not be adequate to detect future 

wear, loss of materials, or assure that allowable stresses under the American Society of 

Mechanical Engineers (ASME) Code are not exceeded during the period of extended operation. 

The staff identified this as OI B2.1.3-1. 

In its August 29, 2013, response, the applicant provided additional information to address the 

staff’s concerns. The staff reviewed and accepted the applicant’s response as documented in 

SER Section 3.0.3.1.3. In addition, the staff proposed License Condition No. 3 (see SER 

Section 1.7) regarding the applicant’s implementation of Commitment Nos. 41 and 42. 

OI B2.1.3-1 is closed.

Open Item B2.1.6-1 Materials Reliability Program (MRP)-227-A Report Applicant/Licensee 

Action Items (A/LAIs)

The applicant’s PWR Vessel Internals Program implements the guidance of Materials Reliability 

Program (MRP)-227-A, “PWR Reactor Internals Inspection and Evaluation Guideline,” dated 

January 9, 2012, which includes the applicant’s plant-specific responses to action items, 

conditions, and limitations identified in the NRC Safety Evaluation for MRP-227, “Materials 

Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guideline 

(MRP-227, Revision 0).” During its review of the applicant’s program and responses to 

applicant/licensee action items (A/LAI) for MRP-227-A, the following aspects were identified by 

the staff as requiring additional information:
INTRODUCTION AND GENERAL DISCUSSION

1-10

A/LAI No. 1. By letter dated January 24, 2013, the applicant provided its response to RAI 

B2.1.6-4a proposing to address A/LAI No. 1 in a future submittal. The staff finds the applicant’s 

response summary to A/LAI No. 1 insufficient because the applicant did not submit its 

evaluation to demonstrate that the MRP-227-A is applicable to Callaway. According to 

RIS 2011-07, Callaway is a “Category D” plant, and the staff expects the applicant to submit an 

AMP for vessel internals that is consistent with MRP-227-A for NRC staff review and approval. 

A/LAI No. 5. By letter dated January 24, 2013, the applicant provided its response to 

RAI B2.1.6-4a indicating that it has replaced the hold-down spring with a martensitic stainless 

steel material. The staff is currently reviewing the applicant’s response to determine whether 

stress relaxation is an applicable aging effect for the new component and material. 

A/LAI No. 7. It was not evident to the staff which of the reactor vessel internal (RVI)

components in the plant design were made from cast austenitic stainless steel (CASS)

materials, or for each RVI component made from CASS, why the applicant would not need to 

provide a supporting flaw tolerance analysis, functionality analysis, or CASS susceptibility 

analysis as recommended for in A/LAI No. 7. The staff finds that the applicant has not provided 

a sufficient basis for concluding that A/LAI No. 7 is not applicable to its CLB and that a 

supporting flaw tolerance analysis, functionality analysis, or susceptibility analysis would not be 

performed and submitted for each RVI component that is made from a CASS. 

A/LAI No. 8, Item (5). By letter dated January 24, 2013, the applicant provided its response to 

RAI B2.1.6-4a proposing to address A/LAI No. 8, Item (5) in a future submittal. The staff finds 

the applicant’s response summary to A/LAI No. 8, Item (5) insufficient because the applicant did 

not clearly identify how it would address those CUF analyses for RVI components that are 

TLAAs for the impact of reactor coolant environment on metal fatigue. According to 

RIS 2011-07, Callaway is a “Category D” plant, and the staff expects the applicant to submit an 

AMP for vessel internals that is consistent with MRP-227-A for NRC staff review and approval. 

The staff noted that adequate responses to the A/LAI are necessary for the staff to determine if 

the applicant’s AMP is consistent with GALL AMP XI.M16A and MRP-227-A. 

The staff identified the need for complete responses to these A/LAIs as OI B2.1.6-1. The staff’s 

evaluation and closure of this OI is documented in SER Section 3.0.3.1.5. OI B2.1.6-1 is 

closed.

Open Item B2.1.20-1 ASME Code Class 1 Small-Bore Socket Welds

Originally LRA Section B2.1.20 stated that there were 19 Class 1 small-bore socket welds in the 

population of ASME Code Class 1 piping less than 4-inches and greater than or equal to 1-inch 

nominal pipe size. However, during the audit the applicant stated that a recent recount, 

subsequent to the LRA submission, had indicated that there were 23 Class 1 small-bore socket 

welds within the scope of the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

Program. By letter dated July 18, 2012, the staff issued RAI B2.1.20-1, requesting that the 

applicant clarify the total population of ASME Code Class 1 socket welds within the scope of the 

AMP. In its response dated August 21, 2012, the applicant stated that there were 77 small-bore 

socket welds in the scope of the AMP. By a teleconference call held on April 11, 2013, the staff 

requested additional clarification from the applicant to explain the reasons for the large 

discrepancy between the different counting results for the number of socket welds, and whether 

any error in the process has been corrected. 

The staff identified the socket weld question as OI B2.1.20-1. By letter dated April 16, 2013, the 

applicant supplemented its response to RAI B2.1.1.20-1; however, this response did not 
INTRODUCTION AND GENERAL DISCUSSION

1-11

address the staff’s concerns. By letter dated July 12, 2013, the staff issued RAI B2.1.20-2, 

requesting that the applicant verify that the issue was entered into the applicant’s corrective 

actions program. In its response dated August 2, 2013, the applicant confirmed that the issue 

was entered in the applicant’s corrective actions program. The staff’s evaluation and closure of 

this OI is documented in SER Section 3.0.3.1.9. OI B2.1.20-1 is closed.

Open Item 4.3.4-1 Effects of the Reactor Coolant System Environment on Fatigue Life of 

Piping and Components

Callaway performed a systematic review of all wetted, reactor coolant pressure boundary 

components with a Class 1 fatigue analysis to either show that the NUREG/CR-6260 locations 

are bounding or to incorporate environmentally assisted fatigue (EAF) into the licensing basis 

for those more limiting components. As described in SER Section 4.3.4.2, the staff has 

concerns on the approach taken by the applicant to address the effects of the reactor coolant 

system environment on fatigue life of piping and components. 

The applicant performed a systematic review to determine the “sentinel” locations to be 

monitored by the Fatigue Monitoring Program for EAF. This systematic review involved ranking 

and comparisons of environmental fatigue usage. However, in justifying its systematic review, 

the applicant did not demonstrate that the values for environmental fatigue usage were based 

on a normalized scale; thus, the resulting ranking and comparisons may not have appropriately 

determined the “sentinel” locations. The applicant also provided examples of screening 

methods used to identify “sentinel” locations to be monitored by the Fatigue Monitoring Program 

for EAF. However, in justifying the screening methods with the plant-specific examples, the 

applicant did not demonstrate that the implementation of these screening methods were 

appropriate for Callaway. The staff’s questions regarding EAF were identified as OI 4.3.2-1. 

The staff’s evaluation and closure of this OI is documented in SER Section 4.3.4. OI 4.3.4-1 is 

closed.

1.6 Summary of Confirmatory Items 

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

June 20, 2014, the staff determines that no confirmatory items exist which would require a 

formal response from the applicant.

1.7 Summary of Proposed License Conditions 

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

the applicant, the staff identified the following proposed license conditions:

License Condition No. 1: The first license condition requires the applicant to include the 

FSAR supplement required by 10 CFR 54.21(d) in the next FSAR update, required by 

10 CFR 50.71(e), following the issuance of the renewed license. The applicant may make 

changes to the programs and activities described in the FSAR supplement provided the 

applicant evaluates such changes in accordance with the criteria set forth in 10 CFR 50.59 and 

otherwise complies with the requirements in that section.

License Condition No. 2: The second license condition will state that the applicant’s FSAR 

supplement describes certain programs to be implemented and activities to be completed 

before the period of extended operation. The second license condition will also state that:
INTRODUCTION AND GENERAL DISCUSSION

1-12

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

programs no later than 6 months before the period of extended operation

(b) The applicant shall complete those inspection and testing activities before the end of the 

last refueling outage before the period of extended operation or 6 months before the 

period of extended operation, whichever occurs later

The second license condition will further state that the applicant shall notify the NRC in 

writing within 30 days after having accomplished item (a) above and include the status of 

those activities that have been or remain to be completed in item (b) above.

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

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

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

oversight process before the plant enters the period of extended operation. 

LRA Section A4, Table A4-1, “License Renewal Commitments,” contains commitments for 

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

complete the commitments. The staff noted that through the commitments in LRA Section A4, 

Table A4-1, the applicant will implement new programs, implement enhancements to existing 

programs, and will also complete inspection or testing activities. The staff noted that the 

applicant’s implementation schedule for some commitments, as provided originally in LRA 

Section A4, Table A4-1, may conflict with the implementation schedule intended by the generic 

second license condition described above. Therefore, by letter dated February 21, 2013, the 

staff issued RAI A4-1, Part (1), requesting the applicant to identify those commitments to 

implement new programs and enhancements to existing programs and state when the 

implementation of these programs will be completed. In addition, RAI A4-1, Part (2), requested 

the applicant to identify those commitments to complete inspection or testing activities and state 

when the completion of these inspection and testing activities will occur. 

By letter dated February 28, 2013, the applicant provided its response to RAI A4-1. In response 

to RAI A4-1, Part (1), the applicant stated that it will complete implementation of new programs 

and enhancements to existing programs no later than 6 months before the period of extended 

operation. As part of its response, the applicant provided LRA Amendment 22 which revised 

LRA Appendix A.0, “Introduction,” and the implementation schedule in LRA Table A4-1 for those 

commitments that implement new programs or enhance existing programs to state that these 

commitments will be completed no later than 6 months before the period of extended operation. 

In response to RAI A4-1, Part (2), the applicant stated it will complete inspection and testing 

activities either 6 months before the period of extended operation or by the end of the last 

refueling outage before the period of extended operation, whichever occurs later. As part of its 

response, the applicant provided LRA Amendment 22, which revised LRA Appendix A.0, 

“Introduction,” and the implementation schedule in LRA Table A4-1 for those commitments with 

inspection and testing activities to state that the inspection and testing activities related to these 

commitments will be completed 6 months before the period of extended operation or by the end 

of the last refueling outage before the period of extended operation, whichever occurs later. In 

addition, the applicant revised LRA Appendix A.0 to state that it shall notify the NRC in writing 

within 30 days after having accomplished item (a) of the proposed second license condition and 

will also include the status of those activities that have been or remain to be completed in 

item (b) of the proposed second license condition. 
INTRODUCTION AND GENERAL DISCUSSION

1-13

The staff finds the applicant response to RAI A4-1, Parts (1) and (2), acceptable because: 

(1) the staff reviewed the applicant’s response and LRA Amendment 22 revision of LRA 

Appendix A, “Final Safety Analysis Report,” and LRA Table A4-1 and confirmed that the 

applicant identified those commitments that implement new programs and enhancements to 

existing programs and stated that these commitments will be implemented no later than 

6 months before the period of extended operation, which is consistent with the proposed second 

license condition; and (2) the staff also confirmed that as part of its response, in LRA 

Amendment 22, the applicant identified those commitments to complete inspection or testing 

activities and stated, consistent with the proposed second license condition, that these 

commitments will be implemented 6 months before the period of extended operation or by the 

end of the last refueling outage before the period of extended operation, whichever occurs later. 

Therefore, the staff’s concerns described in RAI A4-1, Parts (1) and (2), are resolved.

License Condition No. 3: The third license condition will contain language requiring 

implementation of Commitment Nos. 41 and 42, which the applicant proposed in resolution to 

the stuck reactor vessel closure studs open item, OI B2.1.3-1. The license condition will 

address the following requirements:

• In order to ensure that the threads for RPV stud hole No.18 can perform their intended 

function throughout the period of extended operation, the license condition will require 

the applicant to remove stuck stud No. 18 prior to entering the period of extended 

operation. 

• In order to ensure that the RPV stud holes with damaged threads can continue to 

perform their intended function throughout the period of extended operation, the license 

condition will require the applicant to perform a laser inspection for the threads of stud 

hole location Nos. 2, 4, 5, 7, 9, and 53. If inspection of these RPV stud holes reveals

that there is additional degradation in any of these stud holes, the condition will be 

entered in the Corrective Action Program for evaluation and corrective action; in 

addition, the applicant shall inspect the remaining repaired RPV stud hole locations 

(Nos. 13, 25, 39 and 54). 

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 the applicant to identify the systems, structures, and 

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

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

(IPA) that identifies and lists those structures and components (SCs) contained in the SSCs 

identified to be within the scope of license renewal that are subject to an aging management 

review (AMR).

2.1.2 Summary of Technical Information in the Application 

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

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

technical information required by 10 CFR 54.21(a).

LRA Section 2.1, “Scoping and Screening Methodology,” describes the methodology that Union 

Electric Company, doing business as Ameren Missouri (the applicant), used to identify the 

SSCs at the Callaway Plant, Unit 1 (Callaway) within the scope of license renewal (scoping) and 

the SCs subject to an AMR (screening).

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

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

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

Plants” (the Rule)

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

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

(NEI 95-10)

2.1.3 Scoping and Screening Program Review 

The United States (US) Nuclear Regulatory Commission (NRC) (the staff) evaluated the 

applicant’s scoping and screening methodology in accordance with the guidance contained in 

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

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

following regulations provide the basis for the acceptance criteria used by the staff to assess the

adequacy of the scoping and screening methodology that the applicant used to develop 

the LRA:
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-2

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

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

the scope of the Rule

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

subject to an AMR

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

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

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

requirements of 10 CFR 54.21(a).

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

facility located in Callaway County, Missouri, during the week of April 16–19, 2012. The audit 

focused on ensuring that the applicant had developed and implemented adequate guidance to 

conduct the scoping and screening of SSCs, in accordance with the methodology described in 

the LRA and the requirements of the Rule. The staff reviewed the project-level guidelines, 

topical reports, and implementing procedures that described the applicant’s scoping and 

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

implementation and control of the license renewal, the quality practices the applicant used 

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

development. On a sampling basis, the staff performed a review of scoping and screening 

results reports and supporting current licensing basis (CLB) information for the essential service 

water system and the turbine building. In addition, the staff performed walkdowns of selected 

portions of the essential service water system, essential service water pump house, emergency 

diesel generator (EDG) building, the turbine building, and the ultimate heat sink (UHS) basin, as 

part of the sampling review of the implementation of the applicant’s 10 CFR 54.4(a)(2) scoping 

methodology.

2.1.3.1 Implementation Procedures and Documentation Sources for Scoping and 

Screening 

2.1.3.1.1 Summary of Technical Information in the Application 

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

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

Sections 2 and 2.1. Additionally, the applicant’s implementing procedures provided guidance on 

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

10 CFR 54.4 and 10 CFR 54.21.

LRA Section 2.1 listed the following information sources for the license renewal scoping and 

screening process:

• CLB documents

• Callaway equipment database

• Q-List

• engineering drawings
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-3

• topical reports

• site walkdown

2.1.3.1.2 Staff Evaluation

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

and screening methodology implementing procedures, including license renewal guidelines, 

documents and reports, as documented in the staff’s audit report, to ensure the guidance is 

consistent with the requirements of the Rule, the SRP-LR, and Regulatory Guide (RG) 1.188, 

“Standard Format and Content for Applications to Renew Nuclear Plant Operating Licenses,” 

which endorses the use of NEI 95-10. The staff determined 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 the endorsed industry guidance.

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

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

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

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

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

information in the applicant’s responses dated August 9, 2012, to the staff’s requests for 

additional information (RAIs) 2.1-1, 2.1-2, 2.1-3, and 2.1-4, issued by letter dated July 9, 2012. 

SER Section 2.1.4.1.2 provides the staff’s evaluation of the applicant’s responses to RAIs 2.1-1, 

2.1-2, and 2.1-3. SER Section 2.1.4.2.2 provides the staff’s evaluation of the applicant 

response to RAI 2.1-4. After reviewing the LRA and supporting documentation, the staff 

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

methodology description provided in LRA Section 2.1. The staff also determined that the 

methodology is sufficiently detailed in the implementing procedures to provide concise guidance 

on the scoping and screening process to be followed during the LRA activities. 

Sources of Current Licensing Basis Information. Part 54.21(a)(3) of 10 CFR requires, for each 

structure and component determined to be subject to an AMR, demonstration that the effects of 

aging will be adequately managed so that the intended functions will be maintained consistent 

with the CLB for the period of extended operation. Part 54.3(a) of 10 CFR defines the CLB, in 

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

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

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

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

and design-basis information [documented in the most recent final safety analysis report 

(FSAR). The CLB also includes licensee commitments remaining in effect that were made in 

docketed licensing correspondence, such as licensee responses to NRC bulletins, generic 

letters, and enforcement actions, and licensee commitments documented in NRC safety 

evaluations or licensee event reports. The staff considered the scope and depth of the 

applicant's CLB review to verify that the methodology is sufficiently comprehensive to identify 

SSCs within the scope of license renewal and as SCs requiring an AMR.

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

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

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

applicant including the FSAR, CLB documents, equipment database, Q-List, engineering 

drawings, and topical reports.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-4

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

database, Q-List, and the other information sources used to verify system information. These 

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

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

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

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

data; therefore, the information sources the applicant used during the scoping and screening 

process provided a controlled source of system and component data to support scoping and 

screening evaluations.

In addition, the staff reviewed the implementing procedures and results reports used to support 

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

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

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

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

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

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

2.1.3.1.3 Conclusion 

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

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

use of implementing procedures and consideration of document sources, including CLB 

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

acceptable.

2.1.3.2 Quality Controls Applied to License Renewal Application Development 

2.1.3.2.1 Staff Evaluation 

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

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

used the following quality control processes during the LRA development:

• scoping and screening activities using approved documents and implementing 

procedures

• procedurally controlled databases to guide and support scoping and screening and 

to generate license renewal documents 

• processes and procedures that incorporate preparation, review, comment, and owner 

acceptance

• incorporation of industry lessons learned

• inclusion of independent review by industry senior consultants, industry peer review, and 

review by the Onsite Review Committee in the LRA preparation process

The staff performed a review of implementing procedures and guides, examined the applicant’s 

documentation of activities in reports, reviewed the applicant’s activities performed to assess 

the quality of the LRA, and held discussions with the applicant’s license renewal management 

and staff. The staff determined that the applicant’s activities provide assurance that the LRA 

was developed consistent with the applicant’s license renewal program requirements.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-5

2.1.3.2.2 Conclusion 

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

applicant’s license renewal staff, and review of the applicant’s documentation of the activities 

performed to assess the quality of the LRA, the staff concludes that the applicant’s quality 

assurance activities are adequate to ensure that LRA development activities were performed in 

accordance with the applicant’s license renewal program requirements.

2.1.3.3 Training

2.1.3.3.1 Staff Evaluation

The staff reviewed the training process used by the applicant for license renewal project 

personnel to confirm that it was appropriate for the activity. As outlined in the implementing 

procedures, the applicant had required training for personnel participating in the development of 

the LRA and used trained and qualified personnel to prepare the scoping and screening 

implementing procedures.

License renewal project personnel had been trained using applicant-approved license renewal 

project procedures and other relevant license renewal information, as appropriate to their 

functions. Training topics had included 10 CFR Part 54, relevant NRC and industry guidance 

documents, lessons learned from other nuclear power plant license renewals, and applicable 

implementing procedures.

The staff discussed training activities with the applicant’s management and license renewal 

project personnel and performed a sampling review of applicable documentation. The staff 

determined that the applicant had developed and implemented adequate controls for the 

training of personnel performing LRA activities.

2.1.3.3.2 Conclusion

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

scoping and screening process and its review of selected documentation in support of the 

process, the staff concludes that the applicant developed and implemented adequate 

procedures to train personnel to implement the scoping and screening methodology described 

in the applicant’s implementing procedures and the LRA.

2.1.3.4 Conclusion of Scoping and Screening Program Review

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

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

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

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

methodology audit, the staff concludes that the applicant’s scoping and screening program is 

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

acceptable.

2.1.4 Plant Systems, Structures, and Components Scoping Methodology

LRA Section 2.1, “Scoping and Screening Methodology” describes the applicant’s methodology 

used to identify SSCs within the scope of license renewal in accordance with the requirements 

of the 10 CFR 54.4(a) criteria. The LRA states that the scoping process identified the SSCs that 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-6

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

basis event (DBE), are nonsafety-related whose failure could prevent accomplishment of a 

safety-related function, or perform a function that demonstrates compliance with the NRC’s

regulations for fire protection (10 CFR 50.48), environmental qualification (EQ) (10 CFR 50.49),

pressurized thermal shock (PTS) (10 CFR 50.61), anticipated transients without scram (ATWS)

(10 CFR 50.62), or station blackout (SBO) (10 CFR 50.63).

LRA Section 2.1.1, “Introduction,” states that the scoping methodology that the applicant used is 

consistent with 10 CFR Part 54 and with the industry guidance contained in NEI 95-10.

2.1.4.1 Application of the Scoping Criteria in Title 10 Part 54.4(a)(1) of the Code of 

Federal Regulations

2.1.4.1.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(1) in LRA Section 2.1.2.1, 

“10 CFR 54.4(a)(1)–Safety-related,” which states that “Callaway plant-specific definitions of 

safety-related are provided in the FSAR Section 1.1.7 Standard Plant (SP) and the Maintenance 

Rule Program. These definitions are consistent with the definition of safety-related provided in 

10 CFR 54.4(a)(1).”

2.1.4.1.2 Staff Evaluation 

In accordance with 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 (RCPB), (2) the ability to shut down 

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

mitigate the consequences of accidents that could result in potential offsite exposures 

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

as applicable.

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

The set of design basis events as defined in the rule is not limited to Chapter 15 

(or equivalent) of the [FSAR]. Examples of design basis events that may not be 

described in this chapter include external events, such as floods, storms, 

earthquakes, tornadoes, or hurricanes, and internal events, such as a high 

energy line break. Information regarding design basis events as defined in 

10 CFR 50.49(b)(1) may be found in any chapter of the facility [FSAR], the 

Commission's regulations, NRC orders, exemptions, or license conditions within 

the CLB. These sources should also be reviewed to identify [SSCs] that are 

relied upon to remain functional during and following design basis events (as 

defined in 10 CFR 50.49(b)(1)) to ensure the functions described in 

10 CFR 54.4(a)(1).

During the audit, the applicant stated that it evaluated the types of events listed in NEI 95-10 

(anticipated operational occurrences, design-basis accidents, external events, and natural 

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

documents that described design-basis conditions in the CLB and addressed events defined by 

10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The Callaway FSAR and basis documents 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-7

discussed events such as internal and external flooding, tornadoes, and missiles. The staff 

concludes that the applicant’s evaluation of DBEs was consistent with the SRP-LR.

The staff determined that the applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) 

criterion in accordance with the license renewal implementing procedures, which provide 

guidance for the preparation, review, verification, and approval of the scoping evaluations to 

ensure the adequacy of the results of the scoping process. The staff reviewed the implementing 

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

applicant’s reports of the scoping results to ensure that the applicant applied the methodology in 

accordance with the implementing procedures. In addition, the staff discussed the methodology 

and results with the applicant's personnel who were responsible for these evaluations.

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

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

definition of safety-related specified in the Rule. The staff reviewed a sample of the license 

renewal scoping results for the essential 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 had identified and used pertinent engineering and licensing information to identify the 

SSCs required to be within the scope of license renewal in accordance with the 

10 CFR 54.4(a)(1) criteria.

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

Therefore, by letter dated July 9, 2012, the staff issued RAI 2.1-1 which states, in part: 

During the on-site scoping and screening methodology audit, the staff 

determined that the applicant had used a plant equipment database, the 

Callaway Equipment List (CEL),[...] [which] contains a quality field “Q” used to 

identify safety-related SSCs included within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(1). However, during the audit the staff 

determined that not all components identified as “Q” were included within the 

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

The staff requested the applicant to perform a review of this issue and provide a 

description of the process used to evaluate components identified as Q in the database 

and the basis for not including components identified as Q within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(1).

In its response letter, dated August 9, 2012, the applicant stated, in part: 

During the scoping process, all components were considered to be safety-related 

if they had a Y flag in the Q-QUAL field of the CEL. After review of plant basis 

documents, if a component with a Y flag in the CEL Q-QUAL field appeared not 

to have a safety-related function, an additional review was conducted. If there 

was a basis in plant documentation such as the CLB or an engineering 

evaluation that the component does not have a safety-related function, then the 

component was not included within the scope of license renewal based on the 

criteria of 10 CFR 54.4(a)(1). For cases where a component has a Y flag in the 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-8

Q-QUAL field but was determined not to have a safety-related function, a 

corrective action document was initiated. 

Since it is assumed during the initial scoping and screening that a component 

with a Y flag in the Q-QUAL field of the CEL has a safety-related function, all 

components with a Y flag were reviewed. Thus, this methodology did not 

preclude the identification of safety-related SSCs that should have been included 

within the scope of license renewal. 

Based on its review, the staff finds the applicant’s response to RAI 2.1-1 acceptable because

the applicant evaluated all components identified as Q in the CEL to determine if the 

components had a safety-related function and included those that did within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(1). The staff’s concern described in RAI 2.1-1 is 

resolved.

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

staff noted that LRA Section 2.4-4 does not indicate that the turbine building contains 

safety-related SSCs. However, the applicable license renewal drawings indicated that 

safety-related portions of the main steam supply system, main feedwater system, and steam 

generator blowdown system are located within the turbine building. The staff noted that the 

applicant had performed an evaluation and concluded that the safety-related portions of the 

systems located within the turbine building were not included within the scope of license 

renewal, in accordance with 10 CFR 54.4(a)(1). Therefore, by letter dated July 9, 2012, the 

staff issued RAI 2.1-2 requesting that the applicant provide the basis for any determination to 

not include safety-related SSCs within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). 

In its response dated August 9, 2012, the applicant stated that during the scoping process, all 

components were considered to be safety-related if they had a Y flag in the Q-QUAL field of the 

CEL. The applicant stated that 12 piping segments contained in the main steam supply system, 

main feedwater system, and steam generator blowdown system in the turbine building had 

Y flags. The applicant also stated that these piping segments extended from the auxiliary 

building through the auxiliary building-turbine building wall and into the turbine building. The 

applicant further stated that from a review of FSAR Section 3.6.2.1.1e, “High-Energy Piping in 

Containment Penetration Areas,” and engineering evaluations, it was determined that the 

sections of the piping extending into the turbine building do not have a safety-related function. 

In addition, the applicant stated that the boundary drawings for the main steam supply system, 

steam generator blowdown system, and main feedwater system have been revised to indicate 

that the safety-related portion of these lines ends at the auxiliary building-turbine building wall.

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

portions of the systems located in the turbine building that were flagged as Q in the CEL. The 

applicant had reviewed applicable information contained in the FSAR and engineering 

evaluations and determined that the portions of main steam supply system, main feedwater 

system, and steam generator blowdown system in the turbine building did not have a 

safety-related function, and that the safety-related to nonsafety-related interface for each 

system was located in the wall joining the safety-related auxiliary building and the 

nonsafety-related turbine building. The applicant further concluded that the portions of the main 

steam supply, main feedwater, and steam generator blowdown systems located in the turbine 

building were not included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). Furthermore, the applicant‘s response did not address whether the portion 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-9

of nonsafety-related pipe attached to the safety-related pipe at the safety-related to 

nonsafety-related interface located in the turbine building wall was included within the scope of 

license renewal to the first anchor, equivalent anchor, or bounding condition, past the 

safety-related to nonsafety-related interface, in accordance with 10 CFR 54.4(a)(2) and the 

process described in LRA Section 2.1.2.2, which indicates that the applicant followed the 

guidance of NEI 95-10.

On December 6, 2012, the staff held a conference call with the applicant to discuss the inclusion 

of nonsafety-related pipe attached to the safety-related pipe within the scope of license renewal. 

During the telephone conference call, the applicant agreed to provide additional information to 

address the unresolved staff concerns described in RAI 2.1-2 and RAI 2.3.4.2-1a. By letter 

dated January 10, 2013, the applicant supplemented its response to RAI 2.1-2 and also 

provided a response to RAI 2.3.4.2-1a. The staff’s evaluation of RAI 2.3.4.2-1a is documented 

in SER Section 2.3.4.2. 

In its supplemental response to RAI 2.1-2, the applicant stated that, as discussed in its FSAR, 

the piping for the main steam supply and main feedwater systems are located in “no break 

zones,” which extend from the anchors in the reactor building wall to outside the torsional 

restraints in the auxiliary building-turbine building wall. The applicant stated that it did not 

include the nonsafety-related piping, which is attached to the safety-related piping for the main 

steam supply and main feedwater systems and located in the turbine building, within the scope 

of license renewal. The applicant also stated that the basis for not including the 

nonsafety-related pipe within the scope of license renewal was the result of an analysis of a 

postulated failure of the nonsafety-related piping beyond the “no break zones,” as documented 

in the FSAR, which concludes that a failure of the nonsafety-related piping beyond the torsional 

restraints in the “no break zone” will not prevent the connected safety-related components from 

performing their intended function. The applicant further stated that it has taken an exception to

NEI 95-10, Appendix F, and did not include a portion of the nonsafety-related piping attached to 

the safety-related piping of the main steam supply and main feedwater systems, beyond the 

torsional restraints in the “no break zone” and located in the turbine building, within the scope of 

license renewal. The applicant also revised the license renewal boundary drawing for the steam 

generator blowdown system to identify the nonsafety-related piping, beyond the safety-related 

to nonsafety-related interface and located within the turbine building, up to and including an 

anchor, equivalent anchor, or bounding condition, in accordance with guidance contained in 

NEI 95-10, Appendix F, within the scope of license renewal in accordance with

10 CFR 54.4(a)(2).

The staff reviewed the supplemental response to RAI 2.1-2 and the response to RAI 2.3.4.2-1, 

as documented in SER Section 2.3.4.2, and determined that the applicant had performed an

evaluation and provided a basis for the main steam supply and main feedwater systems 

indicating that: (1) the safety-related to nonsafety-related interface was located in the wall 

connecting the safety-related auxiliary building and nonsafety-related turbine building and 

(2) the FSAR documented the results of an analysis that concluded a failure of the 

nonsafety-related piping attached to safety-related piping and located in the turbine building 

would not affect the intended function of the attached safety-related pipe. The staff further 

determined for the steam generator blowdown system that the applicant had included the 

nonsafety-related pipe attached to safety-related pipe and located within the turbine building up 

to and including an anchor, equivalent anchor, or bounding condition within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(2). Therefore, the staff finds the applicant response 

to RAI 2.1-2, as supplemented by letter dated January 10, 2013, acceptable. The staff’s 

concern described in RAI 2.1-2 is resolved.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-10

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

letter dated July 9, 2012, the staff issued RAI 2.1-3 which states, in part:

The staff determined that the applicant had identified safety-related electrical 

SSCs, located within the turbine building, that were not included within the scope 

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

The staff requests that the applicant describe the process used to identify and 

evaluate the safety-related electrical SSCs, located within the turbine building, 

and the basis to not include the SSCs within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(1).

In its response letter, dated August 9, 2012, the applicant stated, in part: 

During the scoping process, all components were considered to be safety-related 

if they had a Y flag in the Q-QUAL field of the CEL. Several electrical 

components (along with the associated cabling) in the turbine building had Y in 

the Q-QUAL field....

From a review of the FSAR and engineering evaluations, it was determined that 

these components do not have a safety-related function. The components were 

therefore not included within the scope of license renewal based on the criteria of 

10 CFR 54.4(a)(1)....

Based on its review the staff finds the applicant’s response to RAI 2.1-3 acceptable because: 

(1) the applicant had evaluated the electrical components located in the turbine building and 

identified as Q in the CEL, to determine if the components had a safety-related function, and 

(2) the applicant had identified 26 electrical components in the turbine building that were flagged 

as Q in the CEL, reviewed applicable information contained in the FSAR and engineering 

evaluations, and concluded that the components did not have a safety-related function and, 

therefore, were not included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). The staff’s concern described in RAI 2.1-3 is resolved.

2.1.4.1.3 Conclusion 

On the basis of its review of the LRA and the applicant’s implementing procedures and reports, 

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

information provided in the responses to RAIs 2.1-1, 2.1-2, and 2.1-3 the staff concludes that 

the applicant's methodology for identifying safety-related SSCs, relied upon to remain functional 

during and following DBEs and including the SSCs within the scope of license renewal, is 

consistent with the SRP-LR and 10 CFR 54.4(a)(1), and is therefore acceptable.

2.1.4.2 Application of the Scoping Criteria in Title 10, Part 54.4(a)(2) of the Code of 

Federal Regulations

2.1.4.2.1 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(2). 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-11

LRA Section 2.1.2.2, “10 CFR 54.4(a)(2)–Nonsafety-Related Affecting Safety-Related,” states, 

in part:

Nonsafety-Related SSCs Performing Safety-Related 10 CFR 54.4(a)(1) 

Functions. The FSAR and other current licensing basis documents were 

reviewed for nonsafety-related plant systems or structures, to determine whether 

nonsafety-related systems or structures were credited with performing a 

safety-related function. Callaway does not have nonsafety-related systems or 

structures credited in CLB documents that perform a safety-related function.

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. 

Nonsafety-related SSCs that are directly connected to safety-related SSCs were 

included within the scope of license renewal to ensure structural integrity of the 

safety-related SSCs up to the first seismic anchor or equivalent anchor past the 

safety/nonsafety interface.

Nonsafety-Related SSCs Not Directly Connected to Safety-Related SSCs. 

In accordance with NEI 95-10, Appendix F, Callaway applied the preventive 

option for 10 CFR 54.4(a)(2) scoping. The preventive option is based on scoping 

nonsafety-related SSCs not directly connected to safety-related SSCs within the

scope of license renewal, which could lead to an interaction with safety-related 

SSCs. Mechanical nonsafety-related interactions with safety-related SSCs 

include high, moderate, and low energy fluid/steam spatial interaction and 

potential flooding of safety-related SSCs. Jet impingement, pipe whip, flood 

barriers, curbing, and pipe supports to prevent falling pipe are structural SSCs 

and are managed in the structural area.

2.1.4.2.2 Staff Evaluation 

RG 1.188, Revision 1, endorses the use of NEI 95-10, Revision 6, which discusses the 

implementation of the staff’s position on 10 CFR 54.4(a)(2) scoping criteria, to include 

nonsafety-related SSCs that may have the potential to prevent satisfactory accomplishments of 

safety-related intended functions. This includes nonsafety-related SSCs connected to 

safety-related SSCs, nonsafety-related SSCs in proximity to safety-related SSCs, and mitigative 

and preventative options related to nonsafety-related and safety-related SSCs interactions. 

LRA Section 2.1.2.2 states that the applicant’s methodology is consistent with the guidance 

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

In addition, the staff’s position (as discussed in SRP-LR Section 2.1.3.1.2) is that the applicant 

should not consider hypothetical failures, but rather should base its evaluation on the plant’s 

CLB, engineering judgment and analyses, and relevant operating experience. NEI 95-10 further 

describes operating experience as all documented plant-specific and industry-wide experience 

that can be used to determine the plausibility of a failure. Documentation would include NRC 

generic communications and event reports, plant-specific condition reports, industry reports 

such as safety operational event reports, and engineering evaluations. The staff reviewed LRA 

Section 2.1.2.2, in which the applicant described the scoping methodology for nonsafety-related 

SSCs in accordance with 10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant’s 

implementing procedure and results report, which documented the guidance and corresponding 

results of the applicant’s scoping review in accordance with 10 CFR 54.4(a)(2).

Nonsafety-Related SSCs Required to Perform a Function that Supports a Safety-Related SSC. 

The staff reviewed LRA Section 2.1.2.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-12

procedure that described the method used to identify nonsafety-related SSCs, required to 

perform a function that supports a safety-related SSC intended function, within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2). The staff confirmed that the applicant 

had reviewed the FSAR, plant drawings, the equipment database, and other CLB documents to 

identify the nonsafety-related systems and structures that function to support a safety-related 

system whose failure could prevent the performance of a safety-related intended function. The 

staff determined that the applicant had not identified any nonsafety-related SSCs that performed 

a safety function or supported a safety system that would require the nonsafety-related SSCs to 

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

The staff determined that the applicant’s methodology for identifying nonsafety-related systems

that perform functions that support safety-related intended functions, for inclusion within the 

scope of license renewal, was in accordance with the guidance of the SRP-LR and the 

requirements of 10 CFR 54.4(a)(2).

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The staff reviewed LRA 

Section 2.1.2.2 and the applicant’s 10 CFR 54.4(a)(2) implementing procedure that described 

the method used to identify nonsafety-related SSCs, directly connected to safety-related SSCs, 

within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant had 

reviewed the safety-related to nonsafety-related interfaces for each mechanical system to 

identify the nonsafety-related components located between the safety to nonsafety-related 

interface and license renewal structural boundary.

The staff determined that the applicant had used a combination of the following to identify the 

portion of nonsafety-related piping systems to include within the scope of license renewal:

• seismic anchors

• equivalent anchors

• bounding conditions described in NEI 95-10, Revision 6, Appendix F (base-mounted 

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

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

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

By letter dated July 9, 2012, the staff issued RAI 2.1-4, which states, in part:

The staff determined that LRA Section 2.1.2.2, “10 CFR 54.4(a)(2)–

Nonsafety-Related Affecting Safety-Related,” states that for nonsafety-related 

SSCs directly connected to safety-related SSCs, “equivalent anchors as defined 

in the Current Licensing Basis (CLB),” were not used because equivalent 

anchors are not defined in the Callaway CLB. However, during a review of the 

license renewal drawings, the staff noted examples where the drawing notes 

credited “equivalent anchors as defined in the CLB” as the termination point for 

attached piping included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2). 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-13

The staff requests that the applicant discuss the use of equivalent anchors 

supporting nonsafety-related SSCs, connected to safety-related SSCs, included 

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

In its response letter, dated August 9, 2012, the applicant stated, in part:

Credit was taken in license renewal for equivalent anchors as defined in the CLB 

at the locations where the main steam piping passes through the auxiliary 

building-turbine building wall.

For this piping, the Callaway FSAR defines the portion of piping extending from 

the outside of the inboard isolation restraint to the outside of the outboard 

isolation restraint as a “no break zone.” The inboard isolation restraint for a main 

steam line is the anchor at the containment penetration. The outboard isolation 

restraint is at the penetration in the auxiliary building-turbine building wall. The 

FSAR states that the maximum stress in the “no break zone” is acceptable when 

subjected to the combined loadings of internal pressure, deadweight, and 

postulated pipe break beyond the “no break zone.” 

The FSAR further states that isolation restraints protect an essential portion of a 

piping system from postulated leaks either upstream or downstream of the 

protected area. These restraints limit pipe motion in all directions.

Thus, the isolation restraints in the auxiliary building-turbine building wall for the 

main steam piping are equivalent anchors as defined in the CLB.

LRA Section 2.1.2.2 has been revised to delete the statement that equivalent 

anchors are not defined in the Callaway CLB.

Based on its review the staff finds the applicant’s response to RAI 2.1-4 acceptable because: 

(1) the applicant had provided information indicating that the FSAR did provide a definition of an 

equivalent anchor and that the applicant had taken credit for the use of an equivalent anchor, as 

defined in the FSAR, in one application, and (2) the applicant had revised the LRA to remove 

the statement that an equivalent anchor is not defined in the CLB and had not been used in 

identifying the boundaries of nonsafety-related pipe within the scope of license renewal. 

The staff’s concern described in RAI 2.1-4 is resolved.

The staff determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs, directly connected to safety-related SSCs, within the scope of license 

renewal, was in accordance with the guidance of the SRP-LR and the requirements of 

10 CFR 54.4(a)(2).

Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. 

The staff reviewed LRA Section 2.1.2.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

procedure that described the method used to identify nonsafety-related SSCs, with the potential 

for spatial interaction with safety-related SSCs, within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2). The staff determined that the applicant had used a spaces 

approach to identify the portions of nonsafety-related systems with the potential for spatial 

interaction with safety-related SSCs. The spaces approach focused on the interaction between 

nonsafety-related and safety-related SSCs that are located in the same space, which was 

described in the LRA as a structure containing active or passive safety-related SSCs.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-14

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

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

nonsafety-related SSCs within the scope of license renewal, unless it had been evaluated by 

the applicant and determined that the failure of the nonsafety-related SC would not result in the 

loss of a 10 CFR 54.4(a)(1) intended function. The staff also determined that, based on plant 

and industry operating experience, the applicant excluded the nonsafety-related SSCs 

containing air or gas from the scope of license renewal, with the exception of portions that are 

attached to safety-related SSCs and required for structural support. 

The staff determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs, with the potential for spatial interaction with safety-related SSCs, within 

the scope of license renewal, was in accordance with the guidance of the SRP-LR and the 

requirements of 10 CFR 54.4(a)(2).

2.1.4.2.3 Conclusion

On the basis of its LRA review and the applicant’s implementing procedures and reports, 

selected system reviews and walkdowns, discussions with the applicant, and review of the 

information provided in the response to RAI 2.1-4, the staff concludes that the applicant’s 

methodology for identifying and including nonsafety-related SSCs, whose failure could prevent 

satisfactory accomplishment of the intended functions of safety-related SSCs, within the scope 

of license renewal, is in accordance with the requirements 10 CFR 54.4(a)(2), and, therefore, is 

acceptable.

2.1.4.3 Application of the Scoping Criteria in Title 10, Part 54.4(a)(3) of the Code of

Federal Regulations 

2.1.4.3.1 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(3).

LRA Section 2.1.2.3, “10 CFR 54.4(a)(3)–Regulated Events,” states:

10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license renewal 

include all SSCs relied on in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the regulations for fire protection 

(10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized thermal 

shock (10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and 

station blackout (10 CFR 50.63).

LRA Section 2.1.2.3 also states that “SSCs credited in the regulated events have been 

classified as satisfying criterion 10 CFR 54.4(a)(3) and have been identified as within the scope 

of license renewal.”

2.1.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.1.2.3, which described the method used to identify, and 

include within the scope of license renewal, those SSCs relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the NRC’s regulations for 

fire protection (10 CFR 50.48), EQ (10 CFR 50.49), PTS (10 CFR 50.61), ATWS

(10 CFR 50.62), and SBO (10 CFR 50.60). As part of this review, during the scoping and 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-15

screening methodology audit the staff had discussions with the applicant, reviewed 

implementing procedure and the technical basis documents (topical reports), license renewal 

drawings, and scoping results reports. The staff determined that the applicant had evaluated 

the CLB to identify SSCs that perform functions addressed in 10 CFR 54.4(a)(3) and included 

these SSCs within the scope of license renewal, as documented in the scoping reports. In 

addition, the staff determined that the scoping report results referenced the information sources 

used for determining the SSCs credited for compliance with the events.

Fire Protection. The staff reviewed the applicant’s implementing procedure and topical report 

that described the method used to identify SSCs within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(3) (fire protection–10 CFR 50.48). The implementing 

procedure described a process that considered CLB information, including the FSAR and the 

fire protection technical basis document. The staff reviewed applicable portions of the LRA, 

CLB information, and license renewal drawings to verify the appropriate SSCs were included 

within the scope of license renewal. In addition, the staff reviewed a selected sample of scoping 

reports for the systems and structures identified in the fire protection topical report. Based on its 

review of the CLB documents and the sample report review, the staff determined that the 

applicant’s methodology was adequate for identifying and including SSCs credited in performing 

fire protection functions within the scope of license renewal in accordance with the requirements 

of 10 CFR 54.4(a)(3).

Environmental Qualification. The staff reviewed the applicant’s implementing procedure and 

topical report that described the method used to identify SSCs within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(3) (EQ–10 CFR 50.49). The implementing 

procedure described a process that considered CLB information, including the FSAR and the 

EQ technical basis document. The staff reviewed applicable portions of the LRA, CLB 

information, Callaway EQ program documentation, and license renewal drawings to verify the 

appropriate SSCs were included within the scope of license renewal. In addition, the staff 

reviewed a selected sample of scoping reports for the systems and structures identified in the 

EQ technical basis document. Based on its review of the CLB documents and the sample 

report review, the staff determined that the applicant’s methodology was adequate for identifying 

and including SSCs credited in performing EQ functions within the scope of license renewal in 

accordance with the requirements of 10 CFR 54.4(a)(3).

Pressurized Thermal Shock. The staff reviewed the applicant’s implementing procedure and 

topical report that described the method used to identify SSCs within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(3) (PTS–10 CFR 50.61). The topical report 

described the process to review the licensing basis for PTS at Callaway. The only component 

within the scope of license renewal for PTS is the reactor pressure vessel. The staff reviewed 

applicable portions of the LRA, CLB information, and license renewal drawings to verify the 

appropriate SSCs were included within the scope of license renewal. Based on its review of the 

CLB documents and the topical report, the staff determined that the applicant’s methodology 

was adequate for identifying and including the reactor pressure vessel in performing PTS

functions within the scope of license renewal in accordance with the requirements of 

10 CFR 54.4(a)(3).

Anticipated Transient Without Scram. The staff reviewed the applicant’s implementing 

procedure and topical report that described the method used to identify SSCs within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(3) (ATWS–10 CFR 50.62). The 

implementing procedure described a process that considered CLB information, including the 

FSAR and the ATWS technical basis document. The staff reviewed applicable portions of the 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-16

LRA, CLB information, and license renewal drawings to verify the appropriate SSCs were 

included within the scope of license renewal. In addition, the staff reviewed a selected sample 

of scoping reports for the systems and structures identified in the ATWS technical basis 

document. Based on its review of the CLB documents and the sample report review, the staff 

determined that the applicant’s methodology was adequate for identifying and including SSCs 

credited in performing ATWS functions within the scope of license renewal in accordance with 

the requirements of 10 CFR 54.4(a)(3).

Station Blackout. The staff reviewed the applicant’s implementing procedure and topical report 

that described the method used to identify SSCs within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(3) (SBO–10 CFR 50.63). The implementing procedure 

described a process that considered CLB information, including the FSAR and the SBO 

technical basis document. The staff reviewed applicable portions of the LRA, CLB information, 

applicable portions of the FSAR, and commitments and analyses that demonstrate compliance 

with 10 CFR 50.63 and license renewal drawings to verify the appropriate SSCs were included 

within the scope of license renewal. In addition, the staff reviewed a selected sample of scoping 

reports for the systems and structures identified in the SBO technical basis document. Based 

on its review of the CLB documents and the sample report review, the staff determined that the 

applicant’s methodology was adequate for identifying and including SSCs credited in performing 

SBO functions within the scope of license renewal in accordance with the requirements of 

10 CFR 54.4(a)(3).

2.1.4.3.3 Conclusion

On the basis of its LRA review and the applicant’s implementing procedures and reports, 

reviews of systems on a sampling basis, and discussions with the applicant, the staff concludes 

that the applicant’s methodology for identifying and including SSCs, relied upon to remain 

functional during regulated events is consistent with the SRP-LR and 10 CFR 54.4(a)(3) and, 

therefore, is acceptable.

2.1.4.4 Plant-Level Scoping of Systems and Structures

2.1.4.4.1 Summary of Technical Information in the Application

The applicant described the methods used to identify SSCs included within the scope of license 

renewal in accordance with the requirements of 10 CFR 54.4(a) in LRA Section 2.1.3, “Scoping 

Methodology,” which states:

Scoping of SSCs was performed to the criteria of 10 CFR 54.4(a) to identify those SSCs within 

the scope of the license renewal rule. The following sections describe the methodology used for 

scoping. Separate discussions of mechanical system scoping methodology, structures scoping 

methodology, and electrical and instrumentation and control system scoping methodology are 

provided.

2.1.4.4.2 Staff Evaluation

The staff reviewed the applicant’s methodology for identifying SSCs within the scope of license 

renewal to verify it met the requirements of 10 CFR 54.4. The applicant had developed 

implementing procedures that described the processes used to identify the systems and 

structures that are subject to 10 CFR 54.4 review and to determine if the system or structure 

performed intended functions consistent with the criteria of 10 CFR 54.4(a) and to document the 

activities in scoping results reports. The process defined the plant in terms of systems and 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-17

structures and was completed for all systems and structures on site to ensure that the entire 

plant was assessed. 

The staff determined that the applicant had identified the SSCs within the scope of license 

renewal and documented the results of the scoping process in reports in accordance with the 

implementing procedures. The reports included a description of the structure or system, a 

listing of functions performed by the system or structure, identification of intended functions, the 

10 CFR 54.4(a) scoping criteria met by the system or structure, references, and the basis for the 

classification of the system or structure intended functions. During the audit, the staff reviewed 

a sampling of the implementing documents and reports and determined that the applicant’s 

scoping results contained an appropriate level of detail to document the scoping process.

2.1.4.4.3 Conclusion

Based on its LRA review, implementing procedures, and a sampling of system scoping results 

reviewed during the audit, the staff concludes that the applicant’s methodology for identifying 

systems and structures within the scope of license renewal, and their intended functions, is 

consistent with the requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.5 Mechanical Component Scoping 

2.1.4.5.1 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify mechanical SSCs within the scope of 

license renewal in accordance with the requirements of 10 CFR 54.4(a). 

LRA Section 2.1.3.1, “Mechanical System Scoping Methodology,” states that a “list of 

mechanical systems was developed and is documented in a topical report. These mechanical 

systems were evaluated to each of the criteria of 10 CFR 54.4(a).”

LRA Section 2.1.3.1, “Determination of the License Renewal Boundary,” states, in part:

After the system functions were identified, the system boundary was determined 

and marked–up on P&IDs. The components needed for the system to perform 

its intended functions were included within the license renewal boundary. The 

system scoping summaries included in [LRA] Section 2.3, Scoping and 

Screening Results: Mechanical Systems provide a description of the license 

renewal boundary for each mechanical system in the scope of the Rule. 

The process to determine the system license renewal boundary required 

examination of interfaces with other systems. System interfaces were evaluated 

to ensure that all components were included in the boundary of one of the 

interfacing systems.

2.1.4.5.2 Staff Evaluation 

The staff evaluated LRA Sections 2.1.3 and 2.1.3.1, implementing procedures, reports, and the 

CLB source information associated with mechanical scoping. The staff determined that the CLB 

source information and the implementing procedure guidance used by the applicant were 

acceptable to identify mechanical SSCs within the scope of license renewal. The staff 

conducted detailed discussions with the applicant’s license renewal project personnel and 

reviewed documentation pertinent to the scoping process during the scoping and screening 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-18

methodology audit. The staff assessed if the applicant had appropriately applied the scoping 

methodology outlined in the LRA and implementing procedures and if 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 2.1.3 and 2.1.3.1 and the guidance 

contained in SRP-LR Section 2.1 and was adequately implemented.

On a sampling basis, the staff reviewed the applicant’s scoping reports for the essential service 

water system and the process used to identify mechanical components that met the scoping 

criteria of 10 CFR 54.4. The staff reviewed the implementing procedures, confirmed that the 

applicant had identified and used pertinent engineering and licensing information, and 

discussed the methodology and results with the applicant. As part of the review process, the 

staff evaluated the system’s identified intended functions and the process used to identify 

system component types. The staff confirmed that the applicant had identified and highlighted 

license renewal drawings to identify the license renewal boundaries in accordance with the 

implementing procedure guidance. Additionally, the staff determined that the applicant had 

independently verified the results in accordance with the implementing procedures. The staff 

confirmed that the applicant’s license renewal personnel verifying the results had performed 

independent reviews of the scoping reports and the applicable license renewal drawings to 

ensure accurate identification of the system intended functions. The staff confirmed that the 

systems and components identified by the applicant were evaluated against the criteria of 

10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff confirmed that the applicant had used pertinent 

engineering and licensing information to determine that systems and components were included 

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

2.1.4.5.3 Conclusion

On the basis of its review of information contained in the LRA, scoping implementing 

procedures, and a sampling review of scoping results, the staff concludes that the applicant’s 

methodology for identifying mechanical SSCs within the scope of license renewal is in 

accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.6 Structural Component Scoping

2.1.4.6.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal in accordance with the requirements of 10 CFR 54.4(a). LRA Section 2.1.3.2, 

“Structure Scoping Methodology,” states, in part that 

A list of structures was developed that included buildings, tank foundations, and 

other miscellaneous structures. These structures are listed in [LRA] Table 2.2-1, 

Callaway Plant Scoping Results. The FSAR was relied upon to identify the 

safety classifications of structures and structural components.

The scoping methodology used for structures was similar to the mechanical system-level 

scoping described in [LRA] Section 2.1.3.1, “Mechanical System Scoping Methodology.”

Structure descriptions were prepared, including the structure purpose and functions. Structure 

evaluation boundaries were determined, including examination of structure interfaces. Structure 

functions were evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3), and the 

results of this evaluation were documented.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-19

2.1.4.5.2 Staff Evaluation 

The staff evaluated LRA Section 2.1.3.2, implementing procedures, reports, and the CLB source 

information associated with structural scoping. The staff determined that the CLB source 

information and the implementing procedure guidance used by the applicant were acceptable to 

identify structural SSCs within the scope of license renewal. The staff conducted detailed 

discussions with the applicant’s license renewal project personnel and reviewed documentation 

pertinent to the scoping process during the scoping and screening methodology audit. The staff 

assessed if the applicant had appropriately applied the scoping methodology outlined in the 

LRA and implementing procedures and if the scoping results were consistent with CLB 

requirements. The staff determined that the applicant’s procedure was consistent with the 

description provided in the LRA Section 2.1.3.2 and the guidance contained in SRP-LR 

Section 2.1, and was adequately implemented.

On a sampling basis, the staff reviewed the applicant’s scoping reports for the turbine building, 

essential service water pump house, EDG building, and the UHS basin, and the process used to 

identify structural systems and components that met the scoping criteria of 10 CFR 54.4. 

The staff reviewed the implementing procedures, confirmed that the applicant had identified and 

used pertinent engineering and licensing information, and discussed the methodology and 

results with the applicant. As part of the review process, the staff evaluated the structures 

identified intended functions and the process used to identify structural component types. 

Additionally, the staff determined that the applicant had verified the results in accordance with 

the implementing procedures. The staff confirmed that the applicant’s license renewal

personnel verifying the results had performed independent reviews of the scoping reports and 

the applicable license renewal drawings to ensure accurate identification of the system intended 

functions. The staff confirmed that the SCs identified by the applicant were evaluated against 

the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff confirmed that the applicant had 

used pertinent engineering and licensing information to determine that systems and 

components were included within the scope of license renewal in accordance with the 

10 CFR 54.4(a).

2.1.4.6.3 Conclusion 

On the basis of its review of information contained in the LRA, scoping implementing 

procedures, and a sampling review of scoping results, the staff concludes that the applicant’s 

methodology for identifying structural SSCs within the scope of license renewal is in accordance 

with the requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.7 Electrical Component Scoping 

2.1.4.7.1 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal in accordance with the requirements of 10 CFR 54.4(a). 

LRA Section 2.1.3.3, “Electrical and Instrumentation and Control System Scoping Methodology,” 

states, in part:

At the system level, the scoping methodology utilized for electrical and 

instrumentation and control systems was similar to the mechanical system-level 

scoping described in [LRA] Section 2.1.3.1, Mechanical System Scoping 

Methodology. The FSAR descriptions, plant records, CLB documents and 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-20

design basis documents applicable to the system were reviewed to determine the 

system safety classification and to identify all of the system functions. System 

level functions were evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2) 

and (a)(3). The results of the system level scoping along with a list of references 

supporting the evaluation of each electrical and instrumentation and control 

system were documented.

LRA Section 2.1.3.3 further states that “[e]lectrical and instrumentation and control components 

that perform an intended function as described in 10 CFR 54.4 for in-scope systems were 

included within the scope of license renewal. “

2.1.4.7.2 Staff Evaluation 

The staff reviewed LRA Section 2.1.3.3, implementing procedures, reports, and the CLB source 

information associated with electrical scoping. The staff determined that the CLB source 

information and implementing procedures’ guidance used by the applicant was acceptable to 

identify electrical SSCs within the scope of license renewal. The staff conducted detailed 

discussions with the applicant’s license renewal project personnel and reviewed documentation 

pertinent to the scoping process during the scoping and screening methodology audit. The staff 

assessed if the applicant had appropriately applied the scoping methodology outlined in the 

LRA and implementing procedures and if the scoping results were consistent with CLB 

requirements. The staff determined that the applicant’s procedure was consistent with the 

description provided in LRA Section 2.1.3.3 and the guidance contained in SRP-LR Section 2.1, 

and was adequately implemented.

The staff noted that after the scoping of electrical and instrumentation and controls (I&C)

components was performed, the in-scope electrical components were categorized into electrical 

commodity groups. Commodity groups include electrical and I&C components with common 

characteristics. Component level intended functions of the component types were identified. 

The electrical commodities included insulated cable and connections, connectors, terminal 

blocks, high-voltage insulators, transmission conductor, transmission connections, metal 

enclosed bus, and switchyard bus and connections.

As part of this review, the staff discussed the methodology with the applicant, reviewed the 

implementing procedures developed to support the review, and reviewed the scoping results for 

a sample of SSCs that were identified within the scope of license renewal. The staff determined 

that the applicant’s scoping included appropriate electrical and I&C components as well as 

electrical and I&C components contained in mechanical or structural systems within the scope 

of license renewal on a commodity basis.

2.1.4.7.3 Conclusion 

On the basis of its review of information contained in the LRA, scoping implementing 

procedures, and a sampling review of scoping results, the staff concludes that the applicant’s 

methodology for identifying electrical SSCs within the scope of license renewal is in accordance 

with the requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.8 Conclusion for Scoping Methodology

On the basis of its review of information contained in the LRA, scoping implementing 

procedures, and a sampling review of scoping results, the staff concludes that the applicant's 

scoping methodology was consistent with the guidance contained in the SRP-LR and identified 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-21

those SSCs: (1) that are safety-related; (2) whose failure could affect safety-related intended 

functions; and (3) that are necessary to demonstrate compliance with the NRC’s regulations for 

fire protection, EQ, PTS, ATWS, and SBO. The staff concluded that the applicant’s 

methodology is consistent with the requirements of 10 CFR 54.4(a), and, therefore, is 

acceptable.

2.1.5 Screening Methodology

2.1.5.1 General Screening Methodology

2.1.5.1.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify SCs included within the scope of license 

renewal that are subject to AMR in accordance with the requirements of 10 CFR 54.21. LRA 

Section 2.1.4, “Screening Methodology,” states, in part:

The structures and components categorized as within the scope of license 

renewal were screened against the criteria of 10 CFR 54.21(a)(1)(i) and (1)(ii) to 

determine whether they are subject to AMR.

10 CFR 54.21 states that the structures and components subject to an AMR shall 

encompass those structures and components within the scope of the license 

renewal rule if they perform an intended function, as described in 10 CFR 54.4, 

without moving parts or without a change in configuration or properties; and are 

not subject to replacement based on a qualified life or specified time period. 

NEI 95-10, Appendix B, “Typical Structure, Component and Commodity Groupings and 

Active/Passive Determinations for the Integrated Plant Assessment,” provides industry guidance 

for screening SCs. The guidance provided in NEI 95-10, Appendix B, has been incorporated 

into the Callaway license renewal screening process. The screening methodology applied for 

each category of system and for structures is described in the following paragraphs.

2.1.5.1.2 Staff Evaluation 

In accordance with the requirements of 10 CFR 54.21, each LRA must contain an IPA that 

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

must identify components that perform an intended function without moving parts or a change in 

configuration or properties (passive), as well as components that are not subject to periodic 

replacement based on a qualified life or specified time period (long-lived). In addition, the IPA 

must include a description and justification of the methodology used to identify passive and 

long-lived SCs and a demonstration that the effects of aging on those SCs will be adequately 

managed so that the intended function(s) will be maintained under all design conditions 

imposed by the plant-specific CLB for the period of extended operation.

The staff reviewed the methodology used by the applicant to identify the mechanical, structural,

and electrical SSCs within the scope of license renewal that are subject to an AMR. The 

applicant implemented a process for determining which SCs were subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1). The staff determined that the 

screening process evaluated the component types and commodity groups, included within the 

scope of license renewal, to determine which ones were long-lived and passive and, therefore,

subject to an AMR. The staff reviewed on a sampling basis the screening results reports for the 

essential service water system and the turbine building. The applicant provided the staff with a 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-22

detailed discussion of the processes used for each discipline and provided administrative 

documentation that described the screening methodology. Specific methodology for 

mechanical, structural, and electrical SCs is discussed in safety evaluation report (SER)

Sections 2.1.5.2, 2.1.5.3, and 2.1.5.4.

2.1.5.1.3 Conclusion

On the basis of a review of the LRA, the implementing procedures, and a sampling of screening 

results, the staff concludes that the applicant’s screening methodology was consistent with the 

guidance contained in the SRP-LR and was capable of identifying passive, long-lived 

components within the scope of license renewal that are subject to an AMR. The staff 

concludes that the applicant’s process for determining the SCs that are subject to an AMR is 

consistent with the requirements of 10 CFR 54.21 and, therefore, is acceptable.

2.1.5.2 Mechanical Component Screening

2.1.5.2.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify mechanical SCs included within the 

scope of license renewal that are subject to an AMR in accordance with the requirements of 

10 CFR 54.21. LRA Section 2.1.4.1, “Mechanical System Component Screening Methodology,” 

states, in part:

After a mechanical system component was categorized as in scope, the 

classification as an active or passive component was determined based on 

evaluation of the component description and type. The active/passive 

component determinations documented in NEI 95-10, Appendix B, provided 

guidance for this activity. In-scope components that were determined to be 

passive and long-lived were documented as subject to AMR.

Each component that was identified as subject to an AMR was evaluated to 

determine its component intended function(s). The component intended 

function(s) was identified based on an evaluation of the component type and the 

way(s) in which the component supports the system intended functions. The 

results of the component screening were documented.

During the screening process, components that were identified as short-lived were eliminated 

from the AMR process and the basis for the classification as short-lived was documented. 

Other in-scope passive components were identified as subject to an AMR.

2.1.5.2.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for mechanical component screening as 

described in LRA Section 2.1.4.1, implementing procedures, basis documents, and the 

mechanical scoping and screening reports. The staff determined that the applicant used the 

screening process described in these documents, along with the information contained in 

NEI 95-10, Appendix B, and the SRP-LR, to identify the mechanical SCs subject to an AMR. 

The staff determined that the applicant had identified SCs that were found to meet the passive 

criteria in accordance with the guidance contained in NEI 95-10. In addition, the staff 

determined that the applicant had evaluated the identified passive commodities to determine 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-23

that they were not subject to replacement based on a qualified life or specified time period 

(long-lived) and that the remaining passive, long-lived components were subject to an AMR. 

The staff performed a sample review to determine if the screening methodology outlined in the 

LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed the essential service water system screening 

report and basis documents, had discussions with the applicant, and verified proper 

implementation of the screening process. 

2.1.5.2.3 Conclusion

On the basis of its review of information contained in the LRA, implementing procedures, and 

the sampled mechanical screening results, the staff concludes that the applicant’s methodology 

for identification of mechanical SCs within the scope of license renewal and subject to an AMR 

is in accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable. 

2.1.5.3 Structural Component Screening

2.1.5.3.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify structural SCs included within the scope 

of license renewal that are subject to an AMR in accordance with the requirements of 

10 CFR 54.21. LRA Section 2.1.4.2, “Structural Component Screening Methodology,” states, in 

part:

During the structural screening process, the intended function(s) of passive 

structural components were documented. In the structure screening process, an 

evaluation was made to determine whether in-scope structural components were 

subject to replacement based on a qualified life or specified time period. If an 

in-scope structural component was determined to be subject to replacement 

based on a qualified life or specified time period, the component was identified as 

short-lived and was excluded from an AMR. In such a case, the basis for 

determining that the structural component was short-lived was documented.

2.1.5.3.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for structural component screening as 

described in LRA Section 2.1.4.2, implementing procedures, basis documents, and the 

structural scoping and screening reports. The staff determined that the applicant used the 

screening process described in these documents along with the information contained in 

NEI 95-10, Appendix B, and the SRP-LR, to identify the structural SCs subject to an AMR. 

The staff determined that the applicant had identified structural SCs that 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 that they were not subject 

to replacement based on a qualified life or specified time period (long-lived) and that the 

remaining passive, long-lived components were determined to be subject to an AMR. 

The staff performed a sample review to determine if the screening methodology outlined in the 

LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed the turbine building screening report and basis 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-24

documents, had discussions with the applicant, and verified proper implementation of the 

screening process. 

2.1.5.3.3 Conclusion

On the basis of its review of information contained in the LRA, implementing procedures, and 

the sampled structural screening results, the staff concludes that the applicant’s methodology to 

identify structural SCs within the scope of license renewal and subject to an AMR is in 

accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable. 

2.1.5.4 Electrical Component Screening

2.1.5.4.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify electrical SCs included within the scope 

of license renewal that are subject to an AMR in accordance with the requirements of 

10 CFR 54.21. LRA Section 2.1.4.3, “Electrical and Instrumentation and Control Component

Screening Methodology,” states, in part:

The in-scope electrical components were categorized as “active” or “passive” 

based on the determinations documented in NEI 95-10, Appendix B. The 

screening of electrical and instrumentation and control components used the 

spaces approach which is consistent with the guidance in NEI 95-10. The 

spaces approach to AMR is based on areas where bounding environmental 

conditions are identified. The bounding environmental conditions are applied 

during AMR to evaluate the aging effects on passive electrical component types 

that are located within the bounding area. Use of the spaces approach for AMR 

of electrical component types eliminates the need to associate electrical and 

instrumentation and control components with specific systems that are within the 

scope of license renewal. The passive long-lived electrical and instrumentation 

and control components that perform an intended function without moving parts 

or without change in configuration or properties were grouped into component 

types such as insulated cable and connections, connectors, terminal blocks, 

high-voltage insulators, transmission conductor, transmission connections, metal 

enclosed bus, and switchyard bus and connections. Component-level intended 

function(s) were determined for each in-scope passive electrical component 

group and documented. The passive in-scope electrical component types were 

documented as subject to an AMR.

2.1.5.4.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for electrical component screening as 

described in LRA Section 2.1.4.3, implementing procedures, basis documents, and the electrical 

scoping and screening reports. The staff confirmed that the applicant had used the screening 

process described in these documents, along with the information contained in NEI 95-10,

Appendix B, and the SRP-LR, to identify the electrical SSCs subject to an AMR. 

The staff determined that the applicant had identified electrical commodity groups that 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 which 

were not subject to replacement based on a qualified life or specified time period (long-lived) 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-25

and that the remaining passive, long-lived components were determined to be subject to 

an AMR. 

The staff performed a sample review to determine if the screening methodology outlined in the 

LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed electrical screening reports and basis 

documents, had discussions with the applicant, and verified proper implementation of the 

screening process.

2.1.5.4.3 Conclusion

On the basis of its review of information contained in the LRA, implementing procedures, and 

the sampled structural screening results, the staff concludes that the applicant’s methodology to 

identify electrical and I&C SCs within the scope of license renewal and subject to an AMR is in 

accordance with the requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.5 Conclusion for Screening Methodology

On the basis of its review of the LRA, the screening implementing procedures, discussions with 

the applicant’s staff, and a sample review of screening results, the staff concludes that the 

applicant’s screening methodology was consistent with the guidance contained in the SRP-LR 

and identified those passive, long-lived components within the scope of license renewal that are 

subject to an AMR. The staff concludes that the applicant’s methodology is consistent with the 

requirements of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.6 Summary of Evaluation Findings

On the basis of its review of the information presented in LRA Section 2.1, the supporting 

information in the scoping and screening implementing procedures and reports, the information 

presented during the scoping and screening methodology audit, discussions with the applicant,

sample system reviews, and the applicant’s responses to RAIs 2.1-1, 2.1-2, 2.1-3, and 2.1-4, 

the staff confirms that the applicant’s scoping and screening methodology is consistent with the 

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also concludes that the 

applicant’s description and justification of its scoping and screening methodology are adequate 

to meet the requirements of 10 CFR 54.21(a)(1). From this review, the staff concludes that the 

applicant’s methodology for identifying systems and structures within the scope of license 

renewal and SCs requiring an AMR is acceptable.

2.2 Plant-Level Scoping Results

2.2.1 Introduction

LRA Section 2.1 describes the methodology for identifying SSCs within the scope of license 

renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which 

SSCs must be included within the scope of license renewal.

The staff reviewed the plant-level scoping results to determine if the applicant properly identified 

the following groups:

• systems and structures relied upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1)

• systems and structures, the failure of which could prevent satisfactory accomplishment 

of any safety-related functions, as required by 10 CFR 54.4(a)(2)
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-26

• systems and structures relied on for safety analyses or plant evaluations to perform 

functions required by regulations referenced in 10 CFR 54.4(a)(3)

2.2.2 Summary of Technical Information in the Application 

LRA Table 2.2-1 lists mechanical, 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 plant’s CLB, other CLB 

information relating to nonsafety-related systems and structures, and certain regulated events, 

the applicant identified plant-level systems and structures within the scope of license renewal, 

as defined by 10 CFR 54.4.

2.2.3 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying systems and 

structures within the scope of license renewal and subject to an AMR. The staff reviewed 

the scoping and screening methodology and provides its evaluation in SER Section 2.1. 

To verify the applicant properly implemented its methodology, the staff’s review focused on 

the implementation results shown in LRA Table 2.2-1, “Callaway Plant Scoping Results,” to 

confirm that there were no omissions of plant-level systems and structures within the scope 

of license renewal.

The staff determined if the applicant properly identified the systems and structures within 

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed systems 

and structures that the applicant did not identify as within the scope of license renewal to 

verify if the systems and structures have any intended functions requiring their inclusion 

within the scope of license renewal. The staff’s review of the applicant’s implementation 

was conducted in accordance with the guidance in SRP-LR Section 2.2, “Plant-Level 

Scoping Results.”

The staff noted that LRA Table 2.2-1 provides the results of applying the license renewal 

scoping criteria to the systems, structures, and commodities and the license renewal 

scoping criteria was described in LRA Section 2.1. The staff reviewed FSAR 

Section 18.1.17, “Plant Safety Parameter Display System,” but could not locate the plant 

safety parameter display system in LRA Table 2.2-1. 

By letter dated June 11, 2012, the staff issued RAI 2.2-1 requesting the applicant to justify 

the exclusion of the plant safety parameter display system from LRA Table 2.2-1.

In its response letter, dated July 2, 2012, the applicant stated the plant safety parameter 

display system is included in the plant computer system. The applicant also stated that the 

plant computer system is listed in LRA Table 2.2-1 and has been excluded from the scope 

of license renewal since it does not perform any of the intended functions that satisfy the 

criteria in 10 CFR 54.4(a)(1), (a)(2), or (a)(3). 

Based on its review, the staff finds the applicant’s response to RAI 2.2-1 acceptable 

because the applicant explained that the plant safety parameter display system is included 

in the plant computer system in LRA Table 2.2-1. The staff finds the applicant’s exclusion 

of the plant computer from scope of license renewal acceptable since it does not have any 

license renewal intended functions. Therefore, the staff’s concern described in RAI 2.2-1 is 

resolved.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-27

2.2.4 Conclusion

The staff reviewed LRA Section 2.2, the RAI response, and the FSAR supporting 

information to determine if the applicant failed to identify any systems and structures within 

the scope of license renewal. On the basis of its review, the staff concludes that the 

applicant has appropriately identified the systems and structures within the scope of 

license renewal in accordance with 10 CFR 54.4.

2.3 Scoping and Screening Results: Mechanical Systems

This section documents the staff’s review of the applicant’s scoping and screening results 

for mechanical systems. Specifically, this section discusses:

• reactor vessel, internals, and reactor coolant system (RCS)

• engineered safety features (ESF) systems

• auxiliary systems

• 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 the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to verify the applicant identified the 

mechanical system SCs that met the scoping criteria and were subject to an AMR, 

confirming that there were no omissions.

The staff’s evaluation of mechanical systems was performed using the evaluation 

methodology described in the guidance in SRP-LR Section 2.3 and took into account the 

system function(s) described in the FSAR. The objective was to determine if the applicant, 

in accordance with 10 CFR 54.4, has identified 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 FSAR, 

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 delineated under 10 CFR 54.4(a), the staff verified 

the applicant properly screened out only: (1) SCs that have functions performed with 

moving parts or a change in configuration or properties, or (2) 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 identified the 

remaining SCs subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested 

additional information to resolve any omissions or discrepancies identified.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-28

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

LRA Section 2.3.1 identifies the reactor vessel, internals, and RCS SCs subject to an AMR for 

license renewal.

The applicant described the supporting SCs of the reactor vessel, internals, and RCS in the 

following LRA sections:

• LRA Section 2.3.1.1, “Reactor Vessel and Internals”

• LRA Section 2.3.1.2, “Reactor Coolant System”

• LRA Section 2.3.1.3, “Pressurizer”

• LRA Section 2.3.1.4, “Steam Generators”

• LRA Section 2.3.1.5, “Reactor Core”

2.3.1.1 Reactor Vessel and Internals

2.3.1.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.1.1 states that the purpose of the reactor vessel is to function as an RCS 

pressure boundary which acts as a barrier to prevent the release of radioactivity generated 

within the reactor. The reactor vessel is a cylindrical vessel with a welded hemispherical bottom 

head and a removable, bolted, flanged hemispherical upper head. The vessel contains the 

core, core supporting structures, control rods, and other parts directly associated with the core. 

The top head also has penetrations for the control rod drive mechanisms (CRDMs) and the 

head vent pipe. The O-ring leak monitoring tube penetrations are in the vessel flange. Reactor 

coolant flows through the vessel inlet and outlet nozzles located in a horizontal plane just below 

the reactor vessel flange, but above the top of the core. The vessel is supported by pads on the 

bottom of four of the eight nozzles. The bottom head of the vessel contains penetration nozzles 

for connection and entry of the nuclear incore instrumentation.

The reactor internals consist of the lower core support structure, the upper core support 

structure, and the incore instrumentation support structure. The reactor internals provide 

various functions, including supporting the core, maintaining fuel alignment, limiting fuel 

assembly movement, maintaining alignment between fuel assemblies and CRDMs, directing 

coolant flow past the fuel elements, directing coolant flow to the pressure vessel head, and 

providing gamma and neutron shielding and guiding incore instrumentation.

The lower core support structure includes the baffle and former plates, core barrel assembly, 

neutron shield panel, lower core plates, core support forging, support columns, secondary core 

support, energy absorbers, tie plates, and man way cover.

The intended functions of the reactor vessel and internals component types within the scope of 

license renewal include the following:

• to serve as a pressure boundary for containing reactor coolant

• to provide a barrier against the release of radioactivity

• to support and contain the reactor core and core support structures

• to provide support, orientation, guidance, and protection of the reactor controls and 

instrumentation

• to direct the main flow of coolant through the core
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-29

• to provide for secondary flows for cooling of the reactor vessel and internals

• to maintain fuel alignment and limit fuel assembly movement

• to provide gamma and neutron shielding

• to support fire protection (10 CFR 50.48), PTS (10 CFR 50.61), and SBO 

(10 CFR 50.63) requirements

LRA Table 2.3.1-1 identifies the reactor vessel and internals component types within the scope 

of license renewal and subject to an AMR.

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.1.1.3 Conclusion 

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and FSAR, the staff concludes that the applicant appropriately identified the reactor vessel 

and internals components within the scope of license renewal, as required by 10 CFR 54.4(a). 

The staff also concluded that the applicant adequately identified the reactor vessel and internals 

components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.2 Reactor Coolant System

2.3.1.2.1 Summary of Technical Information in the Application

LRA Section 2.3.1.2 states that the purpose of the RCS is to transfer the heat generated in the 

reactor core to the steam generators, where steam is produced to drive the turbine generator. 

The RCS provides a pressure boundary barrier for containing the coolant under all anticipated 

temperature and pressure conditions and for limiting the release of radioactivity. The RCS 

consists of four similar heat transfer loops connected in parallel to the reactor vessel. Each loop 

contains an identical reactor coolant pump (RCP), a steam generator, and interconnecting 

piping to various auxiliary or safety systems. The RCS also includes a pressurizer, 

interconnecting piping, pressurizer safety and relief valves, pressurizer relief tank, and 

instrumentation that provide operational pressure control. Borated pressurized water is 

circulated in the system to act as a neutron moderator and reflector and as a neutron absorber 

for chemical shim control. 

The intended functions of RCS component types within the scope of license renewal include the 

following:

• to serve as a pressure boundary and limit the release of fission products

• to provide RCS pressure control and limit pressure transients

• to provide the borated water used as the core neutron moderator and reflector, and for 

chemical shim control

• to provide a containment isolation function
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-30

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and SBO (10 CFR 50.63) 

requirements

LRA Table 2.3.1-2 identifies the RCS component types within the scope of license renewal and 

subject to an AMR.

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.1.2.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and FSAR, the staff concludes that the applicant appropriately identified the RCS 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant adequately identified the RCS components subject to an AMR, as 

required by 10 CFR 54.21(a)(1).

2.3.1.3 Pressurizer

2.3.1.3.1 Summary of Technical Information in the Application

LRA Section 2.3.1.3 states that the purpose of the pressurizer is to provide a point within the 

RCS to maintain liquid and vapor at equilibrium temperature and pressure under saturated 

conditions for pressure control. 

The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads. 

Installed in the bottom head are a surge line nozzle and removable electric heaters. A thermal 

sleeve is also installed to minimize stresses in the surge line nozzle. Located in the top head of 

the vessel are the spray nozzle and the relief and safety valve connections. Automatically 

controlled air-operated valves modulate the spray flow.

The intended functions of the pressurizer component types within the scope of license renewal 

include:

• to serve as a pressure boundary

• to provide RCS pressure control and limit pressure transients

• to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements

LRA Table 2.3.1-3 identifies the pressurizer component types within the scope of license 

renewal and subject to an AMR.

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-31

2.3.1.3.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and FSAR, the staff concludes that the applicant appropriately identified the pressurizer 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant adequately identified the pressurizer components subject to an 

AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.4 Steam Generators

2.3.1.4.1 Summary of Technical Information in the Application

LRA Section 2.3.1.4 states that the purpose of the steam generators is to provide heat removal 

from the RCS through the generation of steam and also to act as an assured source of steam 

for the steam-driven auxiliary feedwater pump. The steam generators system consists of the 

primary and secondary pressure boundaries of the steam generators, including all pieces and 

parts within the pressure boundary and all penetrations out to the safe ends of the penetration 

nozzles.

The intended functions of the steam generators component types within the scope of license 

renewal include the following:

• to serve as a pressure boundary and limit the release of fission products

• to provide RCS heat removal through steam generation

• to provide for inventory and pressure control

• to provide assured source of steam for turbine-driven auxiliary feedwater pump

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements

LRA Table 2.3.1-4 identifies the steam generators component types within the scope of license 

renewal and subject to an AMR.

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.1.4.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and FSAR, the staff concludes that the applicant appropriately identified the steam 

generators components within the scope of license renewal, as required by 10 CFR 54.4(a). 

The staff also concludes that the applicant adequately identified the steam generators

components subject to an AMR, as required by 10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-32

2.3.1.5 Reactor Core

2.3.1.5.1 Summary of Technical Information in the Application

LRA Section 2.3.1.5 states that the purpose of the reactor core is to provide a heat source for 

the steam generators to support the generation of steam.

The reactor core consists of 193 fuel assemblies each containing of 264 fuel rods, 24 rod cluster 

control assembly (RCCA) guide tubes, and an incore instrumentation thimble. Each fuel rod is 

constructed of zirconium alloy tubing containing uranium dioxide fuel pellets. Spacer grids and 

top and bottom nozzles hold each rod in place. Guide thimbles are used as core locations for 

RCCAs, neutron source assemblies, and burnable absorber rods.

The bottom nozzle serves as a structural element of the fuel assembly and directs the coolant 

flow to the assembly. The top nozzle assembly serves a structural element of the fuel assembly 

and also provides a partial protective housing for the RCCA or other components. RCCA 

consists of a group of individual absorber rods fastened to a common hub or spider assembly.

The intended functions of the reactor core component types within the scope of license renewal 

include the following:

• to meet heat transfer performance requirements in all modes

• to serve as a fission product barrier

• to provide reactivity control

• to support fire protection (10 CFR 50.48) requirements

LRA Table 2.3.1-5 identifies the reactor core component types within the scope of license 

renewal and subject to an AMR.

2.3.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.1.5.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and the FSAR, the staff concludes that the applicant appropriately identified the reactor 

core components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff 

also concludes that the applicant adequately identified the reactor core components subject to 

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2 Engineered Safety Features 

LRA Section 2.3.2 identifies the ESF SCs subject to an AMR for license renewal.

The applicant described the supporting SCs of the ESFs in the following LRA sections:

• LRA Section 2.3.2.1, “Containment Spray System”

• LRA Section 2.3.2.2, “Containment Integrated Leak Rate Testing System”

• LRA Section 2.3.2.3, “Containment Hydrogen Control System”
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-33

• LRA Section 2.3.2.4, “Containment Purge System”

• LRA Section 2.3.2.5, “High-Pressure Coolant Injection System”

• LRA Section 2.3.2.6, “Residual Heat Removal System”

2.3.2.1 Containment Spray System 

2.3.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.1 states that the purpose of the containment spray system is to remove heat 

from the containment following a loss-of-coolant accident (LOCA) or main steam line break to 

reduce the containment ambient temperature and pressure. The containment spray system 

also uses trisodium phosphate for pH control to promote absorption of airborne iodine from the 

containment atmosphere, should this fission product be released in an accident.

The containment spray system consists of pumps, spray ring headers and nozzles, containment 

spray system additive eductors, trisodium phosphate baskets, and the associated piping and 

valves.

The intended functions of the containment spray component types within the scope of license 

renewal include the following:

• to provide pH control to limit airborne iodine

• to maintain containment integrity

• to provide sump filtering

• to provide for containment pressure reduction

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements

LRA Table 2.3.2-1 identifies the containment spray system component types within the scope of 

license renewal and subject to an AMR.

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.2.1.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and the FSAR, the staff concludes that the applicant appropriately identified the 

containment spray system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the 

containment spray system components subject to an AMR, as required by 10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-34

2.3.2.2 Containment Integrated Leak Rate Testing System

2.3.2.2.1 Summary of Technical Information in the Application

LRA Section 2.3.2.2 states that the purpose of the containment integrated leak rate testing 

system is to provide a way to periodically test containment leakage. The containment integrated 

leak rate testing system achieves this by pressurizing the containment building and monitoring 

leakage to the atmosphere. 

The intended functions of the containment integrated leak rate testing system within the scope 

of license renewal include the following:

• to provide containment isolation during normal plant operation

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support EQ (10 CFR 50.49) requirements

LRA Table 2.3.2-2 identifies the containment integrated leak rate testing system component 

types within the scope of license renewal and subject to an AMR.

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.2.2.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the containment integrated leak rate testing system components within 

the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the containment integrated leak rate testing system components 

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.3 Containment Hydrogen Control System 

2.3.2.3.1 Summary of Technical Information in the Application

LRA Section 2.3.2.3 states that the purpose of the containment hydrogen control system is to 

control combustible gas concentrations in the containment following a LOCA. The containment 

hydrogen control system consists of the electric hydrogen recombiners and the hydrogen 

monitoring, hydrogen mixing, and backup hydrogen purge subsystems. The containment 

hydrogen control system monitoring is performed by hydrogen analyzers and associated sample 

lines with their containment isolation valves. The containment hydrogen control system 

contains a penetration through which the containment atmosphere is purged and filtered. The 

system uses the fuel/auxiliary building emergency exhaust system and mixing fans to perform 

its functions. 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-35

The intended functions of the containment hydrogen control system within the scope of license 

renewal include the following:

• to provide containment isolation

• to provide mixing of the containment atmosphere after a LOCA

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support EQ (10 CFR 50.49) requirements

LRA Table 2.3.2-3 identifies the containment hydrogen control system component types within 

the scope of license renewal and subject to an AMR.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.2.3.3 Conclusion 

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the containment hydrogen control system components within the scope 

of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the containment hydrogen control system components subject to an AMR, 

as required by 10 CFR 54.21(a)(1).

2.3.2.4 Containment Purge System

2.3.2.4.1 Summary of Technical Information in the Application

LRA Section 2.3.2.4 states that the purpose of the containment purge system is to reduce the 

concentration of noble gases within containment before and during personnel access to the 

containment or to equalize containment internal pressure with the external pressure. The 

containment purge system also supplies outside air into the containment for ventilation and 

cooling or heating needed for prolonged containment access during a reactor outage. The 

containment purge system consists of the containment minipurge and containment shutdown 

purge systems. The principal components of the containment purge system include the heating, 

ventilation, and air-conditioning (HVAC) intake, common unit vent, non-essential filtering unit, 

supply fans, exhaust fans, containment isolation valves, radiation monitors, dampers, and 

ventilation ducts.

The intended functions of the containment purge system within the scope of license renewal 

include the following:

• to provide containment isolation valves to limit the escape of fission products from the 

containment following a DBE 

• to provide radiation monitoring and radiation level input to the ESF actuation signal
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-36

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements 

LRA Table 2.3.2-4 identifies the containment purge system component types within the scope of 

license renewal and subject to an AMR.

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.2.4.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the containment purge system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the containment purge system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

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 states that the purpose of the high-pressure coolant injection (HPCI) 

system is to remove stored and decay heat from the reactor core and provide shutdown 

capability during accident conditions. Reactor core cooling is accomplished in two phases. The 

HPCI system is part of the emergency core cooling (ECC) system. The HPCI takes suction 

from either the refueling water storage tank (RWST) or residual heat removal (RHR) pump 

discharge and delivers the borated water to either the RCS cold legs or RCS hot legs. Also 

included in this section are other parts of the ECC system, the accumulator safety injection 

(ASI) system, and the borated refuel water storage (BRWS) system. The purpose of the ASI

system is to deliver borated water to the RCS coldlegs during the post-LOCA injection phase. 

The purpose of the BRWS system is to store borated water so that it is available to the refueling 

pool during refueling, the chemical and volume control (CVC) system during abnormal operating 

conditions, and the containment spray and ECC systems during accident conditions.

The HPCI system consists of two safety injection pumps, flow orifices, associated piping, 

valves, and instrumentation. The ASI system consists of four accumulator tanks and the 

associated piping, valves, and instrumentation. The BWRS system consists of an outdoor 

storage tank and connections for delivery to and receipt from the fuel pool cooling and cleanup 

system, the CVC system, the containment spray system, and the ECC system.

The intended functions of the HPCI system within the scope of license renewal include the 

following:

• to provide heat removal from the reactor core

• to provide reactivity and inventory control during accident conditions
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-37

• to maintain the integrity of the RCPB

• to ensure that containment integrity is maintained

• to ensure borated water is available 

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements

LRA Table 2.3.2-5 identifies the HPCI system component types within the scope of license 

renewal and subject to an AMR.

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.5 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.2.5.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the HPCI system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the HPCI system components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.6 Residual Heat Removal System

2.3.2.6.1 Summary of Technical Information in the Application

LRA Section 2.3.2.6 states that the purpose of the RHR system is to transfer heat from the RCS 

in normal shutdown and post accident conditions. The RHR system also supports the ECC 

system during a LOCA injection and recirculation phase. In addition, the RHR system is used to 

transfer refueling water between the RWST and the refueling cavity.

The RHR system consists of two heat exchangers, two pumps, and associated piping, valves, 

and instrumentation. 

The intended functions of RHR system within the scope of license renewal include the following:

• to form a part of the RCS pressure boundary

• to provide protection against over-pressurization and rupture of ECC system low 

pressure piping that could result in a LOCA

• to provide borated water for RCS makeup in LOCA conditions

• to remove decay heat in post-accident and normal shutdown conditions

• to ensure that containment integrity is maintained in single failure scenarios

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-38

LRA Table 2.3.2-6 identifies the RHR system component types within the scope of license 

renewal and subject to an AMR.

2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.2.6.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the RHR system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the RHR system components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3 Auxiliary Systems

LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal. 

The applicant described the supporting SCs of the auxiliary systems in the following LRA 

sections: 

• LRA Section 2.3.3.1, “Fuel Storage and Handling System”

• LRA Section 2.3.3.2, “Fuel Pool Cooling and Cleanup System”

• LRA Section 2.3.3.3, “Cranes, Hoists, and Elevators” 

• LRA Section 2.3.3.4, “Essential Service Water System” 

• LRA Section 2.3.3.5, “Service Water System” 

• LRA Section 2.3.3.6, “Reactor Makeup Water System” 

• LRA Section 2.3.3.7, “Component Cooling Water System” 

• LRA Section 2.3.3.8, “Compressed Air System” 

• LRA Section 2.3.3.9, “Nuclear Sampling System” 

• LRA Section 2.3.3.10, “Chemical and Volume Control System” 

• LRA Section 2.3.3.11, “Control Building HVAC System” 

• LRA Section 2.3.3.12, “Essential Service Water Pumphouse HVAC System” 

• LRA Section 2.3.3.13, “Auxiliary Building HVAC System” 

• LRA Section 2.3.3.14, “Fuel Building HVAC System” 

• LRA Section 2.3.3.15, “Miscellaneous Buildings HVAC System” 

• LRA Section 2.3.3.16, “Diesel Generator Building HVAC System” 

• LRA Section 2.3.3.17, “Radwaste Building HVAC System” 

• LRA Section 2.3.3.18, “Turbine Building HVAC System” 

• LRA Section 2.3.3.19, “Containment Cooling System” 

• LRA Section 2.3.3.20, “Fire Protection System” 

• LRA Section 2.3.3.21, “Emergency Diesel Engine Fuel Oil Storage and Transfer System” 

• LRA Section 2.3.3.22, “Standby Diesel Generator Engine System” 

• LRA Section 2.3.3.23, “EOF and TSC Diesels, Security Building System” 

• LRA Section 2.3.3.24, “Liquid Radwaste System” 

• LRA Section 2.3.3.25, “Decontamination System” 

• LRA Section 2.3.3.26, “Oily Waste System” 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-39

• LRA Section 2.3.3.27, “Floor and Equipment Drainage System” 

• LRA Section 2.3.3.28, “Miscellaneous Systems In Scope ONLY for 

Criterion 10 CFR 54.4(a)(2)” 

• LRA Section 2.3.3.29, “Circulating Water System”

2.3.3.1 Fuel Storage and Handling System

2.3.3.1.1 Summary of Technical Information in the Application

LRA Section 2.3.3.1 states that the purpose of the fuel storage and handling system is to 

provide onsite storage of new and spent fuel assemblies, provide manipulation of fuel 

assemblies and rod control clusters, and provide for the servicing of the reactor vessel closure 

head and internals. The system is designed to minimize the possibility of mishandling or 

improper operation that could cause fuel assembly damage or potential fission product release. 

The fuel storage and handling system consists of fuel handling and storage equipment,

including cranes, elevators, fuel storage racks, lift rigs, and transfer systems. Fuel cranes and 

fuel elevators are evaluated in this system.

The intended functions of the fuel storage and handling system within the scope of license 

renewal include: (1) providing onsite storage and maintain a subcritical arrangement of new 

and spent fuel assemblies under normal and postulated DBEs; and (2) providing 

nonsafety-related handling systems to carry heavy loads over safety-related components, or 

over irradiated fuel in the reactor vessel or spent fuel pool.

LRA Table 2.3.3-1 identifies the fuel storage and handling system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.1.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the fuel storage and handling system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system mechanical components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.2 Fuel Pool Cooling and Cleanup System

2.3.3.2.1 Summary of Technical Information in the Application

LRA Section 2.3.3.2 states that the purpose of the fuel pool cooling and cleanup system is to 

remove decay heat and impurities from the refueling pool water and maintain the spent fuel pool 

water temperature below prescribed limits. The fuel pool cooling and cleanup system consists 

of the fuel pool cooling, fuel pool cleanup, and fuel pool surface skimmer systems. Some of the 

main components of the fuel pool cooling and cleanup system are two 100 percent capacity 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-40

cooling trains; pumps; shell and U-tube heat exchangers; filters; a mixed bed demineralizer; and 

associated strainers, piping and valves.

The intended functions of the fuel pool cooling and cleanup system within the scope of license 

renewal include the following:

• to provide water inventory over the spent fuel assemblies to mitigate the radiological 

consequences following a design-basis accident 

• to maintain fuel storage pool water temperature below prescribed limits

• to provide containment integrity

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) requirements

LRA Table 2.3.3-2 identifies the fuel pool cooling and cleanup system component types within 

the scope of license renewal and subject to an AMR.

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.2.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

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). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.3 Cranes, Hoists, and Elevators

2.3.3.3.1 Summary of Technical Information in the Application

LRA Section 2.3.3.3 states that the purpose of the cranes, hoists, and elevators system is to 

provide lifting in Category I structures and various nonsafety-related buildings. The cranes, 

hoists, and elevators system contains nonsafety-related components that perform no 

safety-related functions. The cranes, hoists, and elevators system consists of cranes, doors, 

elevators, hoists, and trolleys. 

The intended functions of the cranes, hoists, and elevators system within the scope of license 

renewal are to carry heavy loads over safety-related components required for plant shutdown or 

decay heat removal and to resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of a safety-related function in accordance with the requirements of

10 CFR 54.4(a)(2).

LRA Table 2.3.3-3 identifies the cranes, hoists, and elevators system component types within 

the scope of license renewal and subject to an AMR.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-41

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.3.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the cranes, hoists, and elevators system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.4 Essential Service Water System

2.3.3.4.1 Summary of Technical Information in the Application

LRA Section 2.3.3.4 states that the purpose of the essential service water (ESW) system is to 

provide cooling water to those components that require cooling for safe shutdown of the reactor 

and conveys the heat to the UHS cooling tower. The ESW system also provides: (1) cooling 

water to the spent fuel pool cooling pump room coolers, (2) cooling water to nonsafety-related 

air compressors and associated after-coolers, and (3) emergency makeup to the spent fuel pool 

and component cooling water (CCW) systems. It also acts as the backup water supply to the 

auxiliary feedwater system if the condensate storage tank water is unavailable. Some of the 

components that the ESW system cools are the following:

• the CCW heat exchangers

• containment air coolers

• diesel generator coolers

• safety injection pump room coolers

• RHR pump room coolers

• containment spray pump room coolers

• centrifugal charging pump room coolers

• CCW pump room coolers

• auxiliary feedwater pump room coolers

• control room air conditioning condensers

• Class 1E switchgear air-conditioning condensers

• penetration room coolers.

The intended functions of the ESW system within the scope of license renewal include the 

following:

• to support the functions of containment isolation, decay heat removal, and inventory and 

pressure control

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-42

LRA Table 2.3.3-4 identifies the ESW system component types within the scope of license 

renewal and subject to an AMR.

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.4.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant has 

appropriately identified the ESW system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.5 Service Water System

2.3.3.5.1 Summary of Technical Information in the Application

LRA Section 2.3.3.5 states that the purpose of the service water system is to provide cooling 

water to the non-essential components that the ESW system serves during normal plant 

operation and shutdown. The service water system also supplies fire water to those stations 

within the ESW pumphouse. The service water system takes water from the cooling tower 

basin and discharges the heated return water into the circulating water system. The service 

water system consists of pumps, piping, valves, strainers, heat exchangers, and chillers.

The intended functions of the service water system within the scope of license renewal are to 

resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2) and to support 

fire protection (10 CFR 50.48) requirements.

LRA Table 2.3.3-5 identifies the service water system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5, FSAR Sections 9.2.1.1 SA, 9.2.1.1 SP, 9.5.1.2.2 SA, 

9.5.1.2.2.SP, and Appendix 9.5B SA, as well as the license renewal boundary drawings using 

the evaluation methodology discussed in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. On the basis of its review, the staff identified an area in which additional 

information was necessary to complete the review of the applicant’s scoping and screening 

results. 

The staff noted that license renewal boundary drawings LR-CW-EA-M-22EA01, location E-8, 

and LR-CW-EA-M-22EA01, locations C-6/7, both depict sections of 10 CFR 54.4(a)(2) piping 

(lines 036-HBD-8-inch and 039-HBD-8-inch, respectively) that continue to drawing 

LR-CW-KA-M-22KB02, location B-8. This drawing was not submitted as part of the LRA for the 

staff’s review. By letter dated June 11, 2012, the staff issued RAI 2.3.3.5-1 requesting the

applicant to provide sufficient information to locate and describe the license renewal boundary 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-43

for the above 10 CFR 54.4(a)(2) piping, including additional information describing the extent of 

the scoping boundary and to verify whether there are additional AMR component types between 

the continuation and termination of the scoping boundary. 

In its response letter, dated July 2, 2012, the applicant stated that the 10 CFR 54.4(a)(2) piping 

from line 036-HBD-8-inch and line 039-HBD-8-inch, as depicted on license renewal boundary 

drawing LR-CW-EA-M-22EA01, continues onto the newly created license renewal boundary 

drawing LR-CW-KA-M-22KB02 and terminates at the breathing air compressor heat 

exchangers. 

The applicant also indicated that due to extension of the scoping boundary of the 

10 CFR 54.4(a)(2) piping, the breathing air compressor heat exchangers were added to the 

compressed air system (LRA Section 2.3.3.8) as being within the scope of license renewal for 

10 CFR 54.4(a)(2) with the intended function of structural integrity. As part of its response, the 

applicant provided revisions to LRA Section 2.3.3.8 and LRA Table 2.3.3-8 to include the heat 

exchanger component. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.5-1 acceptable

because the applicant described the license renewal boundary of the 10 CFR 54.4(a)(2) piping 

on license renewal boundary drawings LR-CW-EA-M-22EA01 and LR-CW-KA-M-22KB02 and 

included the breathing air compressor heat exchanger within the scope of license renewal. The 

staff reviewed the above license renewal boundary drawings and the revisions to LRA 

Section 2.3.3.8 and LRA Table 2.3.3-8 to confirm the scoping boundary and the inclusion of the 

heat exchanger component. Therefore, the staff’s concern described in RAI 2.3.3.5-1 is 

resolved.

2.3.3.5.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, RAI response, and license renewal boundary drawings, the staff concludes that the 

applicant appropriately identified the service water system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.6 Reactor Makeup Water System

2.3.3.6.1 Summary of Technical Information in the Application

LRA Section 2.3.3.6 states that the purpose of the reactor makeup water system is to store 

de-aerated water necessary for primary makeup within the plant. Filtered, de-aerated, 

demineralized water is received from the demineralized water storage and transfer system. The 

reactor makeup water system components within the scope of license renewal consist of 

safety-related and nonsafety-related piping.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-44

The intended functions of the reactor makeup water system within the scope of license renewal 

include the following:

• to provide containment isolation for a containment penetration

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support EQ (10 CFR 50.49) requirements

LRA Table 2.3.3-6 identifies the reactor makeup water system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.6.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the reactor makeup water system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.7 Component Cooling Water System 

2.3.3.7.1 Summary of Technical Information in the Application

LRA Section 2.3.3.7 states that the purpose of the CCW system is to remove heat from heat 

exchangers required for the safe shutdown of the reactor and to act as an intermediate heat 

transfer system between potentially radioactive systems and the service water system or the 

ESW system to eliminate the possibility of an uncontrolled release of radioactivity.

The intended functions of the CCW system within the scope of license renewal include the 

following:

• to support maintenance of vital auxiliaries, heat removal, and containment integrity

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements 

LRA Table 2.3.3-7 identifies the CCW system component types within the scope of license 

renewal and subject to an AMR.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-45

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.7.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the CCW system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.3.8 Compressed Air System 

2.3.3.8.1 Summary of Technical Information in the Application

LRA Section 2.3.3.8 states that the purpose of the compressed air system is to provide 

compressed air to the instrument air, service air, breathing air, and containment systems. The 

compressed air system consists of the compressed air, service gas, and breathing air systems. 

The intended functions of the compressed air system within the scope of license renewal 

include the following:

• to support containment integrity

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

condition

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support EQ (10 CFR 50.49), fire protection (10 CFR 50.48), and SBO (10 CFR 50.63) 

requirements 

LRA Table 2.3.3-8 identifies the compressed air system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8, FSAR Sections 9.3.1 SP, 9.3.5 SP, and 9.5.10 SP, 

as well as the license renewal boundary drawings using the evaluation methodology 

discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its 

review, the staff identified an area in which additional information was necessary to 

complete the review of the applicant’s scoping and screening results. 

The staff could not identify seismic anchors or terminations for the 10 CFR 54.4(a)(2) 

nonsafety-related piping on license renewal boundary drawings LR-CW-KA-M-22KA01, 

location B-1, and LR-CW-KA-M-22KA04, location F-4. By letter dated June 11, 2012, the 

staff issued RAI 2.3.3.8-1, requesting the applicant to locate the seismic anchors between 

the safety-related and nonsafety-related interface and the ends of the 10 CFR 54.4(a)(2) 

scoping boundary for each piping.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-46

In its response letter, dated July 2, 2012, the applicant stated that the 10 CFR 54.4(a)(2) 

pipe sections at these four locations are capped downstream from their respective valves,

as shown on the license renewal boundary drawings, indicating that the pipe sections are 

depicted as open-ended pipe sections that do not require a continuation. The applicant 

added a note to both license renewal boundary drawings to indicate the termination points 

of the pipe sections.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-1 acceptable 

because the 10 CFR 54.4(a)(2) pipe sections are capped and are represented as 

open-ended pipe sections that do not require seismic anchors. The staff reviewed and 

confirmed on the revised license renewal boundary drawings LR-CW-KA-M-22KA01 and 

LR-CW-KA-M-22KA04 that the notes to clarify the scoping boundaries were included. 

Therefore, the staff’s concern described in RAI 2.3.3.8-1 is resolved.

As indicated in SER Section 2.3.3.5, the applicant also added the breathing air compressor 

heat exchangers within the scope of license renewal for 10 CFR 54.4(a)(2) in response to

RAI 2.3.3.5-1. The staff reviewed the revised LRA Section 2.3.3.8 and LRA Table 2.3.3-8 

to confirm that the heat exchanger component was included.

2.3.3.8.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, RAI response, and license renewal boundary drawings, the staff concludes that the 

applicant appropriately identified the compressed air system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.9 Nuclear Sampling System

2.3.3.9.1 Summary of Technical Information in the Application

LRA Section 2.3.3.9 states that the purpose of the nuclear sampling system is to collect 

samples from the reactor coolant, auxiliary, and radwaste systems and bring them to a common 

location for analysis. The nuclear sampling system consists of the primary sampling system 

and the radwaste sampling system.

The intended functions of the nuclear sampling system within the scope of license renewal are 

the following:

• to provide part of the reactor coolant boundary and containment isolation for nuclear 

sampling system containment penetrations

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support EQ (10 CFR 50.49) requirements based upon the criteria of 

10 CFR 54.4(a)(3)

LRA Table 2.3.3-9 identifies the nuclear sampling system component types within the scope of 

license renewal and subject to an AMR.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-47

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.9.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the nuclear sampling system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.10 Chemical and Volume Control System

2.3.3.10.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.10 states that the purpose of the CVC system is to maintain the water 

inventory within the RCS; provide seal water injection flow to the RCPs; vary the boron 

concentration of the RCS; maintain required RCS water chemistry, activity levels, and soluble 

chemical neutron absorber concentration; and provide reactor coolant purification. The CVC

system consists of the charging, letdown, and seal water subsystem; the reactor coolant 

purification and chemistry control subsystem; the reactor makeup control subsystem; and the 

boron thermal regeneration subsystem. The CVC system consists of various tanks, 

accumulators, bellows, chillers, pumps, heat exchangers, demineralizers, piping, and valves 

necessary to control the chemistry, volume, and boric acid content of the reactor coolant.

The purpose of the charging, letdown, and seal water subsystem is to maintain a programmed 

water level in the pressurizer during all phases of plant operation. This is achieved through a 

continuous feed-and-bleed process. Charging pumps are provided to take suction from the 

volume control tank and return the purified reactor coolant to the RCS. A portion of the charging 

flow is directed to the RCPs seal water injection.

The purpose of the reactor coolant purification and chemistry control subsystem is to maintain 

desired RCS water chemistry conditions for radioactivity control. The pH control chemical 

employed is lithium hydroxide. Dissolved hydrogen is used to control and scavenge oxygen. A 

sufficient partial pressure of hydrogen is maintained in the volume control tank so that the 

specified concentration of hydrogen is maintained in the reactor coolant. Mixed bed 

demineralizers are provided in the letdown line to clean up the letdown flow of ionic corrosion 

products and certain fission products.

The purpose of the reactor makeup control subsystem is to maintain proper reactor coolant 

inventory and soluble neutron absorber (boric acid) concentration. In addition, the redundant 

capability exists to supply borated water directly from the RWST to the suction of the charging 

pumps in an emergency. Automatic makeup compensates for minor leakage of reactor coolant 

without causing significant changes in the reactor coolant boron concentration.

The purpose of the boron thermal regeneration subsystem is to adjust boron concentration 

when needed. Downstream of the mixed bed demineralizers, the letdown flow can be diverted 

to the boron thermal regeneration (BTR) system when boron concentration changes are 

desired. Although the BTR system is primarily designed to compensate for xenon transients 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-48

occurring during load follow, it can also be used to handle boron changes during other modes of 

plant operation.

The intended functions of the CVC system within the scope of license renewal include the 

following:

• to maintain RCS pressure boundary

• to provide boration and makeup into the RCS

• to supply seal water injection flow to the RCPs seals

• to provide for containment isolation

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and SBO (10 CFR 50.63) 

requirements

LRA Table 2.3.3-10 identifies the CVC system component types within the scope of license 

renewal and subject to an AMR.

2.3.3.10.2 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.10 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.10.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the CVC system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.11 Control Building HVAC System 

2.3.3.11.1 Summary of Technical Information in the Application

LRA Section 2.3.3.11 states that the purpose of the control building HVAC system is to provide 

conditioned outside air for the ventilation and cooling to the control building. The control 

building HVAC system includes the control room filtration and control room pressurization 

systems. The control building HVAC system removes smoke following a postulated fire and 

provides a suitable environment for personnel and for Class 1E electrical equipment. 

The intended functions of the control building HVAC system within the scope of license renewal 

include the following:

• to provide a suitable environment for Class 1E electrical equipment under normal 

conditions and DBEs

• to support habitability of the control building
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-49

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements

LRA Table 2.3.3-11 identifies the control building HVAC system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.11.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the control building HVAC system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR, as required by 

10 CFR 54.21(a)(1). 

2.3.3.12 Essential Service Water Pumphouse HVAC System 

2.3.3.12.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.12 states that the purpose of the ESW pumphouse HVAC system is to 

provide a suitable environment for operation of the safety-related ESW pump motors and 

associated electrical equipment. The ESW pumphouse HVAC system also provides a suitable 

environment for operation of the safety-related electrical equipment associated with the UHS 

cooling tower fans.

The intended functions of the ESW pumphouse HVAC system within the scope of license 

renewal include the following:

• to provide a suitable environment for operation of the ESW pumps and the electrical 

equipment associated with the UHS cooling tower fans 

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) requirements based on the criteria of 

10 CFR 54.4(a)(3)

LRA Table 2.3.3-12 identifies the ESW pumphouse HVAC system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-50

2.3.3.12.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the ESW pumphouse HVAC system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.13 Auxiliary Building HVAC System

2.3.3.13.1 Summary of Technical Information in the Application

LRA Section 2.3.3.13 states that the purpose of the auxiliary building HVAC system is to 

maintain a suitable environment for safety-related equipment under normal conditions and 

DBEs. The auxiliary building HVAC system process airborne particulates in the auxiliary 

building and exhaust the air from the containment.

The intended functions of the auxiliary building HVAC system within the scope of license 

renewal include the following:

• to provide isolation of the auxiliary building and maintain a suitable environment for 

safety-related equipment in the auxiliary building under normal conditions and DBEs

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements based 

upon the criteria of 10 CFR 54.4(a)(3)

LRA Table 2.3.3-13 identifies the auxiliary building HVAC system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.13.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concluded that the applicant 

appropriately identified the auxiliary building HVAC system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-51

2.3.3.14 Fuel Building HVAC System

2.3.3.14.1 Summary of Technical Information in the Application

LRA Section 2.3.3.14 states that the purpose of the fuel building HVAC system is to provide 

conditioned outside air to the fuel building for ventilation, cooling, or heating. 

The intended functions of the fuel building HVAC system within the scope of license renewal 

include the following:

• to provide a suitable environment for the operation of the safety-related spent fuel pool 

cooling pumps

• to isolate the fuel building HVAC and provide a flow path for the control of radioactivity 

release during a fuel handling accident

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) requirements based on the criteria of 

10 CFR 54.4(a)(3)

LRA Table 2.3.3-14 identifies the fuel building HVAC system component types within the scope 

of license renewal and subject to an AMR.

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.14.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the fuel building HVAC system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the fuel building system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.3.3.15 Miscellaneous Building HVAC System

2.3.3.15.1 Summary of Technical Information in the Application

LRA Section 2.3.3.15 states that the purpose of the miscellaneous buildings HVAC system is to 

provide conditioned outside air to the tendon access gallery for cooling or heating and to provide 

outside air to the main steam enclosure building for ventilation and cooling or heating. The 

miscellaneous buildings HVAC system provides a suitable atmosphere for personnel and 

equipment within the access tunnel and auxiliary boiler room and for the electric motor drivers 

and safety-related motor driven auxiliary feedwater pumps within the auxiliary feedwater pump 

room. The miscellaneous buildings HVAC system also provides heating for the RWST valve 

house, the reactor makeup water storage tank valve house, and the condensate and 

demineralized water pipe tunnels.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-52

The intended functions of the miscellaneous buildings HVAC system within the scope of license 

renewal include the following:

• to provide a suitable environment for the electric motor drivers in the motor-driven 

auxiliary feedwater pump rooms 

• to provide the capability to isolate HVAC system penetrations of the auxiliary building 

boundary 

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements 

LRA Table 2.3.3-15 identifies the miscellaneous buildings HVAC system component types 

within the scope of license renewal and subject to an AMR.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.15.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the miscellaneous buildings HVAC system mechanical components 

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR, in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.16 Diesel Generator Building HVAC System

2.3.3.16.1 Summary of Technical Information in the Application

LRA Section 2.3.3.16.1 states that the purpose of the diesel generator building HVAC system is 

to provide combustion air and cooling for the diesel generators. 

The intended functions of the diesel generator building HVAC system within the scope of license 

renewal are to provide combustion air and a suitable environment to the diesel generators 

during DBEs and to support fire protection (10 CFR 50.48) requirements.

LRA Table 2.3.3-16 identifies the diesel generator building HVAC system component types 

within the scope of license renewal and subject to an AMR.

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-53

2.3.3.16.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the diesel generator building HVAC system mechanical components 

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR, in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.17 Radwaste Building HVAC System

The NRC staff issued Callaway License Amendment 206 by letter dated January 13, 2014, 

which authorizes the applicant to implement a new risk-informed, performance-based Fire 

Protection program based upon 10 CFR 50.48(c) and National Fire Protection Association 

(NFPA) 805, “Performance-Based Standard for Fire Protection for Light Water Reactor Electric 

Generating Plants, 2001 Edition” (NFPA 805). As a result of this license amendment, the 

radwaste building HVAC system is deleted from the scope of license renewal. On the basis of 

its review, the staff concludes that the deletion is acceptable.

2.3.3.18 Turbine Building HVAC System

2.3.3.18.1 Summary of Technical Information in the Application

LRA Section 2.3.3.18 states that the purpose of the turbine building HVAC system is to provide 

outside air for heating, ventilation, and cooling for portions of the turbine building and the 

communication corridor. The turbine building HVAC system also provides isolation of the 

auxiliary building following a DBE.

The intended functions of the turbine building HVAC system within the scope of license renewal 

are to provide capability to isolate HVAC system penetrations of the auxiliary building boundary 

following a DBE and to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) 

requirements.

LRA Table 2.3.3-18 identifies the turbine building HVAC system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.18.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the turbine building HVAC system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR, as required by 

10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-54

2.3.3.19 Containment Cooling System

2.3.3.19.1 Summary of Technical Information in the Application

LRA Section 2.3.3.19 states that the purpose of the containment cooling system is to maintain a 

suitable environment for equipment within the containment during normal operation and to 

remove heat and provide mixing of the containment atmosphere to prevent pockets of hydrogen 

from forming during DBEs.

The intended functions of the containment cooling system within the scope of license renewal 

include the following:

• to provide containment isolation, heat removal, and a suitable containment atmosphere

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements 

LRA Table 2.3.3-19 identifies the containment cooling system component types within the 

scope of license renewal and subject to an AMR.

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.19.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant has 

appropriately identified the containment cooling system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.20 Fire Protection System

2.3.3.20.1 Summary of Technical Information in the Application

LRA Section 2.3.3.20 states that the purpose of the fire protection system is to detect, alarm, 

control, and extinguish any fire that might occur within the plant area. Fire detection devices are 

provided throughout the plant area to detect fire, alert the control room operators, and activate

fire alarms. Personnel alarms are provided in areas where toxic inert gas is used for fire 

protection. The fire protection system also supports the safe shutdown of the plant by 

minimizing the effects of fire on plant SSCs important to safety.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-55

The intended functions of the fire protection system within the scope of license renewal include 

the following:

• to support containment pressure boundary

• to maintain integrity of nonsafety-related SSCs such that no physical interaction with 

safety-related SSCs could prevent satisfactory accomplishment of a safety-related 

function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to perform functions that demonstrate compliance with NRC regulations for fire 

protection (10 CFR 50.48) 

LRA Table 2.3.3-20 identifies the fire protection system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20; FSAR Section 9.5.1, Appendices 9.5A and 9.5B; and

license renewal boundary drawings using the evaluation methodology described in SER 

Section 2.3 and guidance in SRP-LR Section 2.3. During its review, the staff evaluated the 

system functions described in the LRA and FSAR to verify that the applicant had not omitted 

from the scope of license renewal any components with intended functions in accordance with 

10 CFR 54.4(a). The staff then reviewed those components that the applicant identified as 

within the scope of license renewal to verify that the applicant had not omitted any passive or 

long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).

The staff also reviewed the following fire protection documents cited in the CLB listed in 

Callaway Operating License Condition 2.C(5):

• NUREG-0830, “Safety Evaluation Report Related to the Operation of Callaway Plant, 

Unit No 1,” October 1981

• NUREG-0830, Supplement No 3, “Safety Evaluation Report Related to the Operation of 

Callaway Plant, Unit No. 1,” May 1984

Based on the documents above, the staff reviewed Callaway compliance to 10 CFR 50.48, “Fire 

protection” (i.e., approved Fire Protection Program). The review consisted of a point-by-point 

comparison with Appendix A to the Branch Technical Position Chemical and Mechanical 

Engineering Branch 9.5-1, “Guidelines for Fire Protection for Nuclear Power Plants,” Revision 2, 

July 1981, documented in the Standardized Nuclear Unit Power Plant System (SNUPPS) FSAR 

Section 9.5.1, Appendices 9.5A and 9.5B.

During its review of LRA Section 2.3.3.20, the staff identified areas for which additional 

information was necessary to complete its review of the applicant’s scoping and screening 

results.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-56

The staff noted that license renewal boundary drawings LR-CW-KC-M-22KC01 and 

LR-CW-KC-M-22KC02 show the following fire water systems or components as not within the 

scope of license renewal (i.e., not colored in green):

Table 2.3-1 Fire Water Systems or Components Not within the Scope of License Renewal

LRA Drawing Systems and Components Location

LR-CW-KC-M-22KC01 Turbine Generator Bearing A4

North Area Below Turbine (El. 2000’-0”) C5

North Area Below Turbine (El. 2033’-0”) C4

Unit 1 Auxiliary Transformer XMA02 D2

Main Transformers (3) XMA01A ø A, XMA01B ø B, 

and XMA01C ø C

F2

Station Service Transformers XPB03 and XPB04 H5

Condenser Pit A6

South Area Below Turbine (El. 2000’-0”) D7

South Area Below Turbine (El. 2033’-0”) A7

Hydrogen Seal Oil Unit D2

LR-CW-KC-M-22KC02 Auxiliary Boiler Room A2

By letter dated June 11, 2012, the staff issued RAI 2.3.3.20-1 requesting that the applicant 

verify whether the fire water systems and components listed above are within the scope of 

license renewal in accordance with 10 CFR 54.4(a), and subject to an AMR in accordance with 

10 CFR 54.21(a)(1). If water systems and components were excluded from the scope of license 

renewal and not subject to an AMR, the staff requested that the applicant provide justification for 

the exclusion. 

In its response letter dated July 2, 2012, the applicant stated that the fire water suppression 

systems for the main, station service, and unit auxiliary transformers are not within the scope of

license renewal and are not subject to an AMR because these transformers are 50 ft away from 

the building containing safety-related systems. The applicant also cited NUREG-0830, “Safety 

Evaluation Report related to the operation of Callaway Plant, Unit No. 1,” Section 7.4, “Systems 

Required for Safe Shutdown,” as stating the following:

The onsite power system is provided with preferred power from the offsite system 

through two independent and redundant sources of power. The Class 1E AC 

system loads required to maintain the plant at safe shutdown or to mitigate the 

consequences of an accident are separated into two load groups. These are 

powered from separate ESF transformers when offsite power is available or from 

two independent diesel generators (one per load group) when offsite power is not 

available.

In its response to RAI 2.3.3.20-1 regarding outside oil filled transformer fire suppression 

systems, the applicant stated that the outside oil filled transformers are located 15.2 m (50 ft)

away from buildings containing safety-related systems, and satisfy the Appendix A to branch 

technical position APCSB 9.5-1 requirements for spatial separation distance. Based on its 

review, the staff finds the applicant’s response acceptable because it clarifies that the main, 

station service and unit auxiliary transformers’ fire suppression systems and their associated 

components have no license renewal intended functions. The staff reviewed the Callaway 

response to branch technical position APCSB 9.5-1, Position D.1(h), that the outside oil-filled 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-57

transformers are 15.2 m (50 ft) away from the buildings containing safety-related systems. 

Therefore, the staff finds that a fire from the outdoor transformers cannot affect safety-related 

equipment and that the fire suppression systems for the outside transformers were correctly 

excluded from the scope of license renewal and not subject to an AMR. The staff’s concern for 

this portion of the RAI is resolved.

For the auxiliary boiler room fire suppression system, the applicant stated that the auxiliary 

boiler room is separated from adjoining safe-shutdown areas by 3-hour-rated fire barriers and 

contains no post-fire safe-shutdown equipment, circuits, or safety-related equipment. 

Therefore, the fire water suppression system for the auxiliary boiler room is not within the scope 

for license renewal and not subject to an AMR.

In evaluating this response, the staff found that it was incomplete and that review of a portion of 

LRA Section 2.3.3.20 could not be completed. The applicant responded to the RAI by removing 

the auxiliary boiler room fire suppression system and components from the scope of license 

renewal as not being subject to an AMR. The staff finds this contrary to the FSAR, which 

includes the original Callaway fire protection safety evaluation, NUREG-0830, “Safety 

Evaluation Report related to the Operation of Callaway Plant, Unit No. 1,” dated October 1981, 

as the CLB. 

The staff, therefore, does not agree with the applicant’s proposed change to exclude the 

auxiliary boiler room fire suppression system and components from the scope of license 

renewal, as stated in 10 CFR 54.4(a)(3), because it is required for compliance with 

10 CFR 50.48 and, therefore, subject to an AMR pursuant to 10 CFR 54.21(a)(1). Additionally, 

the aging management program (AMP) must demonstrate that the aging effects associated with 

the fire protection system components, if in scope, are adequately managed so that there is 

reasonable assurance that the system components will perform their intended function(s) in 

accordance with the CLB during the period of extended operation, as required by 10 CFR 

50.21(a)(3).The staff finds that the auxiliary boiler room fire suppression system and 

components should not be excluded on the basis that they are not required to function to 

suppress a fire or are not required for compliance with 10 CFR 50.48, without considering the 

CLB. Therefore, the staff identified its concern for this portion of RAI 2.3.3.20-1 as part of Open 

Item 2.3.3.20-1, Part (a).

By letter dated March 29, 2013, the staff issued followup RAI 3.3.2.20-1a, requesting that the 

applicant provide additional information on its basis to exclude from the scope of license 

renewal those SSCs in the fire suppression systems associated with the auxiliary boiler room. 

The staff further requested that, if the auxiliary boiler room fire suppression system SSCs are 

within the scope of license renewal, then the LRA and boundary drawing should be revised 

accordingly.

In a letter dated April 29, 2013, the applicant responded to RAI 2.3.3.20-1a and stated the 

auxiliary boiler room fire suppression system had been added to the Boundary 

Drawing LR-CW-KC-M-22KC02.

Based on its review, the staff finds the applicant’s response acceptable because it clarifies that 

the auxiliary boiler room fire suppression system in question is required to meet the scoping 

criteria of 10 CFR 54.4(a)(3) and is required for compliance with 10 CFR 50.48. The applicant 

included the auxiliary boiler room fire suppression system within the scope of license renewal 

and updated its license renewal documents. The staff’s concern described in this portion of 

RAI 2.3.3.20-1a is resolved.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-58

In its response dated April 29, 2013, the applicant stated that, for the turbine building north area 

below turbine deck (El. 2000’-0”), north area below turbine deck (El. 2033’-0”), south area below 

turbine deck (El. 2000’-0”), and south area below turbine deck (El. 2033’-0”), there was no 

post-fire safe shutdown or safety-related equipment in the turbine building. The applicant stated 

that the fire water suppression systems for these turbine building locations were installed as a 

“good practice” for loss prevention and property protection only and were not required to meet 

the criteria of 10 CFR 50.48. Therefore, the applicant concluded that the fire water suppression 

systems for these areas of the turbine building were not within the scope of license renewal and 

not subject to an AMR.

In evaluating this response, the staff found that it was incomplete and that review of a portion of 

LRA Section 2.3.3.20 could not be completed. The applicant responded to the RAI by removing 

the fire suppression systems and components in the north area below the turbine deck at 

Elevations 2000’-0” and 2033’-0” and south area below the turbine deck at Elevations 2000’-0”

and 2033’-0” in the turbine building from the scope of license renewal as not being subject to an 

AMR. The applicant further stated that the turbine building does not contain post-fire 

safe-shutdown equipment and a fire in the turbine building will not prevent plant safe-shutdown. 

Furthermore, the applicant stated that the fire suppression systems in question are for insurance 

and property protection purposes. The staff finds this contrary to the FSAR which includes the 

original Callaway fire protection Safety Evaluation NUREG-0830, dated October 1981, as the 

CLB. 

The staff, therefore, does not agree with the applicant’s proposed change to exclude the above 

turbine building fire suppression systems and components from scope, as stated in 

10 CFR 54.4(a)(3), because they are required for compliance with 10 CFR 50.48 and, therefore, 

subject to an AMR pursuant to 10 CFR 54.21(a)(1). Additionally, the AMP must demonstrate 

that the aging effects associated with the fire protection system components, if in scope, are 

adequately managed, so that there is reasonable assurance that the system components will 

perform their intended function(s) in accordance with the CLB during the period of extended 

operation as required by10 CFR 50.21(a)(3). The turbine building fire suppression systems and 

components in question should not be excluded on the basis that they are not required to 

function to suppress a fire or are not required for compliance to 10 CFR 50.48 and Appendix R, 

without considering the CLB. Therefore, the staff identified its concern for this portion of 

RAI 2.3.3.20-1 as part of Open Item 2.3.3.20-1, Part (a).

By letter dated March 29, 2013, the staff issued follow-up RAI 3.3.2.20-1a, requesting that the 

applicant provide additional information on its basis to exclude from the scope of license 

renewal those SSCs in the fire suppression systems in the north area below turbine deck at 

Elevations 2000’-0” and 2033’-0” and south area below turbine deck at Elevations 2000’-0” and 

2033’-0” in the turbine building. The staff further requested that, if these fire suppression 

systems SSCs are within the scope of license renewal, then revise the LRA and boundary 

drawing accordingly.

In a letter dated April 29, 2013, the applicant responded to RAI 2.3.3.20-1a and stated fire 

suppression systems in the north area below turbine deck at Elevations 2000’-0” and 2033’-0”

and south area below turbine deck at Elevations 2000’-0” and 2033’-0” in the turbine building

added to the Boundary Drawings LR-CW-KC-M-22KC01, LR-CW-KC-M-22KC08, and 

LR-CW-KC-M-22KC09. Further, the applicant stated that LRA Section 2.3.3.20 was revised as 

shown in LRA Amendment 24 in Enclosure 2 to add a new boundary drawing for the fire 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-59

protection system located in the turbine building. LRA Section 3.3.2.1.20 and Table 3.3.2-20 

have also been revised as shown in LRA Amendment 24, Enclosure 2, to add the following:

• Selective leaching as an aging effect for copper alloy fire protection system components 

with greater than 15 percent zinc.

• Aging management of copper alloy fire protection system components with greater than 

15 percent zinc by the Selective Leaching program (B2.1.19) and Fire Water System 

program (B2.1.14)

• Aging management of carbon steel flow orifices 

Based on its review, the staff finds the applicant’s response acceptable because it clarifies that 

the turbine building fire suppression system in question is required to meet the scoping criteria 

of 10 CFR 54.4(a)(3) and is required for compliance with 10 CFR 50.48. The applicant has 

included the turbine building fire suppression system within the scope of license renewal and 

updated its license renewal document. The staff’s concern described in this portion of 

RAI 2.3.3.20-1a is resolved.

For the turbine generator bearing, condenser pit, and hydrogen seal oil unit fire suppression 

systems, the applicant stated that these areas are separated from the adjacent auxiliary building 

by 3-hour-rated fire barrier walls. The applicant also stated that fire suppression systems and 

components in question are not within the scope of license renewal and subject to an AMR

because these areas do not contain post-fire safe-shutdown equipment, and a fire in this area 

will not prevent safe shutdown.

In evaluating this response, the staff found that it was incomplete and that review of a portion of 

LRA Section 2.3.3.20 could not be completed. The applicant responded to the RAI by removing 

the turbine generator bearing, condenser pit, and hydrogen seal oil unit fire suppression 

systems and components from the scope of license renewal as not being subject to an AMR. 

The applicant further stated that the turbine generator bearing, condenser pit, and hydrogen 

seal oil unit do not contain post-fire safe-shutdown equipment and a fire in these areas will not 

prevent plant safe-shutdown. The staff finds this contrary to the FSAR, which includes the 

original Callaway fire protection safety evaluation NUREG-0830, dated October 1981, as the 

CLB. 

The staff, therefore, does not agree with the applicant’s proposed change to exclude the above 

fire suppression systems and components from the scope of license renewal as stated in 

10 CFR 54.4(a)(3) because they are required for compliance with 10 CFR 50.48 and, therefore, 

subject to an AMR pursuant to 10 CFR 54.21(a)(1). Additionally, the AMP must demonstrate 

that the aging effects associated with the fire protection system, if in scope, are adequately 

managed so that there is reasonable assurance that the system components will perform their 

intended function(s) in accordance with the CLB during the period of extended operation, as 

required by 10 CFR 50.21(a)(3). The turbine generator bearing, condenser pit, and hydrogen 

seal oil unit fire suppression systems and components in question should not be excluded on 

the basis that they are not required to function to suppress a fire or are not required for 

compliance with 10 CFR 50.48, and Appendix R, without considering the CLB. The staff found

the proposed changes to the Callaway-approved fire protection system to be unacceptable. 

Therefore, the staff identified its concern as part of Open Item 2.3.3.20-1, Part (a).

By letter dated March 29, 2013, the staff issued followup RAI 3.3.2.20-1a, requesting that the 

applicant provide additional information on its basis to exclude from the scope of license 

renewal those SSCs in the fire suppression systems associated with the turbine generator 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-60

bearing, condenser pit, and hydrogen seal oil unit. The staff further requested that, if these fire 

suppression systems SSCs are within the scope of license renewal, then the LRA and boundary 

drawing should be revised accordingly.

In a letter dated April 29, 2013, the applicant responded to RAI 2.3.3.20-1a and stated the 

turbine generator bearing, condenser pit, and hydrogen seal oil unit fire suppression systems 

have been added to the Boundary Drawings LR-CW-KC-M-22KC01, LR-CW-KC-M-22KC08, 

and LR-CW-KC-M-22KC09.

Based on its review, the staff finds the applicant’s response acceptable because it clarifies that 

the turbine generator bearing, condenser pit, and hydrogen seal oil unit fire suppression 

systems in question are required to meet the scoping criteria of 10 CFR 54.4(a)(3) and are 

required for compliance with 10 CFR 50.48. The applicant has included the turbine generator 

bearing, condenser pit, and hydrogen seal oil unit fire suppression systems within the scope of 

license renewal and updated its license renewal document. The staff’s concern described in 

this portion of RAI 2.3.3.20-1a is resolved. 

The staff’s concerns in RAI 2.3.3.20-1(a) are resolved, and Open Item 2.3.3.20-1, Part (a) is 

closed.

By letter dated June 11, 2012, the staff issued RAI 2.3.3.20-2, requesting the applicant to 

determine if LRA Tables 2.3.3-20 and 3.3.2-20 should include the following fire protection 

components:

• fire hose connections and hose racks

• sprinklers

• diesel fire pump heat exchanger (bonnet, shell, and tubes)

• lubricating oil collection system components for each RCP

• floor drains and curbs for fire-fighting water

• dikes for oil spill confinement

• sprinkler system water curtain in the auxiliary building equipment hatchway

• filter housing

• diesel generator room roof heat vents 

The staff requested that the applicant verify if the fire protection systems and components listed 

above are within the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to 

an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license 

renewal and are not subject to an AMR, the staff requested that the applicant provide 

justification for the exclusion.

In its response letter dated July 2, 2012, the applicant provided the results of the scoping and 

screening for the listed fire protection component types as follows:

Fire Hose Connections and Hose Racks:

Fire hose connections and hose racks are evaluated as the component type 

“hose station.” LRA Table 2.3.3-20 identifies hose stations as components within 

the scope of license renewal and subject to an AMR. The [AMR] for hose station 

components is provided in LRA Table 3.3.2-20.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-61

Sprinklers:

Sprinklers are evaluated as the component type “spray nozzle.” LRA 

Table 2.3.3-20 identifies spray nozzles as components within the scope of 

license renewal and subject to an AMR. The [AMR] for spray nozzle components 

is provided in LRA Table 3.3.2-20.

Diesel Fire Pump Heat Exchanger ([B]onnet, [S]hell, and [T]ubes):

[The] diesel fire pump heat exchanger is evaluated as the component type “heat 

exchanger (DFP jacket water),” which includes a main component and 

subcomponent representing the shell and tubes, respectively. Channels, 

channel covers, and bonnets are included as part of the heat exchanger 

subcomponent type shell. LRA Table 2.3.3-20 identifies heat exchanger (DFP 

jacket water) [...] components [as] within the scope of license renewal and 

subject to an AMR. The [AMR] for the heat exchanger (DFP jacket water) 

components is provided in LRA Table 3.3.2-20.

Lubricating [O]il [C]ollection [S]ystem [C]omponents for each [R]eactor [C]oolant 

[P]ump:

The system description in LRA Section 2.3.3.27 for the floor and equipment 

drainage system includes reactor coolant lubricating oil drain tanks for the [RCP]

lubricating oil collection system. LRA Table 2.3.3-27 identifies piping, valves, 

splash guards, and tanks of the RCP lubricating oil collection system as 

components within the scope of license renewal and subject to an AMR. The 

AMR for components associated with the [RCP] lubricating oil collection system 

is provided in LRA Table 3.3.2-27.

Floor Drains and Curbs for Fire-Fighting Water:

Floor drains for fire-fighting water are evaluated as the component type “piping.”

LRA Tables 2.3.3-26 (oil waste system) and 2.3.3-27 (floor and equipment 

drainage system) identify piping (floor drains) as components within the scope of 

license renewal and subject to an AMR. The AMR for piping (floor drains) is 

provided in LRA Tables 3.3.2-26 and 3.3.2-27.

Curbs for fire-fighting water are evaluated as part of the component type 

“concrete elements” with a “flood barrier” or “direct flow” function(s) assigned to 

them. LRA Tables 2.4-2 ([c]ontrol [b]uilding), 2.4-3 ([a]uxiliary [b]uilding), and 

2.4-5 ([d]iesel [g]enerator [b]uilding) identify concrete elements (curbs for 

fire-fighting water) as components within the scope of license renewal and 

subject to an AMR. The [AMR] for concrete elements associated with curbs for 

fire-fighting water is provided in LRA Table 3.5-1.

Dikes for Oil Spill Confinement:

[...] Dikes for oil spill confinement are evaluated as part of the component type 

“concrete elements” with a “structural pressure boundary” function assigned to 

them. LRA Tables 2.4.3 ([a]uxiliary [b]uilding) and 2.4.5 ([d]iesel [g]enerator 

[b]uilding) identify concrete elements (dikes for oil spill confinement) as 

components within the scope of license renewal and subject to an AMR. The 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-62

[AMR] for concrete elements associated with dikes for oil spill confinement is 

provided in LRA Table 3.5-1.

Sprinkler System Water Curtain for the Auxiliary Building Equipment Hatchway:

[...] Sprinkler system water curtains for the [a]uxiliary [b]uilding [e]quipment 

[h]atchways are evaluated as component types “valve,” “piping,” and “spray 

nozzle.” LRA Table 2.3.3-20 identifies components associated with the sprinkler 

system water curtain to be within the scope of license renewal and subject to an 

AMR. The [AMR] for the components associated with the sprinkler system water 

curtains for the auxiliary building hatchways are provided in LRA Table 3.3.2-20.

Filter Housing:

Filter housings are evaluated as the component type “filter.” LRA Table 2.3.3-20 

identifies filters as components within the scope of license renewal and subject to 

an AMR. The [AMR] of filters is provided in LRA Table 3.3.2-20.

Diesel Generator Room Roof Heat Vents:

[...] The exhaust air flow path is evaluated as part of the component types 

“damper,” “ductwork,” and “louvers (evaluated as structural steel components).” 

LRA Table 2.3.3-16 (diesel generator building HVAC system) identifies the fan 

and ductwork components associated with the exhaust air flow path as 

components within the scope of license renewal and subject to an AMR. LRA 

Table 2.4-5 (diesel generator building) identifies the louver (structural steel) 

components associated with the exhaust air flow path as components within the 

scope of license renewal and subject to an AMR. The AMR for components 

associated with the exhaust air flow path is provided in LRA Table 3.3.2-16 and 

LRA Table 3.5.2-5.

In reviewing its response to the RAI, the staff found that the applicant had addressed and 

resolved each item in the RAI, as discussed in the following paragraphs. 

Although the description of the “hose station” line item provided in LRA Table 2.3.3-20 does not 

list these components specifically, the applicant stated that it considers this line item to include 

the fire hose connection and hose racks. LRA Table 3.3.2-20 provides the AMR results of these 

components.

In its response, the applicant also confirmed that “sprinklers” are included in component type 

“spray nozzle” in LRA Table 2.3.3-20, with AMR results provided in LAR Table 3.3.2-20. 

The applicant indicated that the diesel fire pump heat exchanger (bonnet, shell, and tubes) is 

included in the category of “heat exchanger (DFP jacket water).” This line item is included in 

LRA Table 2.3.3-20, with the AMR results provided in LRA Table 3.3.2-20. 

The lubricating oil collection system is addressed in LRA Section 2.3.3.27 and LRA 

Table 2.3.3-27, which identify this as components within the scope of license renewal and 

subject to an AMR, with the AMR results provided in LRA Table 3.3.2-27. 

The floor drains are included in LRA Tables 2.3.3-26 and 2.3.3.27 under component type 

“piping,” with the AMR results provided in LRA Tables 3.3.2-26 and 3.3.2-27. Curbs are 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-63

included in the structural component type “concrete elements” in LRA Tables 2.4-2, 2.4-3, and 

2.4-5, with the AMR results provided in LRA Table 3.5-1. 

In addition, the applicant indicated that the dikes for oil spill confinement are included in the 

structural AMR under component type “concrete elements” in LRA Tables 2.4-3 and 2.4-5, with 

the AMR results provided in LRA Table 3.5-1.

The sprinkler system water curtain in the auxiliary building equipment hatchway is included in 

component types “valve,” “piping,” and spray nozzle,” in LRA Table 2.2.3-20 with the AMR 

results provided in LRA Table 3.3.2-20.

The applicant confirmed that the filter housings are subject to an AMR under component type 

“filter.” The filter housing is listed in LRA Tables 2.3.3-20 and 3.3.2-20 in the “filter” component 

type.

The applicant confirmed that the diesel generator building exhaust flow components are within 

the scope of license renewal and subject to an AMR. LRA Table 2.3.3-16 identifies components 

associated with the diesel generator building exhaust flow path with the AMR results in LRA 

Tables 33.2-16 and 3.5.2-5.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.20-2 acceptable 

because the applicant provided clarification that the fire protection system and components 

listed above are within the scope of license renewal and subject to an AMR as required by 

10 CFR 54.4(a) and 54.21(a)(1) respectively. The staff’s concern described in RAI 2.3.3.20-2 is 

resolved.

By letter dated August 29, 2011, the applicant submitted a license amendment request (LAR) to 

transition the existing Fire Protection Program for Callaway to a risk-informed, 

performance-based program based on National Fire Protection Association Standard 805 

(NFPA 805), “Performance-Based Standard for Fire Protection for Light Water Reactor Electric 

Generating Plants,” 2001 Edition, in accordance with 10 CFR 50.48(c). Subsequent to the 

NFPA 805 LAR the applicant submitted to the staff, by letter dated December 15, 2011, an 

application for renewal of Operating License NPF-30 for Callaway.

It is unclear to the staff if there are Fire Protection Program plant modifications planned for 

transition to NFPA 805 that affect the existing Fire Protection Program and SSCs for license 

renewal. By letter dated June 11, 2012, the staff issued RAI 2.3.3.20-3, requesting that the 

applicant identify and discuss the changes associated with the NFPA 805 transition and their 

effect on LRA Tables 2.3.3-20 and 3.3.2-20. In addition, the staff requested that the applicant 

provide a gap analysis of Tables 2.3.3-20 and 3.3.2-20 of the LRA identifying any differences 

between the existing plant configuration and NFPA 805 post-transition configuration. The staff 

requested that the applicant summarize the results and the impacts of these gaps on the Fire 

Protection Program described in LRA Tables 2.3.3-20 and 3.3.2-20. The staff also requested a 

list of the fire protection SSCs, including, but not limited to, structural fire barriers (e.g., fire walls 

and slabs, fire doors, fire barrier penetration seals, fire dampers, fire barrier coatings and wraps, 

equipment and personnel hatchways and plugs, and metal siding), which will be added or 

removed, based on the NFPA 805 transition, from 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).

In its response letter dated July 2, 2012, the applicant stated that the Callaway NFPA 805 LAR 

is presently under the staff’s review and is subject to change as a result of those reviews. The 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-64

applicant stated that it plans to perform the requested gap analysis upon issuance of the draft 

NFPA 805 SER. The applicant acknowledged that the staff requires the license renewal gap 

analysis to support development of the SER for license renewal. The applicant revised LRA 

Table A4-1 (LRA Amendment 4) to add Commitment No. 39, which requires the applicant to 

provide a gap analysis of LRA Tables 2.3.3-20 and 3.3.2-20 identifying differences between the 

existing and NFPA 805 post-transition changes before January 11, 2013. If the draft NFPA 805 

SER is not available in Fall 2012, the applicant will provide an alternate schedule to address this 

commitment.

Based on its review, the staff found the applicant’s response to RAI 2.3.3.20-3 only partially 

acceptable because, while it provided Commitment No. 39 which resolved some of the staff’s

concerns regarding the need for a gap analysis, it was only able to provide a proposed schedule 

for the gap analysis between the existing and post-transition fire protection program changes. 

The staff finds that the gap analysis cannot yet be performed. The license renewal Commitment 

No. 39, Table A4-1, provides the schedule for gap analysis of LRA Tables 2.3.3-20 and 3.3.2-20 

to identify differences between the existing and future NFPA 805 post-transition changes. The 

applicant will summarize the results and the impacts of these gaps on the fire protection 

program described in LRA Tables 2.3.3-20 and 3.3.2-20, based on the transition to the 

NFPA 805 nuclear safety capabilities before January 11, 2013, contingent upon the staff issuing 

the draft NFPA 805 LAR SER in Fall 2012. The applicant further stated in Commitment No. 39 

that if the draft NFPA 805 LAR SER is not available in Fall 2012, it will provide an alternate 

schedule to address this commitment.

By letter dated January 10, 2013, the applicant revised Commitment No. 39 schedule with new 

dates to address the staff concern regarding the gap analysis of LRA Tables 2.3.3-20 and 

3.3.2-20 to identify differences between the existing and future NFPA 805 post-transition 

changes. According to the revised schedule, the applicant would summarize the results and the 

impacts of these gaps on the fire protection program described in LRA Tables 2.3.3-20 and 

3.3.2-20, based on the future transition to the NFPA 805 nuclear safety capabilities before 

March 25, 2013, contingent upon the staff issuing the draft NFPA 805 LAR SER in 

February 2013. The applicant further stated in Commitment No. 39 that if the draft NFPA 805 

LAR SER is not available in February 2013, it will provide an alternate schedule to address this 

commitment.

The staff reviewed the applicant’s revised Commitment No. 39 and noted that the applicant 

should not perform its gap analysis of LRA Tables 2.3.3-20 and 3.3.2-20 based on a draft 

NFPA 805 LAR safety evaluation report. Commitment No. 39 should be based on the final 

NFPA 805 LAR safety evaluation report. Therefore, the staff identified this concern as Open 

Item 2.3.3.20-1, Part (b).

The NRC staff issued final NFPA 805 license amendment safety evaluation report 

January 13, 2014 (ADAMS Accession No. ML13274A596), to comply with 10 CFR 50.48(c) and 

the applicant provided its gap analysis (Amendment 31) based on the approved NFPA 805 fire 

protection program by letter dated February 14, 2014. The staff’s initial review found that this 

submittal lacked sufficient details to reach conclusions as to the adequacy of the gap analysis 

and the changes Ameren Missouri would make to the SSCs, the fire protection AMP, as well as 

any other affected AMPs as a result of transition to NFPA 805. The applicant subsequently 

submitted a supplement to its gap analysis (Amendment 33) by letter dated April 15, 2014, with 

additional information and sufficient details based on its NFPA 805 fire protection program.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-65

The staff reviewed the applicant’s NFPA 805 gap analysis for LRA Tables 2.3.3-20 and 3.3.2-20 

and found that it is consistent with the Callaway August 29, 2011, NFPA 805 Transition Report 

and final approved safety evaluation report. The staff noted that the applicant specifically 

removed structural fire barriers (e.g., fire wall and slabs, fire doors, fire barrier penetration seals, 

fire dampers, fire barriers coatings/wraps, equipment/personnel hatchways and plugs, metal 

siding) from the scope of license renewal and cited them as not being subject to an AMR. In 

addition, the staff noted that in LRA Amendment 33, the applicant used its scoping and 

screening methodology from its NFPA 805 fire protection program based on the NFPA 805 

transition report. Only fire protection suppression systems and fire protection features (fire 

barriers) located in risk-significant fire areas are included in the scope of license renewal and 

subject to an AMR. Callaway Transition Report, Table 4-3, “Summary of NFPA 805 Compliance 

Basis and Required Fire Protection Features,” and Attachment C, “Table B-3 Fire Area 

Transition,” provide the compliance basis and fire protection systems and features required to 

meet 10 CFR 50.48(c). 

The staff noted that LRA Amendment 33 (i.e., gap analysis) provides details on the plant water 

supply systems, water-based and gaseous fire suppression systems, and addresses differences 

in the license renewal application between the existing and NFPA 805 post-transition fire 

protection program as reported in the approved NFPA 805 safety evaluation dated 

January 13, 2014. The applicant identified and discussed changes associated with the 

NFPA 805 transition and their effect on LRA Section 2.3.3-20, “Fire Protection System.” 

The staff reviewed the applicant’s revised Commitment No. 39 gap analysis (LRA 

Amendment 33) which compares NFPA 805 and license renewal scope differences by 

identifying SSCs that are not currently within the scope of license renewal and subject to an 

AMR; and SSCs within the scope of license renewal for fire protection, but which are no longer 

required by the NFPA 805 fire protection program. The staff concludes that the applicant 

appropriately identified changes associated with the NFPA 805 transition. 

The staff’s concerns in RAI 2.3.3.20-1(b) are resolved and OI 2.3.3.20-1, Part (b) is closed. 

Therefore, OI 2.3.3.20-1 is closed.

2.3.3.20.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, LRA Amendments 31 and 33, FSAR, RAI responses, and license renewal boundary

drawings, the staff concludes that the applicant has appropriately identified the fire protection 

system components within the scope of license renewal, as required by 10 CFR 54.4(a) and

subject to an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.21 Emergency Diesel Engine Fuel Oil Storage and Transfer System

2.3.3.21.1 Summary of Technical Information in the Application

LRA Section 2.3.3.21 states that the purpose of the emergency diesel engine fuel oil storage 

and transfer system is to provide onsite storage and transfer of fuel oil to the two emergency 

diesel engines. For each diesel engine, there is an underground storage tank capable of 

providing fuel oil for 7 days of operation.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-66

The intended functions of the emergency diesel engine fuel oil storage and transfer system 

within the scope of license renewal include the following:

• to support the capability to safely shut down the reactor and maintain it in a safe 

condition

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements 

LRA Table 2.3.3-21 identifies the emergency diesel engine fuel oil storage and transfer system 

component types within the scope of license renewal and subject to an AMR.

2.3.3.21.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.21 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.21.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review 

of the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the 

applicant has appropriately identified the emergency diesel engine fuel oil storage and 

transfer system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.22 Standby Diesel Generator Engine System

2.3.3.22.1 Summary of Technical Information in the Application

LRA Section 2.3.3.22 states that the purpose of the standby diesel generator engine system is 

to provide standby power for the operation of ESFs and emergency systems during and 

following a reactor shutdown when offsite power is not available. The standby diesel generator 

engine system contains the diesel generator cooling water system, starting system, lubrication 

system, and combustion air intake and exhaust system.

The intended functions of the standby diesel generator engine system within the scope of 

license renewal include the following:

• to provide onsite emergency power for equipment that supports the safe shutdown of the 

reactor and maintains it in a safe shutdown condition

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and SBO (10 CFR 50.63) 

requirements

LRA Table 2.3.3-22 identifies the standby diesel generator engine system component types 

within the scope of license renewal and subject to an AMR.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-67

2.3.3.22.1 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22, FSAR Sections 8.3.1.1.3 SP, 9.5.5 SP, 9.5.6 SP, 

9.5.7 SP, and 9.5.8 SP and the license renewal boundary drawings using the evaluation 

methodology discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

On the basis of its review, the staff identified areas in which additional information was 

necessary to complete the review of the applicant’s scoping and screening results. 

The staff noted license renewal boundary drawings LR-CW-M-22KJ02 and 

LR-CW-M-22KJ05, locations F-8 and H-8, depict turbocharger casings as being within the 

scope of license renewal for 10 CFR 54.4(a)(1). However, the turbocharger casing is not 

listed in LRA Table 2.3.3-22 as a component type subject to an AMR. By letter dated 

June 11, 2012, the staff issued RAI 2.3.3.22-1 requesting the applicant to justify the 

exclusion of the turbocharger casing as a component type from LRA Table 2.3.3-22.

In its response letter dated July 2, 2012, the applicant stated that the component type 

“turbocharger casing” has been added to LRA Table 2.3.3-22 with an intended function of 

“pressure boundary.” The applicant also provided a revision of LRA Table 2.3.3-22 as part 

of its response.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-1 acceptable 

because the component type “turbocharger casing” was added to LRA Table 2.3.3-22 and 

is therefore subject to an AMR as required by 10 CFR 54.21(a)(1). The staff’s concern 

described in RAI 2.3.3.22-1 is resolved.

The staff noted license renewal boundary drawings LR-CW-M-22KJ02 and 

LR-CW-M-22KJ05, location G-7, depict an air pressure supply manifold housings as being 

within the scope of license renewal for 10 CFR 54.4(a)(1). However, the air pressure 

supply manifold housing is not listed in LRA Table 2.3.3-22 as a component type subject to 

an AMR. By letter dated June 11, 2012, the staff issued RAI 2.3.3.22-2 requesting the

applicant to justify the exclusion of the air supply manifold housing as a component type 

from LRA Table 2.3.3-22.

In its response letter dated July 2, 2012, the applicant stated that the air pressure supply 

manifold housings were evaluated as component type “piping,” with an intended function of 

“pressure boundary” in LRA Table 2.3.3-22.

Based on its review, the staff finds the applicant’s response to RAI 2.3.22-2 acceptable 

because the air pressure supply manifold housings were evaluated as component type 

“piping” in LRA Table 2.3.3-22 and are therefore subject to an AMR as required by 

10 CFR 54.21(a)(1). The staff’s concern described in RAI 2.3.3.22-2 is resolved.

The staff noted license renewal boundary drawings LR-CW-M-22KJ02 and 

LR-CW-M-22KJ05, locations A-6 and C-6, depict pulsation dampers as being within the 

scope of license renewal for 10 CFR 54.4(a)(2). However, the pulsation damper is not 

listed in LRA Table 2.3.3-22 as a component type subject to an AMR. By letter dated 

June 11, 2012, the staff issued RAI 2.3.3.22-3 requesting the applicant to justify the 

exclusion of the pulsation damper as a component type from LRA Table 2.3.3-22.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-68

In its response letter dated July 2, 2012, the applicant stated that the pulsation dampers 

were evaluated as component type “tank” with intended functions of “leakage boundary 

(spatial)” and “structural integrity (attached)” in LRA Table 2.3.3-22.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-3 acceptable 

because the pulsation dampers were evaluated as component type “tank” in LRA 

Table 2.3.3-22 and are therefore subject to an AMR as required by 10 CFR 54.21(a)(1). 

The staff’s concern described in RAI 2.3.3.22-3 is resolved.

The staff noted license renewal boundary drawings LR-CW-M-22KJ03 and 

LR-CW-M-22KJ06, location F-4, depict lube oil ejector casings as being within the scope of 

license renewal for 10 CFR 54.4(a)(1). However, the lube oil ejector casing is not listed in 

LRA Table 2.3.3-22 as a component type subject to an AMR. By letter dated 

June 11, 2012, the staff issued RAI 2.3.3.22-4 requesting the applicant to justify the 

exclusion of the lube oil ejector casing as a component type from LRA Table 2.3.3-22.

In its response letter dated July 2, 2012, the applicant stated that the lube oil ejector 

casings were evaluated as component type “pump” with an intended function of “pressure 

boundary” in LRA Table 2.3.3-22.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-4 acceptable 

because the lube oil ejector casings were evaluated as component type “pump” in LRA 

Table 2.3.3-22 and are therefore subject to an AMR as required by 10 CFR 54.21(a)(1). 

The staff’s concern described in RAI 2.3.3.22-4 is resolved.

The staff noted license renewal boundary drawings LR-CW-M-22KJ03 and 

LR-CW-M-22KJ06, location F-5, depict oil separator casings as being within the scope of 

license renewal for 10 CFR 54.4 (a)(1). However, the oil separator casing is not listed in 

LRA Table 2.3.3-22 as a component type subject to an AMR. By letter dated 

June 11, 2012, the staff issued RAI 2.3.3.22-5 requesting the applicant to justify the 

exclusion of the oil separator casing as a component type from LRA Table 2.3.3-22.

In its response letter dated July 2, 2012, the applicant stated that the oil separator casings 

were evaluated as component type “filter” with an intended function of “pressure boundary” 

in LRA Table 2.3.3-22.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-5 acceptable 

because the oil separator casings were evaluated as component type “filter” in LRA 

Table 2.3.3-22 and is therefore subject to an AMR as required by 10 CFR 54.21(a)(1). The 

staff’s concern described in RAI 2.3.3.22-5 is resolved.

The staff noted license renewal boundary drawings LR-CW-M-22KJ02 and 

LR-CW-M-22KJ05, location G-3, depict four “XJ” components as being within the scope of 

license renewal for 10 CFR 54.4(a)(1). However, the staff could not identify or review the 

components due to a lack of information of what these components are, what intended 

function(s) they perform, and if they are listed in LRA Table 2.3.3-22 as component types 

subject to an AMR. By letter dated June 11, 2012, the staff issued RAI 2.3.3.22-6

requesting the applicant to identify the “XJ” components and their intended functions, and 

to identify if they were included as component types in LRA Table 2.3.3-22.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-69

In its response dated July 2, 2012, the applicant stated that the “XJ” components were 

evaluated as component type “expansion joint” with an intended function of “pressure 

boundary” in LRA Table 2.3.3-22.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.22-6 acceptable 

because the “XJ” components were evaluated as component type “expansion joint” in LRA 

Table 2.3.3-22 and are therefore subject to an AMR as required by 10 CFR 54.21(a)(1). 

The staff’s concern described in RAI 2.3.3.22-6 is resolved.

2.3.3.22.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, RAI responses, and license renewal boundary drawings, the staff concludes that 

the applicant has appropriately identified the standby diesel generator engine system 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant has adequately identified the system components subject to an 

AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.23 EOF and TSC Diesels, Security Building System

2.3.3.23.1 Summary of Technical Information in the Application

LRA Section 2.3.3.23 states that the purpose of the emergency operations facility (EOF) and 

technical support center (TSC) diesels, security building system is to provide backup power to 

the EOF, TSC, security building, and mechanical equipment supporting nonsafety-related 

buildings.

The intended function of the EOF and TSC diesels, security building system within the scope of 

license renewal is to support SBO (10 CFR 50.63) requirements.

LRA Table 2.3.3-23 identifies the EOF and TSC diesels, security building system component 

types within the scope of license renewal and subject to an AMR.

2.3.3.23.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.23 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.23.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the EOF and TSC diesels, security building system components within 

the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-70

2.3.3.24 Liquid Radwaste System

2.3.3.24.1 Summary of Technical Information in the Application

LRA Section 2.3.3.24 states that the purpose of the liquid radwaste system is to collect, 

segregate, process, and recycle liquid wastes during plant power, refueling, and maintenance 

operations. The liquid radwaste system handles potentially radioactive floor and equipment 

drains, laundry, and chemical waste.

The intended functions of the liquid radwaste system within the scope of license renewal include 

the following:

• to minimize the release of fission products following a loss of coolant or fuel handling 

accident

• to provide part of the safety-related pressure boundary of the CCW system 

• to provide containment isolation

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support EQ (10 CFR 50.49) requirements

LRA Table 2.3.3-24 identifies the liquid radwaste system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.24.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.24 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.24.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review 

of the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the 

applicant has appropriately identified the liquid radwaste system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.25 Decontamination System

2.3.3.25.1 Summary of Technical Information in the Application

LRA Section 2.3.3.25 states that the purpose of the decontamination system is to provide for 

cleaning of contaminated equipment and clothing at the plant. Through a containment 

penetration, the decontamination system introduces steam into the containment for the 

decontamination of areas of the refueling pool and reactor vessel head located within the 

containment. In addition, the decontamination system provides for the decontamination of spent 

fuel shipping casks.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-71

The intended functions of the decontamination system within the scope of license renewal 

include the following:

• to provide containment integrity

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support EQ (10 CFR 50.49) requirements

LRA Table 2.3.3-25 identifies the decontamination system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.25.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.25.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review 

of the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the 

applicant has appropriately identified the decontamination system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.26 Oily Waste System

2.3.3.26.1 Summary of Technical Information in the Application

LRA Section 2.3.3.26 states that the purpose of the oily waste system is to collect, process, and 

dispose of nonradioactive waste water from areas that may contain oil and to collect, process,

and recycle waste water that may contain oil or radioactive contaminants.

The intended functions of the oily waste system within the scope of license renewal are: (1) to 

resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of a 

safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2), and (2) to 

support fire protection (10 CFR 50.48) requirements.

LRA Table 2.3.3-26 identifies the oily waste system component types within the scope of 

license renewal and subject to an AMR.

2.3.3.26.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.26 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.26.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review 

of the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-72

applicant has appropriately identified the oily waste system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant has adequately identified the system components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.27 Floor and Equipment Drainage System

2.3.3.27.1 Summary of Technical Information in the Application

LRA Section 2.3.3.27 states that the purpose of the floor and equipment drainage system is to 

collect, monitor, properly direct, process, and dispose of liquid waste generated within the plant. 

The floor and equipment drainage system also contains and drains away any leakage of RCP

lubricating oil.

The intended functions of the floor and equipment drainage system within the scope of license 

renewal include the following:

• to support the functions of containment integrity and the maintenance of vital auxiliary 

SCs

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48) and EQ (10 CFR 50.49) requirements

LRA Table 2.3.3-27 identifies the floor and equipment drainage system component types within 

the scope of license renewal and subject to an AMR.

2.3.3.27.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.27, FSAR Sections 6.2.4 SP, 9.3.3 SP, and 9.5.1 SP 

and the license renewal boundary drawings using the evaluation methodology discussed in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the 

staff identified an area in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. 

The staff noted license renewal boundary drawing LR-CW-LF-M-22LF01, location H-4, 

depicts A10-XND-“4” piping within the scope of license renewal for 10 CFR 54.4(a)(2). 

However, the continuation from license renewal boundary drawing LR-CW-LF-M-22LF02, 

location A-4, depicts the piping within the scope of license renewal for 10 CFR 54.4(a)(3). 

By letter dated June 11, 2012, the staff issued RAI 2.3.3.27-1 requesting the applicant to 

clarify the scoping classification of the A10-XND-4” piping.

In its response letter dated July 2, 2012, the applicant stated the continuation of the 

A10-XND-“4” piping onto license renewal boundary drawing LR-CW-LR- M-22LF01 was 

incorrectly depicted as being within the scope of license renewal for 10 CFR 54.4(a)(2). The 

applicant also indicated that the A10-XND-“4” piping depicted on license renewal boundary 

drawing LR-CW-LR-M-22LF01 should be within the scope of license renewal for 

10 CFR 54.4(a)(3). The applicant revised the license renewal boundary drawing 

LR-CW-LR-M-22LF01 to depict the A10-XND-“4” piping within the scope of license renewal for 

10 CFR 54.4(a)(3).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-73

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.27-1 acceptable 

because the applicant clarified the scoping classification of the A10-XND-“4” piping as being 

within the scope of license renewal for 10 CFR 54.4(a)(3). The staff reviewed license renewal 

boundary drawing LR-CW-LR- M-22LF01 to confirm that the A10-XND-“4” piping scoping 

classification was revised to 10 CFR 54.4(a)(3). Therefore, the staff’s concern described in 

RAI 2.3.3.27-1 is resolved.

2.3.3.27.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, RAI response, and license renewal boundary drawings, the staff concludes that 

the applicant appropriately identified the floor and equipment drainage system components 

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR, in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.28 Miscellaneous Systems In Scope ONLY for Criterion 10 CFR 54.4(a)(2)

2.3.3.28.1 Summary of Technical Information in the Application

LRA Section 2.3.3.28 states that the following systems were identified as within the scope of 

license renewal only because portions of them consist of nonsafety-related components 

affecting safety-related components based on 10 CFR 54.4(a)(2) criteria: 

• condensate system

• demineralized water makeup system

• condensate and feedwater chemical addition system

• plant heating system

• central chilled water system

• gaseous radwaste system

• solid radwaste system

• boron recycle system

• secondary liquid waste system

• domestic water system

• sanitary drainage system

• roof drains system

• chemical and detergent waste system

Condensate System. LRA Section 2.3.3.28 states that the purposes of the condensate system 

are the following:

• to provide a heat sink for the steam cycle 

• to provide a surge volume and flow collection points for the steam

• to provide for removal of air and non-condensable gasses

• to provide a source of water to the main feedwater pumps

• to provide hood sprays to the turbine exhaust

• to provide cooling to the steam generator blowdown regenerative heat exchanger

• to provide seal water to the condensate and turbine-driven main feedwater pumps 

• to accept and bypass steam flow to the main condenser
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-74

Demineralized Water Makeup System. LRA Section 2.3.3.28 states that the purpose of the 

demineralized water makeup and transfer system is to store water for makeup use and to 

transfer water to diverse components.

Condensate and Feedwater Chemical Addition System. LRA Section 2.3.3.28 states that the 

purpose of the condensate and feedwater chemical addition system is to inject hydrazine and 

ammonia or an alternate amine into the condensate pump discharge and to inject additional 

hydrazine and ammonia into the steam generators main feedwater lines.

Plant Heating System. LRA Section 2.3.3.28 states that the purpose of the plant heating 

system is to provide a medium for heating air to maintain a suitable environment for personnel 

and equipment.

Central Chilled Water System. LRA Section 2.3.3.28 states that the purpose of the central 

chilled water system is to provide a medium for cooling, when required, equipment and 

ventilation system cooling coils.

Gaseous Radwaste System. LRA Section 2.3.3.28 states that the purpose of the gaseous 

radwaste system is to receive and contain fission gases removed from radioactive fluids to 

eliminate the need for regular discharge to the atmosphere of radioactive gases during normal 

plant operation. The gaseous radwaste system has the capacity to provide long-term storage 

for fission gases.

Solid Radwaste System. LRA Section 2.3.3.28 states that the purpose of the solid radwaste 

system is to collect, process, and package normal plant operation and anticipated operational 

occurrences radioactive wastes. The solid radwaste system stores the packaged radioactive 

wastes until it is shipped off site to a licensed burial site.

Boron Recycle System. LRA Section 2.3.3.28 states that the purpose of the boron recycle 

system is to support the reuse of boric acid and makeup water by means of recycling reactor 

coolant. The boron recycle system uses demineralization and gas stripping to decontaminate 

the effluent; evaporation is also used to separate and recover the boric acid and makeup water.

Secondary Liquid Waste System. LRA Section 2.3.3.28 states that the purpose of the 

secondary liquid waste system is to process wastes collected in the turbine building 

(e.g., condensate demineralizer regeneration waste and potentially radioactive liquid waste).

Domestic Water System. LRA Section 2.3.3.28 states that the purpose of the domestic water 

system is “to distribute and heat chlorinated potable water for drinking, cooking, showers, 

lavatories, toilets, and washdown.”

Sanitary Drainage System. LRA Section 2.3.3.28 states that the purpose of the sanitary 

drainage system is to collect non-corrosive, non-radioactive, non-oily liquid wastes and sewage 

within the non-radioactive areas of the power block from service and pantry facilities; electric 

water coolers and heaters, clean showers, plumbing fixtures, and toilet room floor drains. 

Roof Drains System. LRA Section 2.3.3.28 states that the purpose of the roof drains system is 

to collect precipitation water from building roofs and convey the water by gravity to the storm 

drain system. 

Chemical and Detergent Waste System. LRA Section 2.3.3.28 states that the purpose of the 

chemical and detergent waste system is “to collect waste from selected laboratory sinks and 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-75

washers, recycle evaporator and reagent tank, waste evaporator and reagent tank, secondary 

liquid waste evaporator and reagent tank, radwaste building sample panel, evaporator bottoms 

tank overflow, decon showers, and men’s showers.”

LRA Table 2.3.3-28 identifies the “Miscellaneous Systems In Scope ONLY for Criterion 

10 CFR 54.4(a)(2)” component types within the scope of license renewal and subject to an 

AMR.

2.3.3.28.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.28 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.3.28.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the “Miscellaneous Systems In Scope ONLY for Criterion 

10 CFR 54.4(a)(2)” components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant adequately identified the system 

components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.29 Circulating Water System

2.3.3.29.1 Summary of Technical Information in the Application

In a letter dated February 14, 2014, the applicant submitted LRA Section 2.3.3.29 as part of

LRA Amendment 31. The amendment states that the circulating water system was added to the 

scope of license renewal as a result of the issuance of Callaway license Amendment 206, 

regarding transition to a risk-informed, performance-based fire protection program in 

accordance with 10 CFR 50.48(c), “National Fire Protection Association Standard NFPA 805.” 

The applicant stated that the circulating water system was added to support fire protection 

requirements based upon the criteria of 10 CFR 54.4(a)(3). The applicant stated that the 

system provides a return path to the cooling tower for the service water system consistent with 

NFPA 805 changes. The applicant also stated that the purpose of the circulating water system 

is to supply cooling water from the plant’s cooling water source to the main condenser to 

condense discharged steam from the exhaust of the turbine or the turbine bypass system. 

Finally, LRA Section 2.3.3.29 states that the system is nonsafety-related and performs no 

safety-related functions.

The intended function of the circulating water system portion within the scope of license renewal 

is to support fire protection requirements of 10 CFR 50.48 and NFPA 805, based upon the 

criteria of 10 CFR 54.4(a)(3).

2.3.3.29.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.29 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-76

2.3.3.29.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3, and on a review of 

the LRA, LRA Amendment 31, FSAR, and license renewal boundary drawings, the staff 

concludes that the applicant appropriately identified the circulating water system components 

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant adequately identified the system components subject to an AMR, in 

accordance with the requirements 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, “Main Turbine System”

• LRA Section 2.3.4.2, “Main Steam Supply System”

• LRA Section 2.3.4.3, “Main Feedwater System”

• LRA Section 2.3.4.4, “Steam Generator Blowdown System”

• LRA Section 2.3.4.5, “Auxiliary Feedwater System”

• LRA Section 2.3.4.6, “Condensate Storage and Transfer System”

Steam and Power Conversion Generic Request for Additional Information

The staff noted the following instances on license renewal boundary drawings where the 

continuation of in-scope piping could not be identified:

• “F”-HBD-2” and “I”-HBD-2” piping on license renewal boundary drawing 

LR-CW-AB-M-22AB02, location B-6

• piping downstream of valves V039m, V028, V017, and V006, which continues from 

license renewal boundary drawing LR-CW-BM-M-22BM01, locations B-5, C-5, E-5, and 

G-5 respectively, to license renewal boundary drawing M-22RM01, which was not 

provided in the LRA

• piping downstream of valve V998 on license renewal boundary drawing 

LR-CW-AL-M-22FC02

By letter dated June 11, 2012, the staff issued RAI 2.3.4-1 requesting the applicant to identify 

the continuation and termination of the above piping examples, along with any information 

regarding scoping classification changes as necessary.

In its response letter dated July 2, 2012, the applicant provided information to clarify the 

above piping continuation examples as follows:

• On license renewal boundary drawing LR-CW-AB-M-22AB02, the applicant stated that 

pipe sections “I”-HBD-2” and “F”-HBD-3/4” continue and connect with their respective 

lines “E”-HBD-2” and “A”-HBD-1” for each of the safety valves in their loop. The 

applicant included a note in the revised license renewal boundary drawing 

LR-CW-AB-M-22AB02 to clarify the scoping boundary for the pipe sections. The staff 

confirmed that the applicant corrected the pipe sections as part of its RAI response. The

staff also reviewed the revised license renewal boundary drawing LR-CW-AB-M-22AB02 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-77

to confirm the scoping boundary for the above pipe sections and the inclusion of the 

note.

• On license renewal boundary drawing LR-CW-BM-M-22BM01, the applicant stated that 

each of the continuation piping downstream of valves V039, V028, V017, and V006 is 

tubing. The applicant indicated that the valves are within the scope of license renewal 

for 10 CFR 54.4 (a)(2) with an intended function of structural integrity (attached). The 

applicant stated that the tubing attached downstream of these valves does not have an 

intended function of structural integrity (attached). The applicant also included a note to 

the revised license renewal boundary drawing LR-CW-BM-M-22BM01 to indicate that 

tubing is not within the scope of license renewal.

• On license renewal boundary drawing LR-CW-AL-M-22FC02, the applicant stated that 

valve 998 is a sentinel relief valve that vents directly to the room and no further 

continuation is needed. The applicant also included a note to the revised license 

renewal boundary drawing LR-CW-AL-M-22FC02 to indicate the scoping boundary for 

the sentinel relief valve.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4-1 acceptable because 

the applicant clarified each of the continuation piping examples as described above and 

identified the system scoping boundary in each instance. The staff reviewed the above revised 

license renewal boundary drawings to confirm the scoping boundaries as described in the 

applicant’s RAI response. Therefore, the staff’s concern described in RAI 2.3.4-1 is resolved.

2.3.4.1 Main Turbine System

2.3.4.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.1 states that the purpose of the main turbine system is to convert the steam 

thermal energy to mechanical energy to drive the main generator.

The intended function of the main turbine system within the scope of license renewal is to 

support ATWS (10 CFR 50.62) requirements.

LRA Table 2.3.4-1 identifies the main turbine system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.4.1.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the main turbine system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-78

2.3.4.2 Main Steam Supply System

2.3.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.2 states that the purpose of the main steam supply system is to send the 

steam produced in the steam generators to the turbine generator, turbine driven feedwater 

pumps, the turbine-driven auxiliary feed pump, steam dumps, reheaters, and the auxiliary steam 

system.

The intended functions of the main steam supply system within the scope of license renewal 

include the following:

• to provide heat removal from the RCS for controlled cooldown during normal, accident, 

and post-accident conditions

• to provide containment isolation and overpressure protection for the steam generator 

secondary side and the main steam piping 

• to provide steam to support the operation of the turbine-driven auxiliary feedwater pump

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48), SBO (10 CFR 50.63), and EQ (10 CFR 50.49) 

requirements

LRA Table 2.3.4-2 identifies the main steam supply system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2, FSAR Sections 10.3 SP and 10.4 SP and the 

license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff

identified an area in which additional information was necessary to complete the review of 

the applicant’s scoping and screening results.

The staff noted license renewal boundary drawing LR-CW-AE-M-22AB02 depicts main 

steam piping in the auxiliary building highlighted in green, which indicates that the piping is 

within the scope of license renewal for 10 CFR 54.4(a)(1). However, at locations C-2, D-2, 

F-2, and G-2, four sections of main steam piping exit the auxiliary building and continue 

into the turbine building. As described by Note 1 on license renewal boundary drawing 

LR-CW-AE-M-22AB02, the scoping classification change and seismic portion of the main 

steam piping occurs at the first weld within the turbine building. Nonsafety-related 

components were not identified within the scope of license renewal for 10 CFR 54.4(a)(2) 

inside the turbine building on the license renewal boundary drawing, as required by the 

applicant’s scoping methodology described in LRA Section 2.1.2.2. By letter dated 

June 11, 2012, the staff issued RAI 2.3.4.2-1 requesting the applicant to provide 

justification for excluding the nonsafety-related components in the turbine building, which 

may be in proximity of the 10 CFR 54.4(a)(1) main steam piping, from the scope of license 

renewal for 10 CFR 54.4(a)(2).

In its response letter dated July 2, 2012, the applicant stated that the main steam piping 

located in the turbine building is not relied upon to remain functional during or following DBEs 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-79

and is excluded from scope of license renewal for 10 CFR 54.4(a)(1). The applicant explained 

that the Callaway FSAR defines the portion of the main steam piping from the containment 

penetration to outside the outboard isolation restraint as a “no break zone.” The outboard 

isolation restraint is a torsional restraint in the wall between the auxiliary building and the 

turbine building. The applicant also indicated that Callaway FSAR Section 3.6.2.1.1e states 

that stresses within the “no break zone” will remain acceptable when subjected to the combined 

loadings of internal pressure, dead weight, and postulated pipe break beyond the “no break 

zone.” The applicant further stated that the main feedwater and steam generator blowdown 

systems also have safety classification breaks in the turbine building. 

As with the main steam piping, the applicant also determined that the piping for these systems 

inside the turbine building are not within the scope of license renewal for 10 CFR 54.4(a)(1). 

The applicant stated that plant documentation associated with these sections of piping was

being revised to clarify the safety classification boundary as being at the wall between the 

auxiliary building and the turbine building.

Based on its review, the staff found the applicant’s response to RAI 2.3.4.2-1 unacceptable. 

Therefore, by letter dated October 12, 2012, the staff issued RAI 2.3.4.2-1a requesting the 

applicant to provide its justification for excluding from the scope of license renewal the attached 

main steam piping, which extends from the “no break zone” area and into the turbine building. 

In addition, during a telephone conference call with the applicant held on December 6, 2012, the 

staff stated that the applicant needs to provide clarification of the safety classification 

boundaries of the piping for the main steam, main feedwater, and steam generator blowdown 

systems, which exit the auxiliary building and enter the turbine building. During the telephone 

conference call, the staff also stated that it considers the applicant’s intention to exclude the 

attached nonsafety-related piping in the turbine building for the main steam, main feedwater, 

and steam generator blowdown systems an exception to its 10 CFR 54.4(a)(2) scoping

methodology for attached nonsafety-related piping to safety-related piping as described in LRA 

Section 2.1.2.2. During the telephone conference call, the applicant stated that it will address 

the staff’s concerns in its upcoming response to RAI 2.3.4.2-1a.

By letter dated January 10, 2013, the applicant provided its response to RAI 2.3.4.2-1a. In its 

response, the applicant indicated that the piping for the main steam and main feedwater 

systems are located in “no break zones,” which extend from the anchors in the reactor building 

wall to outside the torsional restraints in the auxiliary building to turbine building wall. The 

applicant defined “no break zones” as areas of high energy piping, where breaks are not 

postulated because the stresses are limited. The applicant also further described the “no break 

zones” in the RAI response as not exceeding the “1.8 Sh per equation (9), Subarticle NC-3652 of 

ASME Section III when subjected to the combined loadings of internal pressure, deadweight, 

and postulated pipe break beyond the no break zone.” The applicant’s safety assessment of 

the safety-related piping for the main steam and main feedwater systems concluded that, since 

this piping is located in the “no break zones,” postulated pipe breaks on the turbine building side 

beyond the “no break zones” would not prevent the piping within the “no break zones” from 

performing its intended functions. The applicant excluded the nonsafety-related piping, which is 

attached to the safety-related piping for the main steam and main feedwater systems, in the 

turbine building because the failure of this piping beyond the “no break zones” will not prevent 

the connected safety-related components from performing their intended function.

Also, as part of its response, the applicant stated that Callaway was taking an exception to 

NEI 95-10, Appendix F, to exclude the nonsafety-related piping attached to the safety-related 

piping of the main steam and main feedwater systems beyond the “no break zones” and into the 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-80

turbine building from the scope of license renewal. The applicant revised LRA Section 2.1.2.2 

to provide the justification for taking this exception to NEI 95-10, Appendix F. The applicant 

indicated in its response that the steam generator blowdown system will continue to meet 

NEI 95-10, Appendix F. The applicant included the revised license renewal boundary drawing 

LR-CW-BM-22BM01 for the steam generator blowdown system to depict that the 

nonsafety-related piping was included within the scope of license renewal for 

10 CFR 54.4(a)(2). The applicant also provided supplemental drawings of the “no break zones” 

and torisional restraints located within the “no break zones” for staff review. In addition, the 

applicant revised LRA Section 2.3.4.3 and Table 3.4.2-3 as part of its RAI response to remove 

the nonsafety-related main feedwater system components in the turbine building from the scope 

of license renewal. The applicant deleted and revised license renewal boundary drawings, 

LR-CW-AE-M-22AE01 and LR-CW-AE-M-22AE02 respectively, to remove the red highlighted 

nonsafety-related components in the turbine building from scope of license renewal. 

The staff reviewed the applicant’s FSAR assessment, RAI response, and supplemental plant 

drawings of the “no break zones” and torsional restraints for the main steam and main 

feedwater systems. Based on its review, the staff finds that the torsional restraint consists of 

two sets of restraints about 8 ft (2.4 m) apart, which act as bending moment restraints and 

torsional moment restraints along with lateral guides. The staff observed that the axial 

restraining effect is provided by the containment anchor because of the straight sections of main 

steam and main feedwater safety piping between the containment anchor and the auxiliary 

building wall within the “no break zone.” The staff finds that the safety-related piping in the “no 

break zones” is protected from pipe break effects outside of auxiliary building wall. Therefore,

the staff finds the applicant’s justification for taking exception to NEI 95-10, Appendix F 

acceptable because (1) the physical design of the “no break zone” does not allow any piping 

failures downstream from the auxiliary building wall to impact the safety-related main steam and 

main feedwater piping in the “no break zones,” and (2) the physical layout of the main steam 

and main feedwater piping from the containment anchor to the auxiliary building wall restrains 

any axial movement of the piping beyond the “no break zones.” The staff finds the applicant’s 

response to RAI 2.3.4.2-1a acceptable because the applicant provided an adequate justification 

for excluding from the scope of license renewal the main steam piping which extends from the 

"no break zone" area into the turbine building.

The staff also reviewed the revised LRA Sections 2.1.2.2, 2.3.4.3, and the license renewal 

boundary drawings for the main steam and main feedwater systems to confirm that the 

nonsafety-related piping in the turbine building was removed from scope of license renewal. 

The staff also reviewed the revised license renewal boundary drawing for the steam generator 

blowdown system to confirm that the nonsafety-related piping was included within the scope of 

license renewal for 10 CFR 54.4(a)(2). Therefore, the staff’s concerns described in 

RAI 2.3.4.2-1 and RAI 2.3.4.2-1a are resolved.

2.3.4.2.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, RAI responses, and license renewal boundary drawings, the staff concludes that 

the applicant appropriately identified the main steam supply system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-81

2.3.4.3 Main Feedwater System

2.3.4.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.3 states that the purpose of the main feedwater system is to receive 

condensate from the condensate system and deliver feedwater to the four steam generators at 

the required pressure, temperature, and flow rate.

The intended functions of the main feedwater system within the scope of license renewal 

include the following:

• to provide containment and feedwater isolation for reactivity control during an accident 

• to provide a flow path for auxiliary feedwater for the removal of decay heat

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48), EQ (10 CFR 50.49), ATWS (10 CFR 50.62), 

and SBO (10 CFR 50.63) requirements 

LRA Table 2.3.4-3 identifies the main feedwater system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3, FSAR Section 10.4.7 SP, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and 

the guidance in SRP-LR Section 2.3. On the basis of its review, the staff identified an area 

in which additional information was necessary to complete the review of the applicant’s 

scoping and screening results. 

The staff noted license renewal boundary drawing LR-CW-AE-M-22AE01 depicts solenoid 

valves, which are highlighted in green, at locations A-7, B-7, C-7, D-7, E-7, F-7, G-7, and 

H-7. These solenoid valves are accompanied on the license renewal boundary drawing 

with license renewal Note 1, which indicates that these valves are within the scope of 

license renewal under 10 CFR 54.4(a)(1). However, there were not any nonsafety-related 

components identified on license renewal boundary drawing LR-CW-AE-M-22AE01. The 

exclusion of these nonsafety-related components from the scope of license renewal 

appears to be inconsistent with the scoping methodology described in LRA Section 2.1.2.2. 

By letter dated June 11, 2012, the staff issued RAI 2.3.4.3-1 requesting the applicant to 

provide justification for excluding the nonsafety-related components near the solenoid 

valves from the scope of license renewal for 10 CFR 54.4(a)(2) on license renewal 

boundary drawing LR-CW-AE-M-22AE01.

In its response letter dated July 2, 2012, the applicant stated that the solenoid valves do 

not have a safety-related intended function consistent with the 10 CFR 54.4(a)(1) criteria, 

and were incorrectly identified on the boundary drawing as being within the scope of 

license renewal for 10 CFR 54.4(a)(1). The applicant did further state that the solenoid 

valves are within the scope of license renewal for 10 CFR 54.4(a)(2) because they support 

the diverse backup function of the main feedwater control valves and main feedwater 

bypass control valves. The applicant revised license renewal boundary drawing 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-82

LR-CW-AE-M-22AE01 to depict the solenoid valves as being within the scope of license 

renewal for 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-1 acceptable 

because the solenoid valves do not have a safety-related intended function consistent with 

10 CFR 54.4(a)(1). The staff reviewed reference documents regarding the initial classification 

of the solenoid valves during the April 16–19, 2012 scoping and screening audit, which support 

the applicant’s RAI response. However, the safety-related classification of the solenoid valves 

in the current LRA was not identified by the applicant before the staff’s initial review. The staff 

also finds the applicant’s scoping classification of the solenoid valves as being within the scope 

of license renewal for 10 CFR 54.4(a)(2) acceptable since the solenoid valves support the 

safety functions of main feedwater control valves and main feedwater bypass control valves. 

The staff reviewed the revised license renewal boundary drawing LR-CW-AE-M-22AE01 to 

confirm that the solenoid valves are shown as being within the scope of license renewal for 

10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.4.3-1 is resolved.

Also, in its January 10, 2013, response to RAI 2.3.4.2-1a, the applicant stated that Callaway 

was taking an exception to NEI 95-10, Appendix F, to exclude the nonsafety-related piping 

attached to the safety-related piping of the main feedwater systems beyond the “no break 

zones” and into the turbine building from the scope of license renewal. As part of its response, 

the applicant revised LRA Section 2.1.2.2 to provide the justification for taking this exception to 

NEI 95-10, Appendix F. The staff’s resolution of this issue is documented in SER 

Section 2.3.4.2.

2.3.4.3.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, RAI response, and license renewal boundary drawings, the staff concludes that the 

applicant appropriately identified the main feedwater system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.4.4 Steam Generator Blowdown System

2.3.4.4.1 Summary of Technical Information in the Application

LRA Section 2.3.4.4 states that the purpose of the steam generator blowdown system is to 

maintain the secondary side water of the steam generators within the chemical specifications. 

The intended functions of the steam generator blowdown system within the scope of license 

renewal include the following:

• to provide containment isolation for four containment penetrations with isolation valves 

inside and outside of containment

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and ATWS 

(10 CFR 50.62) requirements
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-83

LRA Table 2.3.4-4 identifies the steam generator blowdown system component types within the 

scope of license renewal and subject to an AMR.

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.4.4.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the steam generator blowdown system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

adequately identified the system components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.4.5 Auxiliary Feedwater System

2.3.4.5.1 Summary of Technical Information in the Application

LRA Section 2.3.4.5 states that the purpose of the auxiliary feedwater system is to provide 

feedwater to the steam generators during startup, shutdown, and emergency conditions. 

The intended functions of the auxiliary feedwater system within the scope of license renewal 

include the following:

• to provide decay heat removal in post-accident conditions

• to resist nonsafety-related SSC failure that could prevent satisfactory accomplishment of 

a safety-related function in accordance with the requirements of 10 CFR 54.4(a)(2)

• to support fire protection (10 CFR 50.48), EQ (10 CFR 50.49), ATWS (10 CFR 50.62), 

and SBO (10 CFR 50.63) requirements 

LRA Table 2.3.4-5 identifies the auxiliary feedwater system component types within the scope of 

license renewal and subject to an AMR.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.4.5.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the auxiliary feedwater system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-84

2.3.4.6 Condensate Storage and Transfer System

2.3.4.6.1 Summary of Technical Information in the Application

LRA Section 2.3.3.4.6 states that the purpose of the condensate storage and transfer system is 

to deliver or receive condensate to compensate for changes in plant systems inventory. The 

condensate storage and transfer system consists of a 450,000-gallon condensate storage tank 

that works as a non-seismically designed source of water to the auxiliary feedwater system. 

The condensate storage and transfer system is not credited for accident mitigation. 

The intended functions of the condensate storage and transfer system within the scope of 

license renewal are: (1) to resist nonsafety-related SSC failure that could prevent satisfactory 

accomplishment of a safety-related function in accordance with the requirements of

10 CFR 54.4(a)(2); and (2) to support fire protection (10 CFR 50.48), EQ (10 CFR 50.49), and 

SBO (10 CFR 50.63) requirements.

LRA Table 2.3.4-6 identifies the condensate storage and transfer system component types 

within the scope of license renewal and subject to an AMR.

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. On the basis of its review, the staff did 

not identify the need for any additional information.

2.3.4.6.3 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, FSAR, and license renewal boundary drawings, the staff concludes that the applicant 

appropriately identified the condensate storage and transfer system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the 

applicant adequately identified the system components subject to an AMR, in accordance with 

the requirements stated in 10 CFR 54.21(a)(1).

2.4 Scoping and Screening Results: Structures

This section documents the staff’s review of the applicant’s scoping and screening results for 

structures. Specifically, this section describes the following structures:

• reactor building 

• control building

• auxiliary building

• turbine building

• diesel generator building

• miscellaneous in-scope structures

• in-scope tank foundations and structures

• electrical foundations and structures

• radwaste building

• fuel building

• ESW structures

• supports
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-85

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 met 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, 

which 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).

In its scoping evaluation, the staff 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 relevant licensing basis documents, including the FSAR, for each structure to 

determine if the applicant omitted components with intended functions delineated under 

10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing basis 

documents and the FSAR to determine if all intended functions delineated under 

10 CFR 54.4(a) were specified in the LRA. The staff asked for additional information to resolve 

any omissions or 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 if the 

functions are performed with moving parts or a change in configuration or properties, or 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 

10 CFR 54.21(a)(1). The staff asked for additional information to resolve any omissions or 

discrepancies.

2.4.1 Reactor Building 

2.4.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.1, the applicant described the reactor building as including internal structural 

components within the scope of license renewal that are safety-related, in accordance with 

10 CFR 54.4(a)(1). Portions of the reactor building provide structural support, shelter, and 

protection for nonsafety-related SSCs whose failure could prevent satisfactory accomplishment 

of a safety-related function, in accordance with 10 CFR 54.4(a)(2). 

The reactor building is a seismic Category I structure, which provides protection for the reactor 

vessel, RCS, steam generators, pressurizer, RCPs, accumulators, and containment air coolers. 

The staff defines seismic Category I structures as SSCs designed and built to withstand the 

maximum potential earthquake stresses for the particular region where a nuclear plant is sited. 

The building is a pre-stressed and conventionally reinforced concrete structure consisting of 

several major structural components, including a steel liner plate, penetrations, and various 

reactor building internal structures. 

Reactor building internal structures include a heavily reinforced concrete reactor cavity that 

houses the reactor and provides the primary shield barrier, secondary shield walls, and the 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-86

refueling canal, a reinforced concrete structure lined with stainless steel used to transfer fuel 

elements under water between the reactor and the spent fuel pool. Structural steel provides 

support for various safety-related and nonsafety-related SCs, including piping, ducts, 

equipment, cable trays, conduit, instruments, and tubing. 

The intended functions of the reactor building within the scope of license renewal include the 

following:

• to provide structural support and protection for safety-related SSCs required to mitigate 

the consequences of accidents that could result in potential offsite exposure

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63), in accordance with 

the requirements stated in 10 CFR 54.4(a)(3)

LRA Table 2.4-1 identifies the reactor building component types within the scope of license 

renewal and subject to an AMR.

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.1.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the reactor building components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.2 Control Building

2.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.2, the applicant described the control building as a seismic Category I 

structure supported by a reinforced concrete base mat founded on compacted soil. The 

purpose of the control building is to support, shelter, and protect the main control room, access 

control areas, upper and lower cable spreading rooms, electrical and mechanical equipment 

rooms, Class 1E switchgear, battery rooms, and other equipment supporting the control room 

habitability systems. The intermediate floors and roof are reinforced concrete slabs supported 

by structural steel beams and girders while the floor and roof framing are supported by exterior 

reinforced concrete bearing walls and interior steel columns. The communications corridor 

adjacent to the control building is a non-Category I structure, which is designed to preclude 

gross collapse upon safety-related structures or components under loads imposed by the 

design-basis tornado. 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-87

The intended functions of the control building within the scope of license renewal include the 

following:

• to provide structural support and protection for safety-related SSCs required for safe 

shutdown of the reactor 

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63), in accordance with 

the requirements stated in 10 CFR 54.4(a)(3)

LRA Table 2.4-2 identifies the control building component types within the scope of license 

renewal and subject to an AMR.

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.2.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the control building components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.3 Auxiliary Building

2.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.4.3, the applicant described the auxiliary building as a seismic Category I 

structure supported by a reinforced concrete base mat founded on compacted soil. The

purpose of the auxiliary building is to support, shelter, and protect the safety injection system, 

RHR system, chemical and volume control monitoring system, auxiliary feedwater pumps, 

steam and feedwater isolation and relief valves, heat exchangers, other pumps, tanks, filters, 

demineralizers, and heating and ventilating equipment. The building also includes the 

non-Category I radioactive material storage building and laundry decontamination facility, whose 

structural framing is designed to preclude gross collapse upon the auxiliary building or its 

components under loads imposed by the design-basis tornado. 

The intended functions of the auxiliary building within the scope of license renewal include the 

following:

• to provide structural support and protection for safety-related SSCs required for safe 

shutdown of the reactor 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-88

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63), in accordance with 

the requirements stated in 10 CFR 54.4(a)(3)

LRA Table 2.4-3 identifies the auxiliary building component types within the scope of license 

renewal and subject to an AMR.

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.3.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the auxiliary building components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.4 Turbine Building

2.4.4.1 Summary of Technical Information in the Application

In LRA Section 2.4.4, the applicant described the turbine building as a non-Category I building 

that is designed to support, shelter, and protect the turbine generator, condensers, main feed 

pumps, and other power conversion equipment; and houses the auxiliary boiler room, which is 

evaluated with the turbine building. 

The intended functions of the turbine building within the scope of license renewal are: (1) to 

provide structural support and protect nonsafety-related SSCs whose failure could prevent 

satisfactory accomplishment of a safety-related function in accordance with the requirements of

10 CFR 54.4(a)(2) and (2) to provide structural support and protect SSCs that support fire 

protection (10 CFR 50.48) and ATWS (10 CFR 50.62), in accordance with the requirements 

stated in 10 CFR 54.4(a)(3).

LRA Table 2.4-4 identifies the turbine building component types within the scope of license 

renewal and subject to an AMR.

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-89

2.4.4.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the turbine building components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.5 Diesel Generator Building

2.4.5.1 Staff Evaluation Summary of Technical Information in the Application

In LRA Section 2.4.5, the applicant described the diesel generator building as a seismic 

Category I structure comprised of structural steel and reinforced concrete supported by a 

reinforced concrete base mat founded 10 ft below grade on crushed rock. The purpose of the 

building is to support, shelter, and protect the EDGs, diesel auxiliaries, emergency fuel oil day 

tanks, exhaust silencers, and exhaust stacks. A fire barrier wall separates the two standby 

diesel generator rooms. The building also includes fuel oil storage tanks, which consist of two 

buried cylindrical steel tanks and associated reinforced concrete access vaults. 

The intended functions of the diesel generator building within the scope of license renewal 

include the following:

• to provide structural support and protection for safety-related SSCs required for safe 

shutdown of the reactor 

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48) and SBO (10 CFR 50.63), in accordance with the requirements stated in 

10 CFR 54.4(a)(3)

LRA Table 2.4-5 identifies the diesel generator building component types within the scope of 

license renewal and subject to an AMR.

2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.5.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the diesel generator building components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-90

2.4.6 Miscellaneous In-Scope Structures

2.4.6.1 Summary of Technical Information in the Application

In LRA Section 2.4.6, the applicant described the miscellaneous in-scope structures . The 

miscellaneous in-scope structures intended functions are to support, shelter, and protect 

equipment required for fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) recovery. 

The miscellaneous in-scope structures include the following structures: fire pumphouse, security 

diesel generator building, security building (main access facility), switchyard control building, 

circulating and service water pumphouse, and the cooling tower basin (including reinforced 

concrete structures under the turbine building and in the yard that provide a return flowpath for 

the circulating water system).

Fire Pumphouse. A single-story metal-sided enclosure supported by structural steel framing on 

three sides and a concrete masonry block wall on the west face. The structure is supported by 

reinforced concrete footings on structural backfill and has interior block walls that serve as fire 

barriers. The roof consists of a built-up material over rigid insulation and metal deck supported 

by steel roof joists.

Security Diesel Generator Building. A single-story metal-sided enclosure with a built-up roof. 

The structure is supported by a reinforced concrete foundation on structural backfill. 

Security Building (main access facility). A multi-story reinforced concrete structure with metal 

siding. The intermediate floor framing and reinforced concrete bearing walls are supported by 

reinforced concrete footings on structural backfill. The roof is a reinforced concrete deck with 

built-up roofing over rigid insulation.

Switchyard Control Building. A single-story concrete masonry block wall building with a built-up 

roof. The structure is supported by reinforced concrete footings on structural backfill. 

Circulating and Service Water Pumphouse. A multi-story reinforced concrete and structural 

steel framed building supported by reinforced concrete footings on structural backfill. The roof 

consists of a built-up material over rigid insulation and metal deck supported by steel roof joists.

Cooling Tower Basin. A reinforced concrete slab with sidewalls founded on reinforced concrete 

piers and structural backfill. The structure provides water for the service water pumps supplying 

fire water to hose stations located in the essential service water pumphouse. 

The intended function of the miscellaneous in-scope structures within the scope of license 

renewal is to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48) and SBO (10 CFR 50.63) in accordance with the requirements stated in

10 CFR 54.4(a)(3).

LRA Table 2.4-6 identifies the miscellaneous in-scope structures component types within the 

scope of license renewal and subject to an AMR.

2.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.6 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-91

2.4.6.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the miscellaneous in-scope structures components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.4.7 In-Scope Tank Foundations and Structures

2.4.7.1 Summary of Technical Information in the Application

In LRA Section 2.4.7, the applicant described in-scope tank foundations and structures as 

consisting of the seismic Category I safety-related RWST and valvehouse; and the 

nonsafety-related condensate storage tank (CST), CST trench, nitrogen storage tank foundation 

and pipe trench, and the fire water storage tanks. 

The intended functions of the in-scope tank foundations and structures within the scope of 

license renewal include the following:

• to provide structural support and protection for safety-related SSCs required for safe 

shutdown of the reactor 

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48) and SBO (10 CFR 50.63) in accordance with the requirements stated in 

10 CFR 54.4(a)(3)

LRA Table 2.4-7 identifies the in-scope tank foundations and structures component types within 

the scope of license renewal and subject to an AMR.

2.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7 and the FSAR using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. During its review, the 

staff evaluated the structural component functions described in the LRA and FSAR to verify that 

the applicant has not omitted from the scope of license renewal any SCs with intended functions 

delineated under 10 CFR 54.4(a). The staff then reviewed those SCs that the applicant has 

included within the scope of license renewal to verify that the applicant has not omitted any 

passive and long-lived SCs subject to an AMR in accordance with the requirements of 

10 CFR 54.21(a)(1).

During its review of LRA Section 2.4.7, the staff noted an area in which additional information 

was necessary to complete its review of the applicant’s scoping and screening results. 

The staff noted LRA Section 2.4.7 only lists the Category I safety-related RWST and 

valvehouse, the nonsafety-related CST, and the FWST as the tanks within the scope of license 

renewal. However for the structural foundations and supports of other safety-related tanks that 

are not specifically called out in the LRA, such as the component cooling water surge tank and 

the chemical and volume control system tank, it is not clear if the tank supports are analyzed 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-92

under the specific LRA section that describes the structure that houses the tank, or as a 

separate commodity such as in LRA Section 2.4.7. By letter dated July 5, 2012, the staff issued 

RAI 2.4.7-1 requesting that the applicant clarify if the tank supports are analyzed under the 

specific LRA section that describes the structure that houses the tank, or as a separate 

commodity, such as in LRA Section 2.4.7. In its response letter dated August 6, 2012, the 

applicant stated that the foundations and associated structures for other in-scope tanks are 

evaluated as part of the buildings in which the tanks are located. For example, the component 

cooling water surge tanks are founded on a concrete slab within the auxiliary building which is 

evaluated under component type “concrete elements” in LRA Table 2.4-3. Supports that 

connect in-scope tanks to their foundations are evaluated as commodities in LRA 

Section 2.4.12, “Supports.” These supports are included in LRA Table 2.4-12 as component 

types “Supports Mech Equip Class 1, [2, or 3,]” or “Supports Mech Equip Non-ASME,” 

depending on the code class of the particular tank. Foundations and supports for all in-scope 

tanks are within the scope of license renewal and subject to AMR, while tanks are evaluated in 

their associated mechanical systems.

On the basis of its review, the staff finds the applicant response to RAI 2.4.7-1 acceptable 

because it clarified that the tank supports are analyzed under the specific LRA section that 

describes the structure that houses the tank and also identified the location within the LRA 

where the components were covered. Therefore, staff’s concern described in RAI 2.4.7-1 is 

resolved.

2.4.7.3 Conclusion

On the basis of its review of the LRA, FSAR, and RAI response, the staff concludes that the 

applicant has appropriately identified the in-scope tank foundations and structures components 

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the 

applicant has adequately identified the system components subject to an AMR in accordance 

with the requirements stated in 10 CFR 54.21(a)(1).

2.4.8 Electrical Foundations and Structures

2.4.8.1 Summary of Technical Information in the Application

In LRA Section 2.4.8, the applicant described electrical foundations and structures as consisting 

of reinforced concrete pads on structural backfill for station transformers (ESF, startup, unit 

auxiliary and station service). The purpose of the electrical foundations and structures is to 

support, shelter, and protect the station transformers, cables, and other in-scope electrical 

SSCs. The unit auxiliary transformer and support equipment are mounted on one pad while the 

two ESF transformers and support equipment are mounted on a separate pad. The startup and 

station service transformers and associated support equipment are also mounted on separate 

pads. The seismic Category I electrical duct banks are located below grade and consist of a 

number of PVC conduits encased in reinforced concrete which house safety-related electrical 

cables. Duct banks also connect the ESF transformers to the turbine building and to the 

switchyard. Electrical manholes are reinforced concrete underground chambers founded on 

reinforced concrete slabs and are used for installing and pulling electrical cables in the 

ductbanks. Transmission towers between the ESF and startup transformers are steel towers 

with reinforced concrete foundations. 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-93

The intended functions of the electrical foundations and structures within the scope of license 

renewal include the following:

• to provide structural support and protection for safety-related SSCs required for safe 

shutdown of the reactor 

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48) and SBO (10 CFR 50.63) in accordance with the requirements stated in 

10 CFR 54.4(a)(3)

LRA Table 2.4-8 identifies the electrical foundations and structures component types within the 

scope of license renewal and subject to an AMR.

2.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.8 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.8.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the electrical foundations and structures components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.4.9 Radwaste Building

2.4.9.1 Summary of Technical Information in the Application

In LRA Section 2.4.9, the applicant described the purpose of the radwaste building as providing

support, shelter, and protection for radioactive waste treatment facilities, tanks, filters, and other 

miscellaneous equipment. The building is a multi-story structural steel and reinforced concrete 

structure supported on a reinforced concrete mat foundation constructed on structural backfill, 

and has a built-up roof supported by structural steel beams and girders while the intermediate 

floor framing is supported by structural steel columns and reinforced concrete bearing walls. 

The radwaste pipe tunnel is a below-grade, reinforced concrete, two-cell box structure 

connecting the auxiliary building and the radwaste building. The pipe tunnel provides access 

and carries electrical cable trays and piping between the auxiliary building and the radwaste 

building, and is separated from the connected auxiliary building by a fire wall barrier and 

isolation joints. 

The intended function of the radwaste building within the scope of license renewal is to support 

fire protection (10 CFR 50.48) in accordance with the requirements stated in 10 CFR 54.4(a)(3).

LRA Table 2.4-9 identifies the radwaste building component types within the scope of license 

renewal and subject to an AMR.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-94

2.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.4.9 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.9.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the radwaste building components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified 

the system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.10 Fuel Building

2.4.10.1 Summary of Technical Information in the Application

In LRA Section 2.4.10, the applicant described the fuel building as a multi-story seismic 

Category I structural steel and reinforced concrete structure supported by a two-way reinforced 

concrete base mat founded on structural backfill with reinforced concrete pilasters integral with 

the exterior walls. The elevated floors and roof are reinforced concrete slabs supported by 

structural steel beams and girders while the floor and roof framing are supported by reinforced 

concrete bearing walls.

The purpose of the fuel building is to provide support, shelter, and protection for the spent fuel 

pool, transfer canal, cask loading pool and cask washdown pit, spent fuel pool bridge crane, 

cask handling crane, and other miscellaneous equipment. 

The intended functions of the fuel building within the scope of license renewal include the 

following:

• to provide structural support and protection for safety-related SSCs required to mitigate 

the consequences of accidents that could result in potential offsite exposure

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48) in accordance with the requirements stated in 10 CFR 54.4(a)(3)

LRA Table 2.4-10 identifies the fuel building component types within the scope of license 

renewal and subject to an AMR.

2.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.4.10 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-95

2.4.10.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the fuel building components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.11 Essential Service Water Structures

2.4.11.1 Summary of Technical Information in the Application

In LRA Section 2.4.11, the applicant described ESW structures as those structures used to 

support, shelter, and protect the SSCs required for the ESW system and UHS. The ESW 

structures consist of the UHS cooling tower, ESW pumphouse, ESW system supply lines yard 

vault, and UHS retention pond and ancillary structures.

The intended functions of the ESW structures within the scope of license renewal include the 

following:

• to provide structural support and protection for safety-related SSCs required for safe 

shutdown of the reactor 

• to provide structural support and protect nonsafety-related SSCs whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support and protect SSCs that support fire protection 

(10 CFR 50.48) in accordance with the requirements stated in 10 CFR 54.4(a)(3)

LRA Table 2.4-11 identifies the ESW structures component types within the scope of license 

renewal and subject to an AMR.

2.4.11.2 Staff Evaluation

The staff reviewed LRA Section 2.4.11 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.11.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the ESW structures components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.4.12 Supports

2.4.12.1 Summary of Technical Information in the Application

In LRA Section 2.4.12, the applicant described the supports commodity as including supports 

for American Society of Mechanical Engineers (ASME) Class 1, 2, and 3 piping and 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-96

components, and supports for non-ASME piping and components evaluated as commodities 

across system boundaries. Other commodity groups include cable trays and supports, conduits 

and supports, electrical panels and enclosures, instrument panels and racks, reactor vessel and 

steam generator supports, RCP and pressurizer supports, instrument tubing, and HVAC ducts. 

The intended functions of the supports structures within the scope of license renewal include the 

following:

• to provide structural support and protection for safety-related components 

• to provide structural support of nonsafety-related components whose failure could 

prevent satisfactory accomplishment of a safety-related function in accordance with the 

requirements of 10 CFR 54.4(a)(2)

• to provide structural support of components that support fire protection (10 CFR 50.48), 

ATWS (10 CFR 50.62), and SBO (10 CFR 50.63), in accordance with the requirements 

stated in 10 CFR 54.4(a)(3)

LRA Table 2.4-12 identifies the supports component types within the scope of license renewal 

and subject to an AMR.

2.4.12.2 Staff Evaluation

The staff reviewed LRA Section 2.4.12 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. On the basis of its review, the staff did 

not identify the need for any additional information.

2.4.12.3 Conclusion

On the basis of its review of the LRA and FSAR, the staff concludes that the applicant has 

appropriately identified the supports components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems

This section documents the staff’s review of the applicant’s scoping and screening results for 

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 must list passive, 

long-lived SSCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the

implementation results. This focus allowed the staff to confirm that there were no omissions of 

electrical and I&C system components that meet the scoping criteria and are subject to an AMR.

The staff’s evaluation of the information in the LRA was the same for all electrical and I&C 

systems. The objective was to determine if the applicant has identified, in accordance with 

10 CFR 54.4, components and supporting structures for electrical and I&C systems that appear 

to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant’s 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-97

screening results to verify that all passive, long-lived components were subject to an AMR in 

accordance with 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections and the RAI response, 

focusing on components that have not been identified as within the scope of license renewal. 

The staff reviewed the FSAR for each electrical and I&C system to determine if the application 

has omitted, from the scope of license renewal, components with intended functions delineated 

under 10 CFR 54.4(a).

After its review of the scoping results, the staff evaluated the applicant’s screening results. For 

those SSCs with intended functions, the staff sought to determine whether (1) the functions are 

performed with moving parts or a change in configuration or properties or (2) the SSCs are 

subject to replacement after a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that 

these SSCs were subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5.1 Electrical and Instrumentation and Controls Commodity Groups

2.5.1.1 Summary of Technical Information in the Application

LRA Section 2.5 describes the electrical and I&C systems. The scoping method includes all 

plant electrical and I&C components. Evaluation of electrical systems includes electrical and 

I&C components in mechanical systems. The default inclusion of plant electrical and I&C 

systems within the scope of license renewal reflects the method for the IPAs of electrical 

systems. This method is different from those for mechanical systems and structures.

The basic philosophy of the electrical and I&C components IPA is that components are included 

in the scoping review unless specifically screened out. The electrical and I&C IPA began by 

grouping all components into commodity groups of similar electrical and I&C components with 

common characteristics and by determining component level intended functions of the 

commodity groups.

The IPA eliminated commodity groups and specific plant systems from further review as the 

intended functions of commodity groups were examined. In addition to the plant electrical 

systems, certain switchyard components required to restore offsite power following SBO were 

included conservatively within the scope of license renewal even though those components are 

not relied on in the Callaway plant safety analyses or plant evaluations for functions that 

demonstrate compliance with the SBO regulation (10 CFR 50.63). The offsite power system 

evaluation boundaries are described next.

The offsite power system provides the electrical interconnection between the Callaway plant 

and the offsite transmission network. LRA Section 2.1.2.3.5 states the ESF transformers, 

startup transformer, overhead transmission lines, disconnects, overhead lines from disconnects 

to and including the switchyard breakers and the switchyard breaker control cables and 

connections are within the scope of license renewal as shown in Figure 2.1-2 of the LRA.

LRA Section 2.5 identifies electrical and I&C systems component types within the scope of 

license renewal and subject to an AMR:

• cable connections (metallic parts) 

• connectors 

• high voltage insulator 
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-98

• insulated cable and connections 

• switchyard bus and connections 

• terminal blocks 

• transmission conductors 

• transmission connections 

• electrical equipment subject to 10 CFR 50.49 EQ requirements 

• metal enclosed bus 

• mechanical EQ components

• fuse holders (not part of a larger assembly) 

• penetrations, electrical 

• grounding conductors 

• cable tie wraps

The intended functions of the electrical and I&C systems component types within the scope of 

license renewal are to provide electrical continuity, expansion and separation, structural 

support, and electrical insulation. 

2.5.1.2 Staff Evaluation

The staff reviewed Callaway LRA Section 2.5 and Unit 1 FSAR 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 FSAR to 

verify that the applicant has not omitted from the scope of license renewal, any components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

General Design Criterion 17 of 10 CFR Part 50, Appendix A, requires, in part, 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)),” (ADAMS Accession 

No. ML020920464) and later incorporated in SRP-LR Section 2.5.2.1.1, states the following:

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.
STRUCTURES AND COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW

2-99

In addition, the aforementioned guidance has been clarified in a license renewal interim staff 

guidance (ISG) document LR-ISG-2008-01, “Staff Guidance Regarding the Station Blackout 

Rule (10 CFR 50.63) Associated with License Renewal Applications,” related to the SBO 

recovery path for license renewal. LR-ISG-2008-01 emphasizes that the SBO recovery path 

should include (1) the switchyard breakers at the transmission system (69 kV and higher) that 

connect to the offsite system power transformers; (2) the transformers themselves; (3) the 

intervening overhead or underground circuits between circuit breaker and transformer and 

transformer and onsite electrical distribution system; and (3) the associated control circuits and 

structures.

In its application dated December 15, 2011, the applicant described the SBO recovery path that 

was in the scope of license renewal. The applicant stated that the SBO recovery path included 

all the components and connections from the offsite power source, including switchyard 

transformers, high side disconnects, conductors, transformers, and buses up to the Callaway 

nuclear plant safeguards buses. Based on the above, the staff finds that the scope of the 

license renewal SBO recovery path is consistent with the scope of NUREG-1800, Revision 2, 

and, therefore, is acceptable. 

During its review of LRA Section 2.5, the staff identified a need for additional information and,

therefore, issued RAI 2.5-1 dated June 11, 2012, regarding the inclusion of control circuits of the 

switchyard circuit breakers (at the transmission voltage) in the scope of license renewal. In its 

response letter dated July 2, 2012, the applicant stated that the control circuits for the 

switchyard circuit breakers are included in the scope of license renewal as they are part of the 

SBO recovery path. The staff finds that the applicant‘s response is consistent with SRP-LR, 

and, therefore, is acceptable. The staff’s concern described in RAI 2.5-1 is resolved.

2.5.1.3 Conclusion

The staff reviewed the LRA, FSAR, and RAI responses to determine if the applicant identified all 

SSCs within the scope of license renewal and to determine if the applicant had identified all 

components subject to an AMR. On the basis of its review, the staff concludes that the 

applicant adequately identified the electrical and I&C systems components within the scope of 

license renewal as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.6 Conclusion for Scoping and Screening

The staff reviewed the information in LRA Section 2, “Scoping and Screening Methodology for 

Identifying Structures and Components Subject to Aging Management Review and 

Implementation Results.” The staff finds that the applicant’s scoping and screening 

methodology is consistent with the requirements of 10 CFR 54.21(a)(1). The staff also finds 

that the applicant’s scoping and screening methodology is consistent with the staff’s position on 

the treatment of safety-related and nonsafety-related SSCs within the scope of license renewal 

and on SCs subject to an AMR as required by 10 CFR 54.4 and 10 CFR 54.21(a)(1).

On the basis of its review, the staff concludes that the applicant adequately identified those 

SSCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and those 

SCs that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

3-1

SECTION 3

AGING MANAGEMENT REVIEW RESULTS

This safety evaluation report (SER) section evaluates aging management programs (AMPs) and 

aging management reviews (AMRs) for Callaway Plant Unit 1 (Callaway) by the staff of the 

U.S. Nuclear Regulatory Commission (NRC or the staff).

In Appendix B of its license renewal application (LRA), Union Electric Company, doing business 

as Ameren Missouri (the applicant), described the 42 AMPs that it relies on to manage or 

monitor the aging of passive, long-lived structures and components (SCs).

In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA 

Section 2 as within the scope of license renewal and subject to an AMR.

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report

In preparing its LRA, the applicant credited NUREG-1801, Revision 2, “Generic Aging Lessons 

Learned (GALL) Report,” dated December 2010. The GALL Report contains the staff’s generic 

evaluation of the existing plant programs and documents the technical basis for determining 

where existing programs are adequate without modification and where existing programs should 

be augmented for the period of extended operation. The evaluation results documented in the 

GALL Report indicate that many of the existing programs are adequate to manage the aging 

effects for particular license renewal SCs. The GALL Report also contains recommendations on 

specific areas for which existing programs should be augmented for license renewal. An 

applicant may reference the GALL Report in its LRA to demonstrate that its programs 

correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or 

monitor the aging of SCs subject to an AMR. If an applicant commits to implementing these 

staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, 

improving the efficiency and effectiveness of the license renewal review process. The 

GALL Report also serves as a quick reference for applicants and staff reviewers to AMPs and 

activities that the staff has determined will adequately manage or monitor aging during the 

period of extended operation.

The GALL Report identifies the following: 

• systems, structures, and components (SSCs)

• SCs materials

• environments to which the SCs are exposed

• aging effects of the materials and environments

• AMPs credited with managing or monitoring the aging effects

• recommendations for further applicant evaluations of aging management for certain 

component types

The staff performed its review in accordance with the requirements of Title 10, Part 54, of the 

Code of Federal Regulations (CFR), “Requirements for Renewal of Operating Licenses for 
AGING MANAGEMENT REVIEW RESULTS

3-2

Nuclear Power Plants”; the guidance provided in NUREG-1800, Revision 2, “Standard Review 

Plan for Review of License Renewal Applications for Nuclear Power Plants” (SRP-LR), dated 

December 2010; and the guidance provided in the GALL Report. 

In addition to its LRA review, the staff conducted an onsite audit of selected AMPs during the 

weeks of April 30 and May 7, 2012, as described in the “Aging Management Programs audit 

report Regarding the Callaway Plant Unit 1 License Renewal Application,” dated 

August 9, 2012. The onsite audits and reviews are designed for maximum efficiency of the 

staff’s LRA review. The applicant can respond to questions, the staff can readily evaluate the 

applicant’s responses, and the need for formal correspondence between the staff and the 

applicant is reduced, resulting in improvement review efficiency.

3.0.1 Format of the License Renewal Application

The applicant submitted an application that follows the standard LRA format agreed to by the 

staff and the Nuclear Energy Institute (NEI) by letter dated December 15, 2011. 

The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presents 

the results of AMR information in the following two table types:

(1) Table 1s: Table 3.x.1—where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, and “1” indicates that this table type is the 

first in LRA Section 3

(2) Table 2s: Table 3.x.2-y—where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, “2” indicates that this table type is the second 

in LRA Section 3, and “y” indicates the system table number

The content of the previous LRAs and of the Callaway application is essentially the same. 

The intent of the revised format of the Callaway LRA was to modify the tables in LRA Section 3 

to provide additional information that would assist in the staff’s review. In Table 1s, the 

applicant summarized the portions of the application that it considered to be consistent with the 

GALL Report. In Table 2s, the applicant identified the linkage between the scoping and 

screening results in LRA Section 2 and the AMRs in LRA Section 3.

3.0.1.1 Overview of Table 1s 

Each Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the 

corresponding tables of the GALL Report. The table is essentially the same as Tables 1 

through 6 provided in the GALL Report, Volume 1, except that the “Type” column has been 

replaced by an “Item Number” column and the “Related Generic Item” and “Unique Item” 

columns have been replaced by a “Discussion” column. The applicant used the “Discussion” 

column to provide clarifying and amplifying information. The following are examples of 

information that might be contained within this column:

• further evaluation recommended—information or reference to where that information is 

located

• name of a plant-specific program

• exceptions to the GALL Report assumptions
AGING MANAGEMENT REVIEW RESULTS

3-3

• discussion of how the line is consistent with the corresponding AMR item in the 

GALL Report when the consistency may not be obvious

• discussion of how the item is different from the corresponding AMR item in the 

GALL Report (e.g., when an exception is taken to a GALL Report AMP)

The format of Table 1s allows the staff to align a specific Table 1 row with the corresponding 

GALL Report table row so that the consistency can be checked efficiently.

3.0.1.2 Overview of Table 2s

Each Table 3.x.2-y (Table 2) provides the detailed AMR results for those components identified 

in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or 

components within a system grouping (e.g., reactor coolant systems (RCS), engineered safety 

features (ESF), auxiliary systems, etc.). For example, the ESF group contains tables specific to 

the containment spray system, residual heat removal (RHR) system, and safety injection 

system. Each Table 2 consists of the following nine columns:

(1) Component Type: The first column lists LRA Section 2 component types subject to an 

AMR in alphabetical order.

(2) Intended Function: The second column identifies the license renewal intended 

functions, including abbreviations, where applicable, for the listed component types. 

Definitions and abbreviations of intended functions are in LRA Table 2.1-1.

(3) Material: The third column lists the particular construction material(s) for the component 

type.

(4) Environment: The fourth column lists the environments to which the component types 

are exposed. A list of these environments in LRA Tables 3.0-1. 3.0-2, and 3.0-3 

indicates internal and external service environments.

(5) Aging Effect Requiring Management (AERM): The fifth column lists AERMs. As part of 

the AMR process, the applicant determined any AERMs for each combination of 

material and environment.

(6) AMPs: The sixth column lists the AMPs that the applicant uses to manage the identified 

aging effects.

(7) The GALL Report 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 Report, the 

applicant left the column blank 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 AMR item summary number should be listed in LRA 

Table 2. If there is no corresponding item in the GALL Report, column eight is left blank. 

In this manner, the information from the two tables can be correlated.

(9) Notes: The ninth column lists the corresponding notes used to identify how the 

information in each Table 2 aligns with the information in the GALL Report. The notes, 

identified by letters, were developed by an NEI working group and will be used in future 
AGING MANAGEMENT REVIEW RESULTS

3-4

LRAs. Any plant-specific notes identified by numbers provide additional information 

about the consistency of the AMR item with the GALL Report.

3.0.2 Staff’s Review Process

The staff conducted the following three types of evaluations of the AMRs and AMPs:

(1) For items that the applicant stated were consistent with the GALL Report, the staff 

conducted either an audit or a technical review to determine consistency.

(2) For items that the applicant stated were consistent with the GALL Report with 

exceptions, enhancements, or both, the staff conducted either an audit or a technical 

review of the item to determine consistency. In addition, the staff conducted either an 

audit or a technical review of the applicant’s technical justifications for the exceptions or 

the adequacy of the enhancements.

The SRP-LR states that an applicant may take one or more exceptions to specific 

GALL Report AMP elements; however, any exception to the GALL Report AMP should 

be described and justified. Therefore, the staff considers exceptions as being portions 

of the GALL Report AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program that does not meet 

all the program elements defined in the GALL Report AMP. However, the applicant may 

make a commitment to augment the existing program to satisfy the GALL Report AMP 

before the period of extended operation. Therefore, the staff considers these 

augmentations or additions to be enhancements. Enhancements include, but are not 

limited to, activities needed to ensure consistency with the GALL Report 

recommendations. Enhancements may expand, but not reduce, the scope of an AMP.

(3) For other items, the staff conducted a technical review to verify conformance with 

10 CFR 54.21(a)(3) requirements.

These audits and technical reviews of the applicant’s AMPs and AMRs determine if the effects 

of aging on SCs can be adequately managed so that the intended functions can be maintained 

consistent with the plant’s current licensing basis (CLB) for the period of extended operation, as 

required by 10 CFR Part 54.

3.0.2.1 Review of AMPs

For those AMPs for which the applicant had claimed consistency with the GALL Report AMPs, 

the staff conducted either an audit or a technical review to confirm that the applicant’s AMPs 

were consistent with the GALL Report. For each AMP that had one or more deviations, the staff 

evaluated each deviation to determine whether the deviation was acceptable and whether the 

AMP, as modified, would adequately manage the aging effect(s) for which it was credited. For 

AMPs that were not addressed 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”—should include the specific SCs subject to a license renewal 

AMR.

(2) “preventive actions”—should prevent or mitigate aging degradation.

(3) “parameters monitored or inspected”—should be linked to the degradation of the 

particular structure or component-intended function(s).
AGING MANAGEMENT REVIEW RESULTS

3-5

(4) “detection of aging effects”—should occur before there is a loss of structure or 

component-intended function(s). This includes aspects such as method or technique 

(i.e., visual, volumetric, surface inspection), frequency, sample size, data collection, and 

timing of new and one-time inspections to ensure timely detection of aging effects.

(5) “monitoring and trending”—should provide predictability of the extent of degradation, as 

well as timely corrective or mitigative actions.

(6) “acceptance criteria”—these criteria, against which the need for corrective action will be 

evaluated, should ensure that the structure or component-intended function(s) are 

maintained under all CLB design conditions during the period of extended operation.

(7) “corrective actions”—these actions, including root cause determination and prevention of 

recurrence, should be timely.

(8) “confirmation process”—should ensure that preventive actions are adequate and that 

appropriate corrective actions have been completed and are effective.

(9) “administrative controls”—should provide for a formal review and approval process.

(10) “operating experience”—this experience of the AMP, including past corrective actions 

resulting in program enhancements or additional programs, should provide objective 

evidence to support the conclusion that the effects of aging will be adequately managed 

so that the SC intended function(s) will be maintained during the period of extended 

operation.

Details of the staff’s audit evaluation of program elements (1) through (6) and (10) are 

documented in the AMP audit report and summarized in SER Section 3.0.3.

The staff reviewed the applicant’s Quality Assurance (QA) Program and documented its 

evaluations in SER Section 3.0.4. The staff’s evaluation of the QA Program included an 

assessment of the “corrective actions,” “confirmation process,” and “administrative controls” 

program elements.

The staff reviewed the information on the “operating experience” program element and 

documented its evaluation in SER Sections 3.0.3 and 3.0.5.

3.0.2.2 Review of AMR Results

Each LRA Table 2 contains information concerning whether the AMRs identified by the 

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed 

the intended function, material, environment, AERM, and AMP combination for a particular 

system component type. Item numbers in column seven of the LRA, “NUREG-1801 Item,” 

correlate to an AMR combination as identified in the GALL Report. A blank in column seven 

indicates that the applicant was unable to identify an appropriate correlation in the GALL Report. 

The staff also conducted a technical review of combinations not consistent with the 

GALL Report. The next column, “Table 1 Item,” refers to a number indicating the correlating 

row in Table 1.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which it does not recommend further evaluation, the staff determined, on 

the basis of its review, whether the plant-specific components of these GALL Report component 

groups were bounded by the GALL Report evaluation.
AGING MANAGEMENT REVIEW RESULTS

3-6

The applicant noted for each AMR item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with notes A through E, 

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these items to verify consistency with the GALL Report and validity of the AMR 

for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff audited these items to verify consistency with the GALL Report and confirmed 

that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. 

The staff also determined whether the applicant’s AMP was consistent with the GALL Report 

AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL Report AMP. This note indicates that the applicant was unable to find 

a listing of some system components in the GALL Report; however, the applicant identified in 

the GALL Report a different component with the same material, environment, aging effect, and 

AMP as the component under review. The staff audited these items to verify consistency with 

the GALL Report. The staff also determined if the AMR item of the different component was 

applicable to the component under review and if the AMR was valid for the site-specific 

conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL Report AMP. The staff audited these items to verify consistency 

with the GALL Report. The staff confirmed whether the AMR item of the different component 

was applicable to the component under review and whether the identified exceptions to 

GALL Report AMPs have been reviewed and accepted. The staff also determined if the 

applicant’s AMP was consistent with the GALL Report AMP and if the AMR was valid for the 

site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but it credits a different AMP. The staff audited these items to 

verify consistency with the GALL Report. The staff also determined if the credited AMP would 

manage the aging effect consistently with the GALL Report AMP and if the AMR was valid for 

the site-specific conditions.

The applicant defined its mechanical service environments in LRA Table 3.0-1. LRA 

Table 3.0-1 states that the Callaway water environments encompass the GALL Report defined 

water environments for water temperatures both above and below 60°C (140°F). For example, 

the “closed cycle cooling water” environment in the LRA encompasses the GALL Report defined 

environments of “closed cycle cooling water” and “closed cycle cooling water > 60°C (140°F).” 

Also, the “secondary water” environment in the LRA encompasses the GALL Report defined 

environments of “treated water” and “treated water > 60°C (140°F).” GALL Report Section IX.D 

indicates that the susceptibility of stainless steels to stress-corrosion cracking (SCC) in water 

environments depends on whether the water temperature is above or below 60°C (140°F). 
AGING MANAGEMENT REVIEW RESULTS

3-7

Because the applicant defined its water environments as encompassing the GALL Report 

defined water environments for water temperatures both above and below the stress corrosion 

cracking threshold, the staff could not determine if the proper aging effects and aging 

management programs had been identified for those AMR items exposed to water 

environments. By letter dated July 5, 2012, the staff issued Request for Additional Information 

(RAI) 3.0.1-1 requesting that the applicant (a) identify which components are exposed to water 

environments with temperatures greater than the stress corrosion cracking threshold and 

(b) add AMR items to manage stress corrosion cracking, as necessary. 

In its response dated August 6, 2012, the applicant stated that stainless steel components 

exposed to water environments greater than 60°C (140°F) have an aging effect of cracking. 

The applicant provided a list of LRA tables that include such components, and it also revised 

LRA Table 3.3.2-22 to add AMR items for stainless steel components in the standby diesel 

generator engine system that are susceptible to stress corrosion cracking. 

In a teleconference with the applicant dated August 23, 2012, the staff requested clarification of 

the applicant’s response regarding which AMR items in the LRA have a water environment with 

a temperature greater than 60°C (140°F). The applicant clarified that it reviewed the LRA and 

confirmed that all stainless steel components that are exposed to water environments with 

temperatures greater than 60°C (140°F) have an AMR item for cracking caused by stress 

corrosion cracking (i.e., the cracking aging effect can be used as an indicator of an elevated 

temperature water environment in the LRA). In the teleconference, the staff also discussed the 

applicant’s list of affected LRA tables, which appeared to be incomplete. By letter dated 

September 18, 2012, the applicant supplemented its original RAI response to add additional 

tables to the list of those containing affected components.

The staff finds the applicant’s response, as supplemented, acceptable because the applicant 

identified which stainless steel components in the LRA are exposed to water environments with 

temperatures greater than 60°C (140°F), such that the staff can determine whether the proper 

aging effects and aging management programs have been identified. The staff’s individual 

AMR item evaluations for components exposed to water environments are documented in the 

appropriate SER sections for their associated LRA Table 1 references. The staff’s concern 

described in RAI 3.0.1-1 is resolved.

3.0.2.3 FSAR Supplement

Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also 

reviewed the final safety analysis report (FSAR) supplement that summarizes the applicant’s 

programs and activities for managing the effects of aging for the period of extended operation, 

as required by 10 CFR 54.21(d).

3.0.2.4 Documentation and Documents Reviewed

In performing its review, the staff used the LRA, LRA supplements, the SRP-LR, the 

GALL Report, and Requests for Additional Information (RAI) responses. Also, during the onsite 

audit, the staff examined the applicant’s justifications, as documented in the audit summary 

report, 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.
AGING MANAGEMENT REVIEW RESULTS

3-8

3.0.3 Aging Management Programs

SER Table 3.0-1 below presents the AMPs credited by the applicant and described in LRA 

Appendix B. The table also indicates the GALL Report AMP that the applicant claimed its AMP 

was consistent with and whether the program is a new or existing AMP. The SER section in 

which the staff’s evaluation of the program is documented also is provided.

Table 3.0-1 Callaway Aging Management Programs

Applicant AMP LRA 

sections

New or 

existing 

program

Applicant 

comparison to 

the 

GALL Report

GALL Report AMPs SER section

[American Society of 

Mechanical 

Engineers] ASME 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD

A1.1

B2.1.1

Existing Consistent XI.M1, “ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC,

and IWD”

3.0.3.1.1

Water Chemistry A1.2

B2.1.2

Existing Consistent XI.M2, “Water Chemistry” 3.0.3.1.2

Reactor Head 

Closure Studs Bolting

A1.3

B2.1.3

Existing Consistent XI.M3, “Reactor Head 

Closure Stud Bolting”

3.0.3.1.3

Boric Acid Corrosion A1.4

B2.1.4

Existing Consistent with 

enhancements

XI.M10, “Boric Acid 

Corrosion”

3.0.3.2.1

Cracking of 

Nickel-Alloy 

Components and 

Loss of Material 

Caused by Boric 

Acid-Induced 

Corrosion in Reactor 

Coolant Pressure 

Boundary 

Components

A1.5

B2.1.5

Existing Consistent XI.M11B, “Cracking of 

Nickel-Alloy Components 

and Loss of Material Due 

to Boric Acid-Induced 

Corrosion in Reactor 

Coolant Pressure 

Boundary Components”

3.0.3.1.4

PWR Vessel Internals A1.6

B2.1.6

New Consistent XI.M16A, “PWR Vessel 

Internals”

3.0.3.1.5

Flow-Accelerated 

Corrosion

A1.7

B2.1.7

Existing Consistent XI.M17, 

“Flow-Accelerated 

Corrosion”

3.0.3.1.6

Bolting Integrity A1.8

B2.1.8

Existing Consistent with 

enhancements

XI.M18, “Bolting Integrity” 3.0.3.2.2

Steam Generators A1.9

B2.1.9

Existing Consistent XI.M19, “Steam 

Generators”

3.0.3.1.7

Open-Cycle Cooling 

Water System

A1.10

B2.1.10

Existing Consistent with 

enhancements

XI.M20, “Open-Cycle 

Cooling Water System”

3.0.3.2.3

Closed Treated Water 

Systems

A1.11

B2.1.11

Existing Consistent with 

enhancements

XI.M21A, “Closed 

Treated Water Systems”

3.0.3.2.4

Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to Refueling) 

Handling Systems

A1.12

B2.1.12

Existing Consistent with 

enhancements

XI.M23, “Inspection of 

Overhead Heavy Load 

and Light Load (Related 

to Refueling) Handling 

Systems”

3.0.3.2.5

Fire Protection A1.13

B2.1.13

Existing Consistent with 

enhancements

XI.M26, “Fire Protection” 3.0.3.2.6
AGING MANAGEMENT REVIEW RESULTS

3-9

Applicant AMP LRA 

sections

New or 

existing 

program

Applicant 

comparison to 

the 

GALL Report

GALL Report AMPs SER section

Fire Water System A1.14

B2.1.14

Existing Consistent with 

enhancements 

and exceptions

XI.M27, “Fire Water 

System”

3.0.3.2.7

Aboveground Metallic 

Tanks

A1.15

B2.1.15

New Consistent with 

exception

XI.M29, “Aboveground 

Metallic Tanks”

3.0.3.2.8

Fuel Oil Chemistry A1.16

B2.1.16

Existing Consistent with 

enhancements

XI.M30, “Fuel Oil 

Chemistry”

3.0.3.2.9

Reactor Vessel 

Surveillance

A1.17

B2.1.17

Existing Consistent with 

enhancements

XI.M31, “Reactor Vessel 

Surveillance”

3.0.3.2.10

One-Time Inspection A1.18

B2.1.18

New Consistent XI.M32, “One-Time 

Inspection”

3.0.3.1.8

Selective Leaching A1.19

B2.1.19

New Consistent with 

exception

XI.M33, “Selective 

Leaching”

3.0.3.2.11

One-Time Inspection 

of ASME Code 

Class 1 Small-Bore 

Piping

A1.20

B2.1.20

New Consistent XI.M35, “One-Time 

Inspection of ASME 

Code Class 1 Small-Bore 

Piping”

3.0.3.1.9

External Surfaces 

Monitoring of 

Mechanical 

Components

A1.21

B2.1.21

New Consistent XI.M36, “External 

Surfaces Monitoring of 

Mechanical Components”

3.0.3.1.10

Flux Thimble Tube 

Inspection

A1.22

B2.1.22

Existing Consistent XI.M37, “Flux Thimble 

Tube Inspection”

3.0.3.1.11

Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components

A1.23

B2.1.23

New Consistent with 

exception

XI.M38, “Inspection of 

Internal Surfaces in 

Miscellaneous Piping and 

Ducting Components”

3.0.3.2.12

Lubricating Oil 

Analysis

A1.24

B2.1.24

Existing Consistent with 

enhancement

XI.M39, “Lubricating Oil 

Analysis”

3.0.3.2.13

Buried and 

Underground Piping 

and Tanks

A1.25

B2.1.25

New Consistent with 

exceptions

XI.M41, “Buried and 

Underground Piping and 

Tanks”

3.0.3.2.14

ASME Section XI, 

Subsection IWE

A1.26

B2.1.26

Existing Consistent with 

enhancements

XI.S1, “ASME Section XI, 

Subsection IWE”

3.0.3.2.15

ASME Section XI, 

Subsection IWL

A1.27

B2.1.27

Existing Consistent XI.S2, “ASME Section XI, 

Subsection IWL”

3.0.3.1.12

ASME Section XI, 

Subsection IWF

A1.28

B2.1.28

Existing Consistent with 

enhancements

XI.S3, “ASME Section XI 

Subsection IWF”

3.0.3.2.16

10 CFR PART 50, 

Appendix J

A1.29

B2.1.29

Existing Consistent XI.S4, “10 CFR Part 50 

Appendix J”

3.0.3.1.13

Masonry Walls A1.30

B2.1.30

Existing Consistent XI.S5, “Masonry Walls” 3.0.3.1.14

Structures Monitoring A1.31

B2.1.31

Existing Consistent with 

enhancements

XI.S6, “Structures 

Monitoring”

3.0.3.2.17

RG 1.127, Inspection 

of Water-Control 

Structures Associated 

with Nuclear Power 

Plants

A1.32

B2.1.32

Existing Consistent XI.S7, “RG 1.127, 

Inspection of 

Water-Control Structures 

Associated with Nuclear 

Power Plants”

3.0.3.1.15
AGING MANAGEMENT REVIEW RESULTS

3-10

Applicant AMP LRA 

sections

New or 

existing 

program

Applicant 

comparison to 

the 

GALL Report

GALL Report AMPs SER section

Protective Coating 

Monitoring and 

Maintenance Program

A1.33

B2.1.33

Existing Consistent with 

enhancements 

and exception

XI.S8, “Protective 

Coating Monitoring and 

Maintenance Program”

3.0.3.2.18

Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

A1.34

B2.1.34

Existing Consistent with 

enhancements

XI.E1, “Insulation 

Material for Electrical 

Cables and Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

3.0.3.2.19

Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used 

in Instrumentation 

Circuits

A1.35

B2.1.35

Existing Consistent with 

enhancements

XI.E2, “Insulation 

Material for Electrical 

Cables and Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits”

3.0.3.2.20

Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

A1.36

B2.1.36

Existing Consistent with 

enhancements

XI.E3, “Inaccessible 

Power Cables Not 

Subject to 10 CFR 50.49 

Environmental 

Qualification 

Requirements”

3.0.3.2.21

Electrical Cable 

Connections Not 

Subject To 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

A1.37

B2.1.37

New Consistent XI.E6, “Electrical Cable 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements”

3.0.3.1.16

Monitoring of 

Neutron-Absorbing 

Materials Other than 

Boraflex

A1.38

B2.1.38

New Consistent XI.M40, “Monitoring of 

Neutron-Absorbing 

Materials Other than 

Boraflex”

3.0.3.1.17

Metal Enclosed Bus A1.39

B2.1.39

New Consistent XI.E4, “Metal Enclosed 

Bus”

3.0.3.1.18

Fatigue Monitoring A2.1

B3.1

Existing Consistent with 

enhancements

X.M1, “Fatigue 

Monitoring”

3.0.3.2.22

Environmental 

Qualification (EQ) of 

Electrical 

Components

A2.2

B3.2

Existing Consistent X.E1, “Environmental 

Qualification (EQ) of 

Electric Components”

3.0.3.1.19

Concrete 

Containment Tendon 

Prestress

A2.3

B3.3

Existing Consistent with 

enhancements

X.S1, “Concrete 

Containment Tendon 

Prestress”

3.0.3.2.23
AGING MANAGEMENT REVIEW RESULTS

3-11

3.0.3.1 AMPs Consistent with the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as consistent with the 

GALL Report:

• ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

• Water Chemistry

• Reactor Head Closure Stud Bolting

• Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced 

Corrosion in Reactor Coolant Pressure Boundary Components

• [Pressurized Water Reactor (PWR)] Vessel Internals

• Flow-Accelerated Corrosion

• Steam Generators

• One-Time Inspection

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping

• External Surfaces Monitoring of Mechanical Components

• Flux Thimble Tube Inspection

• ASME Section XI, Subsection IWL

• 10 CFR PART 50, Appendix J

• Masonry Walls

• 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

• Monitoring of Neutron-Absorbing Materials Other than Boraflex

• Metal Enclosed Bus

• Environmental Qualification (EQ) of Electrical 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 B2.1.1 describes the 

existing American Society of Mechanical Engineers (ASME) Section XI Inservice Inspection 

(ISI), Subsections IWB, IWC, and IWD Program, as consistent with GALL Report AMP XI.M1, 

“ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD.” The LRA states that 

this program manages cracking, loss of fracture toughness, and loss of material in Class 1, 2, 

and 3 piping and components within the scope of license renewal. The LRA also states that this 

program includes periodic visual, surface, volumetric examinations, and leakage tests of 

Class 1, 2, and 3 pressure-retaining components, including welds, pump casings, valve bodies, 

integral attachments, and pressure-retaining bolting. 

In addition, the LRA states that these components are identified in ASME Code Section XI 

Tables IWB-2500-1, IWC-2500-1, and IWD-2500-1 for Class 1, 2, and 3 components, 

respectively. The LRA states that the program directs that repair and replacement activities be 
AGING MANAGEMENT REVIEW RESULTS

3-12

performed in accordance with IWA-4000. The LRA further states that this program is updated 

during each successive 120-month (i.e., 10-year) inspection interval to comply with the 

requirements of the ASME Code Section XI, Subsections IWB, IWC, and IWD, edition and 

addenda in accordance with 10 CFR 50.55a, subject to prior approval of the edition and 

addenda by the NRC. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M1. As discussed in the audit 

report, the staff confirmed that each element of the applicant’s program is consistent with the 

corresponding element of GALL Report AMP XI.M1. 

The “detection of aging effects” program element in GALL Report AMP XI.M1 states that ASME 

Code Section XI Tables IWB-2500-1 and IWC-2500-1 are used to determine the examination 

requirements for Class 1 and Class 2 components, respectively. The staff noted that the 

applicant implemented risk-informed inservice inspections (RI-ISI) with Examination 

Category R-A in lieu of Categories B-F, B-J, C-F-1, and C-F-2 for the current 10-year ISI interval 

as approved by the NRC. The RI-ISI provides alternative inspection requirements for a subset 

of Class 1 and Class 2 piping welds. The staff also noted that the use of RI-ISI is only approved 

for the current 10-year ISI interval. Future implementation of the RI-ISI is subject to NRC 

approval, in accordance with 10 CFR Part 55.55a, for each subsequent 10-year ISI interval, 

including the period of extended operation. The staff confirmed during the onsite audit that the 

applicant’s ISI Program plan calls for a review of the RI-ISI implementation for future inspection 

intervals. The staff finds this acceptable because the applicant will need NRC approval for use 

of this RI-ISI relief request for future inspection intervals.

In addition, the staff noted that the applicant updates its program every 10 years (120 months) 

to the latest ASME Code Section XI as approved by the NRC before the start of the inspection 

interval. The applicant’s ISI Program is currently in the third 10-year ISI interval, from 

December 19, 2004, to December 18, 2014. The applicant’s fourth 10-year ISI interval will be 

from December 19, 2014, to December 18, 2024. The proposed period of extended operation 

will commence on October 19, 2024. The current ASME Code of record for the applicant’s 

ISI Program is the ASME Code Section XI 1998 Edition with 2000 addenda of the ASME Code.

Based on its audit, and review of the applicant’s ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program, the staff finds that program elements one through 

six, for which the applicant claimed consistency with the GALL Report, are consistent with the 

corresponding program elements of GALL Report AMP XI.M1.

Operating Experience. LRA Section B2.1.1 summarizes operating experience related to the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. 

The applicant indicated that this program is based on the ASME Code Section XI, 

Subsections IWB, IWC, and IWD, which is based on industrywide operating experience, 

research data, and technical evaluations. The applicant stated that plant-specific examples are 

documented in its ISI Summary Reports, as well as in the Corrective Action Program (CAP) 

records. 

LRA Section B2.1.1 also provides a specific example of the applicant’s operating experience. 

The LRA states that during refueling outage (RFO) 13 (spring 2004) the ISI examination 

detected one indication in a nozzle weld that required an evaluation for continued operation. 

The applicant’s evaluation concluded that the indication was a result of fabrication. The flaw 

had propagated to the inside surface, but the growth toward the outside surface was minimal to 
AGING MANAGEMENT REVIEW RESULTS

3-13

nonexistent. The flaw was found to be acceptable by analytical evaluation, as allowed by 

ASME Code Section XI, Section IWB-3600. Based on a technical evaluation of the indication, 

the course of action was to monitor the indication for change. The LRA states that the 

monitoring will use the same nondestructive evaluation (NDE) techniques as the current to 

ensure accurate comparison. The LRA also states that the monitoring interval coincides with 

the ASME Code’s requirement for re-inspection within 3 years. The LRA further states that a 

subsequent inspection was performed during RFO 15 in 2007 and indicated that the flaw had 

not grown. In addition, the flaw also will be examined in RFO 19 in 2013 and in RFO 21 in 2016 

or RFO 22 in 2017. 

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant. As discussed in the audit report, the staff conducted an 

independent search of the plant operating experience information to determine if the applicant 

had adequately evaluated and incorporated operating experience related to this program

The staff also performed an independent search of plant operating experience related to the 

applicant’s program. During its audit and review, the staff identified operating experience for 

which it determined the need for additional clarification and resulted in the issuance of RAIs as 

discussed below.

The staff reviewed the applicant’s ISI summary reports dated from 1999 to 2012 and noted that 

degradation, including multiple pin hole leaks, have been detected in the site’s essential service 

water (ESW) piping system. However, it was not clear to the staff how these aging effects were 

effectively addressed since no details had been provided. By letter dated July 18, 2012, the 

staff issued RAI B2.1.1-1 requesting the applicant to discuss and justify the ISI Program’s 

effectiveness in addressing the noted aging effects in light of the failures, as documented in its 

ISI summary reports. 

In its response dated August 21, 2012, the applicant stated that most of the leaks identified in 

the ISI summary reports from 1999 to 2012 have been in the ESW system. The applicant 

stated that “leaks were caused or exacerbated by microbiologically-[influenced] corrosion (MIC) 

of carbon steel surfaces.” The applicant also stated that the failures were addressed effectively 

and the number of leaks detected was drastically decreased in recent ISI Program inspections. 

In its response, the applicant provided detailed corrective actions and mitigative measures that 

the ISI Program implemented to address the aging effects. The measures included 

enhancement of chemistry control in the ESW system and replacement of susceptible and 

degraded piping with more corrosion-resistant piping. The applicant further stated that the 

positive trend in recent inspections indicates that the aging effects have been addressed. The 

staff noted the corrective actions and mitigative measures that the applicant’s program 

implemented. As part of the corrective actions, the applicant has replaced the degraded piping 

with more corrosion-resistant piping. In addition, the applicant has improved its water treatment 

to eliminate the root cause, as part of its mitigative measures. The staff also noted that there 

were significantly fewer leaks in the most recent ISI Program inspections, indicating that the 

program’s implementation has been effective in addressing aging and degradation. The staff 

finds the applicant’s response acceptable because the applicant performed appropriate 

corrective actions and adequate mitigative measures to address the aging effects. Therefore, 

the staff’s concern described in RAI B2.1.1-1 is resolved.

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

RAI B2.1.1-1, the staff finds that the applicant has appropriately evaluated plant-specific and 
AGING MANAGEMENT REVIEW RESULTS

3-14

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective action. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M1 was 

evaluated.

FSAR Supplement. LRA Section A1.1, as amended by letter dated February 14, 2013, provides 

the FSAR supplement for the ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program. The FSAR supplement was amended in response to RAI B2.1.5-4b

discussed in SER Section 3.0.3.1.4. The staff reviewed this FSAR supplement description of 

the program and noted that it is consistent with the recommended description for this type of 

program, as described in SRP-LR Table 3.0-1. The staff finds that the information in the FSAR 

supplement, as amended by letter dated February 14, 2013, is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program, the staff concludes that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended 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 

FSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

3.0.3.1.2 Water Chemistry

Summary of Technical Information in the Application. LRA Section B2.1.2 describes the 

existing Water Chemistry Program as consistent with GALL Report AMP XI.M2, “Water 

Chemistry.” The LRA states that the Water Chemistry Program manages loss of material, 

cracking, reduction of heat transfer, and wall thinning in components exposed to a treated water 

environment. The program comprises the primary water chemistry program, which includes 

monitoring and control of the chemical environment in the RCS and related auxiliary systems, 

and the secondary water chemistry program, which includes monitoring and control of the 

chemical environment in the steam generator secondary side and the secondary cycle systems. 

The LRA states that the primary water chemistry program is consistent with Electric Power 

Research Institute (EPRI) 1014986, Revision 6, “PWR Primary Water Chemistry Guidelines,” 

Volumes 1 and 2, and the secondary water chemistry program is consistent with EPRI 1016555, 

Revision 7, “PWR Secondary Water Chemistry Guidelines.” The LRA also states that the 

One-Time Inspection Program will be used to verify the effectiveness of the Water Chemistry 

Program. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP Xl.M2. Based on its audit of the 

applicant’s Water Chemistry Program, the staff finds that program elements one through six, for 

which the applicant claimed consistency with the GALL Report, are consistent with the 

corresponding program elements of GALL Report AMP XI.M2. 

Operating Experience. LRA Section B2.1.2 summarizes operating experience related to the 

Water Chemistry Program. A summary of the operating experience is given below.
AGING MANAGEMENT REVIEW RESULTS

3-15

• In 2004, the applicant replaced the main condenser tube bundles with 316L stainless 

steel tube sheets and stainless steel tubes. Previously, the main condenser consisted 

mostly of 90/10 copper/nickel and some small percentage of 304 stainless steel tubes.

• Following the replacement of the steam generators in 2005, the applicant implemented 

an optimized methoxy-propyl-amine/ethanol-amine chemistry plan, which, along with the 

replacement of key susceptible piping with more corrosion resistant material,

significantly reduced corrosion transport rates in the extraction steam and drain piping.

• In 2005, just after replacement of the steam generators, RCS samples indicated high 

sulfate concentration. The sulfate spike later was identified as oxalic acid, which is 

found in lubricants used in cutting, drilling, and hydrostatic expansion of the steam 

generator components. Oxalates degrade the performance of ion chromatographs, 

causing false sulfate measurements. The oxalates were removed by the letdown mixed 

beds.

• In 2005, the Callaway pressurizer liquid space had a dissolved oxygen concentration of 

500 parts per billion (ppb) just after an insurge of RCS water was allowed to cool the 

pressurizer surge line. Pressurizer liquid-space oxygen concentration was monitored 

every 6 hours until oxygen concentration came back down to within specification (less 

than 100 ppb). In 2010, the dissolved oxygen concentration in the pressurizer liquid 

space exceeded 100 ppb for approximately 16 hours because of premature initiation of 

pressurizer spray while in Mode 5.

• Since cycle 15, Callaway has run on no condensate polisher operation, except for 

shutdowns, startups, and chemical and other transients, and with 

methoxy-propyl-amine/ethanol-amine chemistry and use of the blowdown demineralizers 

as the main secondary chemistry control. The applicant stated that it plans to continue 

to run in a no-polisher mode.

• In March 2007, a major sodium, sulfate, and chloride intrusion from a condenser 

circulating water tube rupture caused a plant shutdown. A single tube rupture was 

located in the condenser. The applicant determined that the rupture was the result of 

the failure of a 10-inch slope-drain angle iron. The applicant repaired the support.

• In 2007, the applicant evaluated NRC Information Notice (IN) 2007-37, “Buildup of 

Deposits in Steam Generator.” The applicant determined that the Callaway Steam 

Generator Program was not affected because the contributing factors cited in the IN are 

not present at Callaway. The applicant also performed a secondary-side sludge loading 

analysis and determined that the actions that it has taken to reduce the amount of 

corrosion products in the secondary systems have been effective.

The staff reviewed operating experience information in the application and during the audit 

to determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 
AGING MANAGEMENT REVIEW RESULTS

3-16

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M2 was evaluated.

FSAR Supplement. LRA Section A1.2 provides the FSAR supplement for the Water Chemistry 

Program. The staff reviewed this FSAR supplement description of the program and noted that it 

is consistent with the recommended description in SRP-LR Table 3.0-1. The staff finds that the 

information in the FSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry Program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. The staff concludes that the applicant has demonstrated 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff reviewed the FSAR 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 Reactor Head Closure Stud Bolting

Summary of Technical Information in the Application. LRA Section B2.1.3 describes the 

existing Reactor Head Closure Stud Bolting Program as consistent, with GALL Report 

AMP XI.M3, “Reactor Head Closure Stud Bolting.” The LRA states that the Reactor Head 

Closure Stud Bolting Program manages cracking and loss of material by conducting ASME 

Code Section XI inspections of reactor vessel flange stud hole threads, reactor closure studs, 

nuts, and washers. The LRA also states that the program uses visual and volumetric 

examinations in accordance with the general requirements of ASME Code Section XI, 

Subsection IWA-2000. The LRA further states that examination and inspection requirements 

specified in the ASME Code Section XI, Subsection IWB, Table IWB-2500-1, are used. 

The LRA states that reactor vessel studs are removed from the reactor vessel flange during 

each RFO, when possible. In addition, the LRA states that if a stud is stuck, a stainless steel or 

fiberglass protective cover is installed before cavity flooding. The LRA also states that the 

program has proven to be effective in preventing and detecting potential aging effects of reactor 

vessel flange stud hole threads, closure studs, nuts, and washers.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M3. For the “detection of aging 

effects” and “monitoring and trending” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

During the LRA review and the audit of the applicant’s operating experience for the AMP, the 

staff noted that on several occasions, the applicant’s closure studs became stuck during stud 

insertion or removal activities. During RFO 3 (spring 1989), five stuck studs were destructively 

removed from their reactor pressure vessel (RPV) flange stud hole locations. Subsequent to 

the removal of the studs, the applicant determined that the corresponding RPV lower flange 

stud hole locations had damaged threads, which resulted in fewer threads than the original 

design. In addition, during stud installation in RFO 8 (fall 1996), stud No. 18 became stuck with 

only partial RPV flange hole thread engagement (i.e., the stud was not completely threaded into 

the hole). The staff noted that stud No. 18 has not been removed during subsequent outages. 

The staff is concerned that examinations performed in accordance with the Reactor Head 

Closure Stud Bolting Program may not be capable of detecting loss of material for the flange 

hole threads or quantifying the amount of wear or damage of the portion of the threads thought 

to be engaged. In addition, the staff noted that, when studs are stuck in place, corrosion due to
AGING MANAGEMENT REVIEW RESULTS

3-17

the boric acid environment during cavity flooding could go unmonitored if the studs were never 

removed for examination.

By letter dated July 18, 2012, the staff issued RAI B2.1.3-1 to request that the applicant clarify 

how the program will detect loss of material caused by wear or corrosion (including potential 

boric acid corrosion) and quantify the potential amount of damage in areas of the studs and 

lower flange (including engaged threaded regions and remaining stud hole areas below the stud 

bottom faces), when a stud is not removed during an outage.

In its response dated August 21, 2012, the applicant stated that it currently has only one stuck 

stud (No. 18), which has been stuck since 1996 and is threaded to 2.625 in. above the base of 

the stud hole (i.e., 6.505 in. of thread engagement). The applicant stated that, since the 

minimum required thread engagement length is 6.31 in., stud No. 18 meets the requirement for 

minimum thread engagement. The applicant also stated that inspection of stud No. 18, before 

reactor vessel head installation, identified a small burr on the 10th and 11th threads; the burr 

was removed, and no other problems were noted with the stud threads. The applicant further 

stated that the stud hole threads were also inspected, and no damage was found. In addition, 

the applicant stated that when the stud became stuck, excessive force was not used to force it 

in, or remove it. Thus, the applicant stated its belief that no thread damage was caused by 

actions taken after the stud became stuck. 

Furthermore, the applicant stated that, in preparation for refueling, when the stuck stud is 

de-tensioned, a stress of 65,000 psi is successfully applied, which provides further evidence 

that there is no thread damage. The applicant noted that during normal operations, the stress is 

approximately 39,400 psi. The applicant also stated that, during an RFO, stud No. 18 is 

protected from exposure to borated water in the refueling pool by encapsulation to prevent 

corrosion caused by exposure to boric acid. The applicant further stated that it performs 

inspection of the stuck stud as required by ASME Code Section XI, and it believes that stud 

No. 18 will continue to perform its intended function.

The staff finds that the applicant’s response did not address the following issues: (1) the 

number of threads that may have been damaged as a result of stud No. 18’s getting stuck,

(2) uniform wear, and (3) corrosion. In addition, it is not clear from the applicant’s response if 

the noted inspections associated with stud No. 18 were performed right before it became stuck. 

The applicant’s response is also not specific in how ASME Code Section XI inspections can 

verify the current number of threads that are properly engaged for stud No. 18, particularly since 

the stud has not been removed since getting stuck in 1996. Furthermore, the staff needs 

clarification of the applicant’s basis for stating that the stuck stud has 6.505 in. of thread 

engagement remaining and that the required minimum thread engagement is 6.31 in. By letter 

dated October 24, 2012, the staff issued RAI B2.1.3-1a to request that the applicant provide 

additional information regarding its basis for determining that all the engaged threads for stud 

No. 18 are undamaged. In addition, the staff requested that the applicant provide the analyses 

used to support the determinations that stud No. 18 has 6.505 in. of thread engagement and 

that the required minimum thread engagement is 6.31 in.

In its response dated November 20, 2012, the applicant stated that the threads for stud No. 18 

and its stud hole were inspected immediately prior to installation of the stud and found to be

intact at that time. The applicant also stated that, when the stud became stuck, excessive force 

was not used in an attempt to free the stud, and therefore no threads were damaged by 

installation of the stud. The applicant further stated that, although the threads of stud No. 18 

have not been inspected for damage caused by wear or corrosion, the other 53 reactor vessel 
AGING MANAGEMENT REVIEW RESULTS

3-18

studs and stud holes have been inspected. The applicant also stated that, since 1992, no 

damage to the threads of the other studs and stud holes has been observed. The applicant 

further stated that, since stud No. 18 is exposed to the same environment as the other studs, 

except during refueling, it is reasonable to conclude that damage to the threads caused by 

corrosion or wear has not occurred. The applicant also stated that the ultrasonic test (UT) 

examination is capable of identifying cracking and severe corrosion of the threads.

In addition, the applicant provided a sketch of the stuck stud and stud hole to demonstrate its 

basis that, with the stud 2.625 in. from the bottom of the stud hole, the stuck stud still has 

6.505 in. of thread engagement. The applicant also provided the basis that only 6.31 in. of 

thread engagement is required. 

The staff finds that the applicant’s response still did not address the possibility of thread damage 

to the vessel flange or stud threads, as a result of the stud’s becoming stuck. In addition, in its 

previous response the applicant had stated that a burr was removed from threads 10 and 11 on 

stud No. 18 just before the stud was inserted.

The staff noted that the applicant did not appropriately consider the unique condition for the 

stuck stud. Specifically, the staff noted that the stresses would be higher for the stuck stud than 

at other locations because of less thread engagement. Furthermore, the staff noted that the 

applicant assumes that future tensioning and de-tensioning operations will not cause any wear, 

and that there will be no loss of material because of corrosion. This reasoning is 

non-conservative and contrary to the engineering evaluations performed in 1989, which 

recommended that if damage approaches the limiting value (6.31 in. of engagement or 19.5 

threads missing), or if the vessel is operated with a missing stud, vessel hydrotest should be 

avoided, and the plant heat up rate should be limited to half the design value to minimize the 

risk of localized plastic deformation. 

The staff also noted that, as stated by the applicant in its response, the current UT examinations 

performed on the stuck stud and its flange hole would only be able to detect cracking or severe 

thread corrosion. Since the number of fully engaged threads for this location is near the 

acceptance level, a marginal reduction in the number of properly engaged threads may bring 

the effective number of engaged threads below the acceptance criteria. Furthermore, the staff 

does not agree with the applicant’s assertion that the conditions at this location are typical of the 

remaining 53 locations. Specifically, since the stud at location No. 18 is stuck 2.625 in. from the 

bottom of the flange hole and has fewer threads engaged than normal, it has higher stresses 

than those that have no thread damage or more threads engaged. As stated earlier, this 

location would be more susceptible to localized plastic deformation.

Since the applicant’s stated acceptance criteria for the minimum allowable thread engagement 

(6.31 in.) is very close to the acceptable calculated thread engagement for stud No. 18 

(6.505 in.), the staff does not have reasonable assurance that the applicant’s current UT 

examinations will detect thread degradation prior to exceeding the acceptance criteria. 

By letter dated March 26, 2013, the staff issued follow-up RAI B2.1.3-1b, requesting that the 

applicant clarify how the Reactor Head Closure Stud Bolting Program will detect thread damage 

on stud and vessel flange hole threads at locations with stuck studs. In its response dated 

April 26, 2013, the applicant stated, in part, that detensioning of stud No. 18 during each RFO 

confirms its intended function will be maintained. The applicant also stated that normal RPV 

head stud tensioning and detensioning operations performed during each RFO are a form of 

“proof test” of the adequacy of the threaded connection to support inservice RPV head stud 

loads. The applicant further stated that the minimum RPV head stud load experienced by RPV 
AGING MANAGEMENT REVIEW RESULTS

3-19

head stud No. 18 during detensioning is a 113-percent proof test of the maximum inservice 

primary plus secondary RPV head stud loading during heatup. 

The applicant stated that the 1987 evaluation which calculated the RPV head stud minimum 

thread engagement (6.31 in.) was based on a conservative methodology. The applicant also 

stated that an evaluation performed in 2013 demonstrates that the minimum RPV head stud 

engagement required to resist all primary loads is 4.77 in. The applicant further stated that the 

stuck stud No. 18 nominally has in excess of 35 percent more thread engagement than is 

required to meet American Society of Mechanical Engineers (ASME) Code limits, and that the 

margin is sufficiently large that the comments related to plastic deformation in the 1989 

evaluations do not apply to RPV stud No. 18.

The applicant stated that although the condition of the threads on the inside of the RPV head 

stud hole No. 18 cannot be observed through direct visual examination, the 2013 evaluation 

performed a bounding estimate based on the amount of force used during efforts to remove 

stud No. 18 and concluded that the effective damage could be no more than 20 percent of a 

single thread, which would result in less than 0.025 in. of lost effective thread engagement. 

The applicant also stated that stud No. 18 is protected from boric acid corrosion by 

encapsulation during refueling to prevent exposure to the boric acid in the refueling pool. The 

applicant further stated that most wear occurs when an RPV head stud is threaded in and out of 

the RPV head stud hole. Since stud No. 18 is stuck, it is not being removed or installed, 

therefore essentially there is no wear (loss of material).

In addition, the applicant stated that the existing RPV head stud handling procedures and 

practices do not damage threads. The applicant stated that with the exception of minor 

maintenance on RPV head stud No. 18 (burr removal in 1996) and RPV head stud No. 20 

(chasing lead threads), no threads have been damaged in over 20 years. The applicant also 

stated that it has not destructively removed an RPV head stud since 1989, when five stuck 

studs were removed due to their interference with the fuel transfer path and to restore 

functionality to RPV head stud No. 2. The applicant further stated that, at that time, the risks 

associated with destructive removal, which included possible introduction of foreign material, 

worker safety, dose exposure, possibility of additional damage during the repair process, 

technical challenges associated with the RPV head stud removal tooling, and failure to restore 

the normal fuel transfer path, were acceptable in order to repair the RPV. Finally, the applicant 

stated that given the above considerations, it is considered appropriate to monitor and manage 

the continued use of RPV head stud No. 18 rather than pursue its removal.

The staff finds that the applicant’s response did not fully address how the condition of the 

threads for the RPV head stud and stud hole No.18 would be monitored during the period of 

extended operation. In its response the applicant stated that normal RPV head stud tensioning 

and detensioning operations performed during each RFO is a form of “proof test” of the 

adequacy of the threaded connection to support inservice RPV head stud loads for the 

subsequent cycle. The staff does not agree that successful tensioning and detensioning 

provides adequate assurance that the threads will withstand all inservice loads in the 

subsequent operating cycle. Specifically, the tensioning and detensioning is usually performed 

at ambient temperature. In addition, during tensioning and detensioning, some of the stresses 

may be distributed or shared by the adjacent studs and flange ligaments, while during inservice 

transients the adjacent areas may not be able to share as much of the stresses.

Furthermore, the staff noted that the applicant is essentially assuming zero corrosion at the 

location of the stuck stud, because the stuck stud is encapsulated during RFOs. The staff noted 
AGING MANAGEMENT REVIEW RESULTS

3-20

that leakage past the encapsulation may occur along with leakage past the inner O-ring, and 

therefore loss of material at this location is an aging effect which requires management during 

the period of extended operation.

By letter dated August 2, 2013, the staff issued RAI B2.1.3-1c, requesting the applicant explain 

how the current aging management program (AMP) will monitor the condition of the threads on 

the stud and vessel flange hole threads, so that there is reasonable assurance that the known 

degradation and any postulated degradation along with the number of unengaged threads will 

not exceed the acceptance criteria during the period of extended operation.

In its response dated August 29, 2013, the applicant stated that it manages cracking and loss of 

material for RPV stud and stud hole No. 18 consistent with the Reactor Head Closure Bolting 

Program and in accordance with the ASME Section XI. The applicant also stated that RPV stud 

and stud hole No. 18 are protected from exposure to the borated water of the refueling pool to 

prevent loss of material due to corrosion. The applicant further stated that to allow for 

monitoring of the condition of the threads of the RPV stud and stud hole No. 18 relative to aging, 

it will remove stud No. 18 through a nondestructive or destructive means. The applicant also 

stated that the removal will be scheduled no later than 6 months prior to the period of extended 

operation or the refueling outage prior to the period of extended operation, whichever occurs 

later. The applicant further stated that if repair of the stud hole is required subsequent to the 

stud removal, the repair plan would include inspection prior to and after the repair to assess the 

as-found conditions and the results of the repair. As part of its response, the applicant 

amended LRA Table A4-1 and added Commitment No. 41, which states:

To allow for monitoring of the condition of the threads on the RPV stud and 

flange hole threads, Callaway commits to remove RPV stud No. 18 through 

nondestuctive or destructive means. If RPV stud hole repair is required following 

removal of the RPV stud No. 18, the repair plan will include inspecting the RPV 

stud hole prior to the repair to assess the as-found condition and an inspection 

after the repair is completed to assess the results of the repair.

In order to ensure that the condition of the threads for RPV stud and stud hole No.18 can be 

monitored, so that there is a reasonable assurance that it can perform its intended function 

through the period of extended operation, the staff will issue a license condition to the applicant. 

The license condition will require the applicant to remove the stuck stud prior to entering the 

period of extended operation. Therefore, the staff’s concerns described in RAIs B2.1.3-1, 

B2.1.3-1a, B2.1.3-1b, and B2.1.3-1c are resolved.

Based on its audit and review of the applicant’s Reactor Head Closure Stud Bolting Program 

and review of the applicant’s responses to RAIs B2.1.3-1, B2.1.3-1a, B2.1.3-1b, and B2.1.3-1c, 

the staff finds that the program elements 1 through 6, for which the applicant claimed 

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

GALL Report AMP XI.M3. 

Operating Experience. LRA Section B2.1.3 summarizes operating experience related to the 

Reactor Head Closure Stud Bolting Program. The applicant stated that review of owner activity 

reports for RFO since 1996 indicates that there were no repair or replacement items identified 

with reactor vessel closure studs, nuts, washers, or flange stud hole threads. The LRA states 

that during RFO 8 (fall 1996) a stud became stuck during installation, as discussed in the staff’s 

evaluation regarding stud No. 18 above.
AGING MANAGEMENT REVIEW RESULTS

3-21

The applicant also stated that Callaway experienced problems with other stuck reactor head 

closure studs. Specifically, during RFO 2 (fall 1987) five reactor head closure studs could not 

be removed from the reactor vessel flange. The applicant further stated that the studs were cut 

out during RFO 3 (spring 1989). 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its audit and review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of RAIs as 

discussed below.

The staff noted that there may be additional RPV flange stud holes that may have damaged 

threads. Specifically, RPV flange stud hole location Nos. 2, 4, 5, 7, 9, 13, 18, 25, 39, 53, and 54 

may have missing or damaged threads. The total number of locations with possible damaged 

threads represents more than 20 percent of the applicant’s total RPV closure stud bolting.

By letter dated July 18, 2012, the staff issued RAI B2.1.3-2, requesting that the applicant:

(a) Identify all RPV flange assembly studs or stud hole locations that have had past 

experience with stuck studs, damage, or missing stud/stud hole threads. For each 

location, identify when the issue was first detected, and summarize the corrective 

actions taken to resolve the issue.

(b) Clarify how the AMP performs “monitoring and trending” of relevant operating 

experience, and include an explanation on the type of evaluations that will be performed 

in individual stud or stud hole problems detected at the plant and of the entire RPV 

flange, based on the latest configuration of the flange assembly. Clarify how the 

evaluations will be used to reconcile the latest, as-known configuration of the RPV 

flange assembly against the applicable ASME Code Section III design requirements.

In its response dated August 21, 2012, the applicant provided a summary description of the 

problems encountered with its reactor vessel head closure stud bolting. The applicant stated

that the Reactor Head Closure Stud Bolting Program owner monitors the operating experience 

associated with the reactor head closure studs, nuts, and stud holes, such as repairs, 

replacements, prior evaluations or calculations, and documented aging effects. The applicant 

also stated that evaluations of reactor vessel head closure stud and stud hole problems, such 

as stuck studs or missing threads, are initiated through use of the applicant’s corrective action 

program. The applicant further stated that inputs to the evaluations consider all relevant 

information, including ASME Code requirements, the latest vendor calculations, and operating 

experience such as repairs, replacements, prior evaluations, and documented aging effects. In 

addition, the applicant stated that these evaluations are performed in accordance with 

applicable plant procedures for repairs, design changes, or calculations, as appropriate for the 

disposition.

In its review of the applicant’s response, the staff noted that the applicant’s summary of the 

problems encountered with its RPV closure stud bolting was not complete in that it did not 

include information on stud Nos. 15 and 35, whose inspection reports the staff reviewed during 

its audit and indicated that the studs for these locations were replacement studs. The staff 
AGING MANAGEMENT REVIEW RESULTS

3-22

needed additional information to understand the nature of these replacements (i.e., whether 

they were replaced because of damage). 

Furthermore, based on the assessment in the applicant’s response, there was no consideration 

of the cumulative impact of the degraded closure stud bolting over the years on the entire RPV 

flange assembly. Because of the cumulative number of damaged stud holes and their locations 

throughout the RPV flange, the staff is concerned that assessments to justify adequate thread 

engagement for individual stud holes may not consider the overall impact of other degraded 

studs within the vicinity of one another. Moreover, the staff is uncertain how future RPV closure 

stud bolting issues will be assessed during the period of extended operation in this respect 

(e.g., if additional stud locations became damaged over time). The staff’s concern is based on 

the fact that currently at least 10 closure stud bolting locations have some degradation in the 

form of missing threads. In addition, stud No. 18 has been stuck in a partially engaged position 

since fall 1996.

By letter dated October 24, 2012, the staff issued RAI B2.1.3-2a, requesting that the applicant 

supplement RAI B2.1.3-2 to provide information on all RPV closure stud bolting corrective 

actions, repair, and replacement activities performed to date, which were not included in its 

response letter dated August 21, 2012. In addition, the staff also requested that the applicant 

provide a condition assessment and evaluations that justify the adequacy of the entire RPV 

flange assembly, which accounts for all of the locations with known closure stud bolting 

degradation.

In its response dated November 20, 2012, the applicant stated that review of plant records 

confirmed that reactor vessel stud No. 15 was replaced in June of 1984, and stud No 35 was 

replaced in the spring of 1989. The applicant also stated that these studs were replaced 

because of thread damage. The applicant further stated that no other repair or replacement 

activities were discovered in the review of plant records.

In addition, the applicant provided a brief summary of two engineering evaluations which were 

performed on its reactor vessel head closure studs in 1987 and 1989. The applicant stated that 

the two evaluations which were performed in 1987 and 1989 related to the problems the 

applicant has experienced with the reactor vessel studs and flange threads. The applicant also 

stated that both of the evaluations addressed minimum thread engagement, and based on 

those evaluations, the value of 6.31 in. has been used by the applicant to determine 

acceptability of the reactor vessel stud thread engagement. The applicant further stated that the 

1989 evaluation provided criteria for taking partial credit for damaged threads; however, all 

damaged threads were removed from the stud holes in 1989 and 1992, and all studs with 

damaged threads were replaced.

The applicant stated that the first evaluation was performed in 1987, when in RFO 2, five reactor 

vessel studs became stuck. The applicant also stated that the evaluation provided justification 

for operation in the subsequent cycle with one stud untensioned and the other four studs with 

partial engagement. The applicant further stated that the evaluation provided three 

recommendations in addition to the conclusion that the plant could operate with stud No. 2 

untensioned. The applicant stated that all three recommendations were satisfied.

In addition, the applicant stated that the purpose of the 1989 report was to develop criteria to 

accept or reject reactor vessel thread degradation on a generic basis. The applicant also stated 

that the report also provided five recommendations. The applicant stated that it has met all five 

recommendations. 
AGING MANAGEMENT REVIEW RESULTS

3-23

During its review, the staff noted that both evaluations (1987 and 1989) assumed that, with the 

exception of the five stud hole locations (2, 4, 5, 7, and 9), all the other remaining studs and 

stud hole threads had no degradation. Furthermore, the 1989 report also anticipated that a 

laser inspection technique would be used to accurately evaluate thread damage at the facility, 

noting that the laser inspection technique would yield high quality profiles of damaged threads; 

the report further stated that care should be exercised in the evaluation of areas with uniform 

wear, because they may appear intact but may in fact be out of tolerance. It is not clear to the 

staff whether the applicant has employed this specific technique in evaluating thread damage.

In contrast to the conditions assumed in the 1987 and 1989 evaluations, additional stud hole 

locations have known thread damage (i.e., 13, 25, 39, 53, and 54). Furthermore, stud No. 18 

has been stuck since 1996, with partial thread engagement. The staff also noted that the 

affected locations are mostly on one side of the reactor vessel flange periphery.

In addition, during review of the applicant’s reply, the staff noted that recommendation 2 (from 

the 1989 report), stated, in part, that studs used in vessel flange holes with degraded threads 

should be free from damage. Since the applicant stated that a burr was removed from

threads 10 and 11 on the No. 18 stud, it is not clear to the staff that recommendation 2 from the 

1989 report will be met for this location. Furthermore, recommendation 4 (also from the 1989 

report) stated, in part, that if damage approaches the limiting values, or if the vessel is operated 

with a missing stud, vessel hydrotests should be avoided, and the plant heatup rate limited to 

50 °F/hr in order to minimize the risk of localized plastic deformation of the threads. It is not 

clear to the staff that this aspect of recommendation 4 is met.

By letter dated March 26, 2013, the staff issued RAI B2.1.3-2b, requesting that the applicant 

clarify if the thread inspections for the vessel flange hole and stud threads include a laser 

inspection method referenced in the 1989 report, which can accurately gauge thread 

degradation so that there is assurance that any damage which is present does not exceed the 

acceptance criteria prior to the next inspection. In addition, the evaluations performed in 1987 

and 1989 assumed that, with the exception of location nos. 2, 4, 5, 7, and 9, there were no other 

locations with damaged threads. Since additional damage has occurred, the applicant was also 

requested to provide justification that the evaluations and the acceptance criteria provided by 

these reports will be valid during the period of extended operation and that the overall adequacy 

of the entire RPV flange assembly will be adequately managed during the period of extended 

operation. 

In its response dated April 26, 2013, the applicant stated that during the 1989 and 1992 repairs, 

a tool specially designed for inspection of RPV stud holes was used which produced a 

high-quality video of the stud hole threads by using a laser to illuminate and map the profile of 

the threads. The applicant stated that the laser inspection tool was used before and after the 

repairs. The applicant also stated that, since 1992, due to improved RPV head stud handling 

procedures, only one minor indication was found on RPV stud hole No. 20 threads. The 

applicant further stated that the laser inspection device has not been used since 1992.

In addition the applicant stated that the 1989 evaluation was intended to apply to the remainder 

of the “RPV design life” and does not include a discussion on the pattern of the degraded RPV 

head at that time, rather the thread damage existing at that time was used only to support the 

discussions estimating the effective thread engagement in hole locations 2, 4, 5, 7, and 9. The 

applicant also stated that thread damage to RPV stud hole Nos. 13, 25, 39, 53, and 54,

subsequent to the 1989 evaluations, do not invalidate past evaluations as long as the minimum 

thread engagement criteria are met. The applicant further stated that the thread degradation 
AGING MANAGEMENT REVIEW RESULTS

3-24

evaluation criteria developed in the 1989 report was analyzed such that each RPV stud 

engagement region fully meets applicable ASME Code rules, provided that the thread 

degradation evaluation criteria are met for each vessel stud hole. The applicant stated that 

using this evaluation, the RPV flange as a whole would fully meet ASME Code rules even if the 

effective thread engagement of all 54 RPV head stud locations were at a minimum. The 

applicant stated that there is no interaction mechanism between adjacent RPV stud hole 

locations, provided that each one meets the acceptance criteria established in the 1989 

evaluation.

The applicant also stated that Recommendation 2 from the 1989 evaluation, which stated that 

“studs used in vessel flange holes with degraded threads should be free from damage,” was 

based on the assumption that the vessel threads would engage with RPV head stud threads 

that were each fully intact. The applicant stated that use of RPV head stud No. 18 after 

removing a small burr was not in conflict with the recommendation that “studs used in vessel 

flange holes with degraded threads should be free of damage.” The applicant further stated that 

the recommendations of the 1989 evaluations are considered to be optional since the language 

used was “should” rather than “must” or “shall.”

The applicant stated that the 1987 evaluation calculated a 6.31-in. minimum vessel/stud thread 

engagement length based on a conservative calculation methodology. However, a 2013 

evaluation demonstrates that the minimum vessel/stud engagement required to resist all 

primary loads is 4.77 in. The applicant also stated that the stuck RPV head stud No. 18 has in 

excess of 35 percent more thread engagement than is required to meet ASME Code limits. The 

applicant further stated that this margin is sufficiently large that the comments related to 

localized plastic deformation do not apply to stuck stud No. 18.

During its review, the staff noted that the evaluations (1987 and 1989), essentially used similar 

language such as “should” rather than “must” or “shall.” This is because at the time these 

evaluations were performed the applicant had other options, such as the option to repair the 

RPV stud hole locations with stud hole inserts. However, in pursuing the continued use of the 

1987 and 1989 evaluations to justify the use of the RPV closure bolting in its current condition 

(i.e., with multiple locations with less than full thread engagement), the use of the 

recommendations should not be considered as “optional” by the applicant. In addition, since 

these evaluations are only valid if the acceptance criteria are still being met, the staff still seeks 

assurance that, for location Nos. 2, 4, 5, 7, 9, 13, 18, 25, 39, 53, and 54, the minimum thread 

engagement criteria will continue to be met during the term of the renewed license, with 

sufficient margin such that there is an extremely low probability of abnormal leakage, rapidly 

propagating failure, and gross rupture. The staff also noted that the applicant in its response 

stated that the 1989 evaluation was intended to apply to the remainder of the RPV design life. 

The staff reviewed the license renewal application (LRA) and did not note that the 1989 

evaluation was identified as time-limited aging analysis (TLAA), the applicant’s response did not 

provide additional information for the staff to determine whether this evaluation should have 

been identified as a TLAA in the LRA.

By letter dated August 2, 2013,the staff issued RAI B2.1.3-2c, requesting the applicant explain:

(1) What is meant by the term “remainder of the RPV design life,” as discussed above. 

In addition, clarify whether the 1987 and 1989 evaluations should be identified as TLAAs

in accordance with 10 CFR 54.3. If the evaluations are identified as TLAAs, revise the 

LRA accordingly and provide TLAA disposition in accordance with 10 CFR 54.21(c)(1). 

If not, provide the justifications why these evaluations are not considered as TLAAs.
AGING MANAGEMENT REVIEW RESULTS

3-25

2) How the current AMP will monitor the condition of the threads such that there is 

adequate assurance that the acceptance criteria will continue to be met at repaired RPV 

stud hole location Nos. 2, 4, 5, 7, 9, 13, 18, 25, 39, 53, and 54 during the period of 

extended operation.

In its response dated August 29, 2013, the applicant responded to Part (1) of RAI B2.1.3-2c and 

stated that the 1987 evaluation addressed questions relating to plant operation with RPV stud 

No. 2 not tensioned and unknown thread conditions in RPV stud holes 4, 5, 7, and 9. The 

applicant also stated that the 1987 evaluation discussed a number of different issues that were 

germane to the circumstances of the fall 1987 refueling outage, and this report was specific to 

the pattern of stuck studs and the known thread degradation that existed at that time. The 

applicant further stated that the calculation in 1987 provided the basis for the applicant to 

operate during Cycle 3 and was communicated to NRC by letter ULNRC-1663 dated 

October 29, 1987. 

The applicant stated that the stud and flange conditions described in the 1987 evaluation have 

been repaired and therefore are no longer representative of the current stud and flange 

conditions. The applicant also stated that, since the 1987 evaluation does not provide the basis 

for the current conclusion related to the capability of the reactor vessel studs, stud holes, or 

flange to perform their intended functions, the evaluation is not a TLAA in accordance with 

10 CFR 54.3(a), criterion 5.

The applicant also stated that the 1989 evaluation provided acceptance criteria for thread 

degradation and the starting point of the evaluation was related to the reactor vessel flange 

condition as it was known in 1989. In addition, the applicant stated that the evaluation itself did 

not contain any time-limited assumptions. The applicant further stated that its response to 

RAI B2.1.3-2b inadvertently introduced the statement that the 1989 evaluation was “intended to 

apply to the remainder of the RPV design life.” The applicant stated that the phrase was meant 

to convey that the 1989 evaluation was forward-looking rather than a snapshot in time and could 

be used to evaluate similar future conditions should the need arise. The applicant also stated 

that since the analyses contained in the 1989 evaluation are not time-dependent, this analysis is 

not a TLAA in accordance with 10 CFR 54.3(a), criterion 3.

The staff finds the applicant’s response acceptable because the applicant clarified that it 

inappropriately introduced the statement “intended to apply to the remainder of the RPV design 

life,” in its response to staff’s RAI. In addition, the applicant reiterated that the 1989 evaluations 

which provided its acceptance criteria for the RPV threads did not contain any time-limited 

assumption and the analysis is not time dependent. The staff’s concerns described in 

RAI B2.1.3-2c, Part (1), are resolved.

In its response to Part (2) of RAI B2.1.3-2c, the applicant stated that its RPV closure stud and 

stud holes experienced problems early in plant life (1986-1992), and multiple RPV stud holes 

required ASME Section XI repairs to remove damaged threads. The applicant also stated that,

to supplement the monitoring that is accomplished through regular volumetric inspections and to 

confirm that additional thread degradation has not occurred in the RPV stud holes, it commits to 

perform a one-time inspection of select RPV stud holes (Nos. 2, 4, 5, 7, 9, and 53) using a 

method consistent with the laser inspection that was applied following stud hole repair in 1989 

and 1992. The applicant also stated that if inspection of these RPV stud holes confirms that 

there was minimal or no additional degradation since the prior inspections, then it is reasonable 

to conclude that there will be minimal additional degradation in the period of extended operation. 

The applicant further stated that, if additional degradation is observed, the condition will be 
AGING MANAGEMENT REVIEW RESULTS

3-26

entered in the Corrective Action Program for evaluation and corrective action, and the remaining 

RPV stud hole locations will be inspected (Nos. 13, 25, 39, and 54). The applicant stated that 

the inspections will be completed no later than 6 months prior to the period of extended 

operation or the refueling outage prior to the period of extended operation, whichever occurs 

later. As part of its response, the applicant amended LRA Table A4-1 and added Commitment 

No. 42, which states:

It is noted that Callaway experienced problems with the reactor vessel head closure 

studs and stud holes early in plant life (1986-1992) and that multiple RPV stud holes 

required ASME Section XI repairs to remove damaged threads. To supplement the 

monitoring that is accomplished through regular volumetric inspections and to confirm 

that additional thread degradation is not occurring in the RPV stud holes, Callaway 

commits to perform a one-time inspection of select RPV stud holes using a method 

consistent with the Babcock and Wilcox laser inspection that was applied following stud 

hole repair in 1989 and 1992. RPV stud hole locations 2, 4, 5, 7, 9, and 53 have had 

more than one thread removed and will be inspected. If inspection of these RPV stud 

holes confirms that there was minimal or no additional degradation since the prior video 

inspection, then it is a reasonable conclusion that there will be minimal additional 

degradation in the period of extended operation. If additional degradation is observed in 

any of the repaired stud holes where more than one thread has been removed, the 

condition will be entered in the Corrective Action Program for evaluation and corrective 

action, and the remaining repaired RPV stud hole locations 13, 25, 39, and 54 will be 

inspected. The inspection is expected to confirm that further degradation is not 

occurring in the repaired stud holes, and will provide a basis for the conclusion that 

acceptance criteria for thread engagement will continue to be met through the period of 

extended operation.

In order to ensure that the condition of the threads for the RPV stud holes can be monitored, so 

that there is adequate assurance that the stud holes with less than the number of designed 

threads can continue to perform their intended function through the period of extended 

operation, the staff will issue a license condition to the applicant. The license condition will 

require the applicant perform laser inspection for the threads of stud hole location Nos. 2, 4, 5, 

7, 9, and 53. If inspection of these RPV stud holes confirms that there is additional degradation 

observed in any of these stud holes, the condition will be entered in the Corrective Action 

Program for evaluation and corrective action. In addition, the remaining repaired RPV stud hole 

locations Nos. 13, 25, 39, and 54 will be inspected. Therefore, the staff’s concerns described in 

RAIs B2.1.3-2, B2.1.3-2a, B2.1.3-2b, and B2.1.3-2c are resolved.

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

RAIs B2.1.3-2, B2.1.3-2a, B2.1.3-2b, and B2.1.3-2c, and review of the applicant’s commitments, 

the staff finds that the applicant has appropriately evaluated plant-specific and industry 

operating experience. In addition, the staff finds that, when implemented, the applicant’s 

program can adequately manage the effects of aging on SSCs within the scope of the program. 

FSAR Supplement. LRA Section A1.3, as amended by letter dated August 29, 2013, provides 

the FSAR supplement for the Reactor Head Closure Stud Program. The staff reviewed the 

FSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed to completing Commitment Nos. 41 and 42 no later than 6 months prior to the period 

of extended operation or the refueling outage prior to the period of extended operation, 
AGING MANAGEMENT REVIEW RESULTS

3-27

whichever occurs later. As stated earlier in this section, the staff will issue license conditions to 

ensure that these commitments are completed prior to entering the period of extended 

operation.

The staff finds that the information in the FSAR supplement, as amended by letter dated 

August 29, 2013, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Reactor Head Closure Stud 

Bolting Program, the staff concludes that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. Also, the staff reviewed the 

applicant’s Commitment Nos. 41 and 42 and confirmed that their implementation through 

license conditions prior to the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced 

Corrosion in Reactor Coolant Pressure Boundary Components 

Summary of Technical Information in the Application. LRA Section B2.1.5 describes the 

existing Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced 

Corrosion in Reactor Coolant Pressure Boundary Components Program as consistent with 

GALL Report AMP XI.M11B, “Cracking of Nickel-Alloy Components and Loss of Material Due to 

Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components.” The LRA 

states that the Cracking of Nickel-Alloy Components and Loss of Material Due to Boric 

Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components Program manages 

cracking of nickel-alloy components and associated welds as well as loss of material caused by 

boric acid-induced corrosion in susceptible components in the vicinity of nickel-alloy reactor 

coolant pressure boundary (RCPB) components. The LRA also states that detection of aging is 

accomplished through examinations consistent with ASME Code Section XI Subsection IWB 

Code Case N-722-1, subject to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E), ASME Code 

Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D), and ASME 

Code Case N-770-1, subject to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(F). The LRA 

further states that this program provides for bare-metal visual, surface, and volumetric 

examinations of nickel-alloy components, and for pressure boundary leakage and signs of boric 

acid leakage on adjacent ferritic steel components. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M11B. For the “parameters 

monitored or inspected” and “detection of aging effects” program elements, the staff determined 

the need for additional information, which resulted in the issuance of RAIs as discussed below.

The “parameters monitored or inspected” program element described in the applicant’s program 

evaluation report indicates that cracking and leakage of the RCPB are monitored by the 

applicant’s ISI program as augmented by ASME Code Cases N-722-1, N-729-1, and N-770-1, 

subject to the conditions specified in 10 CFR 50.55a. The applicant’s third interval ISI plan also 

indicates that the applicant’s program uses ASME Code Cases N-722-1, N-729-1, and N770-1 

in accordance with 10 CFR 50.55a. In comparison, GALL Report AMP XI.M11B recommends 
AGING MANAGEMENT REVIEW RESULTS

3-28

that RCPB cracking and leakage should be monitored by the applicant’s ISI program in 

accordance with 10 CFR 50.55a.

ASME Code Case N-770-1, in part, specifies visual examinations to detect reactor coolant 

leakage and boric acid corrosion associated with ASME Code Class 1 pressure retaining 

dissimilar metal piping and vessel nozzle welds. During the audit, the staff noted that the 

third-interval examination schedule for the applicant’s lSI program plan and the procedure for 

boric acid walkdown do not clearly indicate the implementation of visual examinations specified 

in ASME Code Case N-770-1.

By letter dated July 18, 2012, the staff issued RAI B2.1.5-1 requesting that the applicant clarify 

why the applicant’s examination schedule for ISI and implementing procedure for a boric acid 

walkdown do not clearly indicate the implementation of the visual examinations that are 

specified in ASME Code Case N-770-1. The staff also requested that as part of the response, 

the applicant confirm whether the implementing procedures or examination schedules of the ISI 

adequately implement visual examination, as specified in Inspection Items A-1 and A-2 of 

ASME Code Case N-770-1 (i.e., unmitigated butt welds at hot-leg operating temperatures to be 

examined by visual examinations during each RFO).

In its response dated August 21, 2012, the applicant indicated that the implementation 

procedure for aging management of Alloy 600 components provides guidance for ASME Code 

Case N-770-1 examination requirements for the different ASME Code Class 1 Alloy 82/182 

dissimilar metal butt welds. The applicant also stated that the following procedures are being 

enhanced to reference implementation and scheduling of ASME Code Case N-770-1 as 

applicable for implementation and scheduling of visual examinations: (1) QCP-ZZ-05048, “Boric 

Acid Walkdown for RCS Pressure Boundary,” (2) QCP-ZZ-05041, “Visual Examination to 

ASME VT-2,” and (3) Third Interval ISI Program Plan Appendix D.

The staff finds the applicant’s response acceptable because the applicant initiated the revisions 

to the procedures as applicable for implementation and scheduling of visual examinations in 

accordance with ASME Code Case N-770-1, consistent with its program basis document and 

GALL Report AMP XI.M11B. The staff’s concern described in RAI B2.1.5-1 is resolved.

The “detection of aging effects” program element described in the applicant’s program 

evaluation report indicates that the program includes examinations in accordance with the 

requirements of ASME Code Section XI, as augmented by ASME Code Cases N-722-1, 

N-729-1, and N-770-1, subject to the conditions specified in 10 CFR 50.55a. The staff also 

noted that applicant’s operating experience indicates that refueling cavity seal leakage caused a 

potential to interfere with the visual examinations of dissimilar metal welds on the reactor vessel 

loop nozzles and bottom-mounted instrument (BMI) penetrations.

Therefore, the staff needed to confirm whether the applicant’s operating experience indicates 

any other previous or current leakage that may interfere with the visual examinations of the 

reactor vessel nozzles specified in ASME Code Case N-770-1 and the other RCPB components 

specified in ASME Code Case N-722-1. In addition, the applicant’s implementing procedure for 

boric acid walkdown for the RCS does not clearly address how the applicant’s procedure would 

resolve the situation when leakage from other locations interferes with the visual examinations 

of the reactor vessel nozzle welds and other RCPB components specified in ASME Code 

Cases N-770-1 and N-722-1. 

By letter dated July 18, 2012, the staff issued RAI B2.1.5-2 requesting that the applicant 

describe the corrective action that was taken to prevent the refueling cavity seal leakage and to 
AGING MANAGEMENT REVIEW RESULTS

3-29

correct the conditions (e.g., corrosion product buildup) that would potentially interfere with the 

visual examination of dissimilar metal welds on the reactor vessel loop nozzles and BMI 

penetrations. The staff also requested that if applicable, the applicant describe any other 

previous or current leakage that may interfere with the visual examinations of the dissimilar 

metal welds on the reactor vessel nozzles, the BMI penetrations, or the other components 

included in the scope of the program. The staff further requested that the applicant describe 

how the applicant’s implementing procedures would resolve the situation when leakage from the 

other locations interferes with the visual examination of the RCPB components specified in 

ASME Code Cases N-770-1 and N-722-1.

In its response dated August 21, 2012, the applicant stated that its “[CAP] is used to address 

reactor cavity seal ring leakage that could potentially interfere with the visual examination of 

dissimilar metal welds on the reactor vessel loop nozzles and [BMI] penetrations.” The 

applicant also provided a summary of its corrective actions taken over the past 10 years to 

prevent refueling cavity seal leakage and potential interference of the leakage with the 

applicant’s visual examinations. The corrective actions include maintenance and replacement 

activities for the refueling cavity seals, cleaning of reactor vessel nozzles, and confirmation that 

inspection areas are free of boron residues with no interference with visual examinations. The 

applicant further stated that after the final draining of the refueling cavity during a RFO, it 

ensures that any residue due to cavity seal leakage, which might interfere with the examination 

of the RV nozzles, RV bottom head, or BMI penetrations that will be inspected during the next 

refueling outage, is removed, 

In its response, the applicant stated that no leakage other than the previously discussed cavity 

seal leakage has occurred that may affect the inspections of the applicant’s program. The 

applicant also stated that the dissimilar metal welds on the reactor vessel are examined and 

cleaned as necessary at the end of each RFO to remove any residue from refueling operations, 

which could interfere with the examination for leakage at the beginning of the next refueling 

outage. The applicant further stated that visual examination on specific Inconel 

(Alloy 600/82/182 and 690/52/152) components is conducted on the bare surface of the area of 

interest in accordance with the applicant’s implementing work documents. In addition, the 

applicant indicated that the invoking work document specifies that debris or other restrictions to 

the examinations are to be removed or resolved for adequate inspection of the components.

In its response, the applicant clarified that its procedures for boric acid walkdown for the RCS 

pressure boundary require that if boric acid residues are detected on or in the vicinity of 

components, a corrective action document is generated to evaluate leakage. The applicant also 

indicated that if boric acid deposits are discovered on the surface of the reactor vessel head or 

related insulation, regardless of the source or manner found, an examination is performed of the 

affected area(s) to verify the integrity of the reactor vessel head and penetrations before 

returning the plant to operation.

The staff finds the applicant’s response acceptable because: (1) the applicant confirmed that it 

has taken corrective actions in response to the previous concerns related to potential 

interference with the visual examinations of its program; (2) the applicant uses its CAP to 

ensure that reactor cavity seal ring leakage events or other leakage events do not potentially 

interfere with the visual examinations of the reactor vessel loop nozzles and BMI penetrations; 

(3) the applicant confirmed that after the draining of the refueling cavity, it ensures that any 

residue due to cavity seal leakage is removed; and (4) the applicant’s implementing procedures 
AGING MANAGEMENT REVIEW RESULTS

3-30

(work documents) for visual examinations ensure that debris or other restrictions to the 

examination are to be removed or resolved. The staff’s concern described in RAI B2.1.5-2 is 

resolved.

Based on its audit of the applicant’s Cracking of Nickel-Alloy Components and Loss of Material 

Due to Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components 

Program and review of the applicant’s responses to RAIs B2.1.5-1 and B2.1.5-2, the staff finds 

that program elements one through six for which the applicant claimed consistency with the 

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

AMP XI.M11B.

Operating Experience. LRA Section B2.1.5 summarizes operating experience related to the 

Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced Corrosion 

in Reactor Coolant Pressure Boundary Components Program. The LRA states that during 

RFO 15 (spring 2007), the reactor vessel head penetrations were examined using volumetric 

and surface techniques, and no evidence of cracking or leak path was identified with the 

volumetric and surface examinations. The LRA also states that no evidence of leakage from the 

penetration nozzles or indications of wastage was identified during bare metal visual 

examinations. In addition, the LRA states that during RFO 15, the applicant’s RPV hot-leg and 

cold-leg nozzles were volumetrically examined, and no evidence of cracking or leak path was 

identified in the nozzle to pipe dissimilar metal welds. 

As discussed above, the applicant’s program includes volumetric and visual examinations of 

Class 1 pressure retaining dissimilar metal piping and vessel nozzle welds that are specified in 

ASME Code Case N-770-1. Inspection Items of ASME Code Case N-770-1, A-1 and A-2 

specify the examinations for unmitigated butt welds at hot-leg operating temperatures greater 

than 329 °C (625 °F) and equal or less than 329 °C (625 °F), respectively.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of RAIs as 

discussed below.

During the audit, the staff noted that the applicant’s operating experience indicates that the RCS 

has experienced reactor hot-leg temperature fluctuations associated with changes in adjacent 

hot-leg temperatures. This phenomenon has been referred to by the term “upper plenum 

anomaly” (UPA) and apparently is caused by a flow switching phenomenon in the reactor vessel 

upper plenum.

The UPA may increase the local temperatures of the reactor hot-leg nozzles above 329 °C

(625 °F) because of nonsymmetrical flow mixing such that Inspection Item A-1, rather than A-2, 

should be applied to the inspections of the applicant’s reactor hot-leg nozzles. It was not clear 

to the staff how the applicant’s program evaluates the potential effects of the UPA on the reactor 

hot-leg nozzle temperatures and the determination of the inspection items.

By letter dated July 18, 2012, the staff issued RAI B2.1.5-3 requesting the applicant to provide 

the following information to confirm that its program uses relevant inspection items in 

accordance with ASME Code Case N-770-1: (1) inspection item assigned to unmitigated 
AGING MANAGEMENT REVIEW RESULTS

3-31

hot-leg nozzle butt welds (that is, Inspection Item A-1 or A-2), and (2) the temperatures of the 

hot-leg nozzles based on adequate consideration of the local temperature distributions and 

fluctuations at the hot-leg nozzles. The staff also requested that as part of the response the 

applicant describe how the temperatures of the hot-leg nozzles are determined (e.g., an 

engineering evaluation or actual measurements). In addition, the staff requested that if the 

applicant’s inspection item for the unmitigated hot-leg nozzle welds is A-2 and the maximum 

temperature of the hot-leg nozzles exceeds 329 °C (625 °F), the applicant should clarify why its 

program does not specify Inspection Item A-1 to the hot-leg nozzle welds exposed to 

temperatures exceeding 329 °C (625 °F). The staff further requested that the applicant describe 

the operating experience in terms of occurrence of primary water stress-corrosion cracking 

(PWSCC) in the hot-leg nozzles to confirm whether the UPA has an adverse effect on PWSCC 

of the hot-leg nozzles. 

In its response dated August 21, 2012, the applicant stated that its UPA manifests itself in pairs 

of loops; and in the loop 2 and loop 3 hot-legs, loop 2 has a higher temperature than loop 3. 

The applicant also stated that “[w]hen the UPA occurs, the temperature in loop 2 temporarily 

decreases, accompanied by a corresponding increase in loop 3 temperature, [and] after a few 

seconds, the temperatures return to normal.” The applicant further stated that “[w]hen the 

temperature in loop 3 increases, it does not increase above the temperature in loop 2 prior to

the onset of the UPA event.” The applicant further stated that “[l]oops 1 and 4 behave in a 

similar fashion, with the temperature in loop 1 normally higher than the temperature in loop 4. 

Thus, the UPA does not affect the maximum temperature of the reactor hot leg nozzles.”

In its response, the applicant also stated that “[e]ach hot-leg has three [resistance temperature 

detectors (RTDs)] installed 120 degrees apart [and] [c]omputer logs of all the RTDs were 

reviewed back to 2005, when the steam generators were replaced.” The applicant indicated 

that during that time period, except during calibration of an RTD, none of the RTDs indicated a 

temperature greater than 327 °C (620 °F). The applicant also stated that based on this review 

ASME Code Case N-770-1 Inspection Item A-2 is assigned. The applicant further stated that no 

cracks have been found in the RCS hot-leg nozzles.

In its review, the staff found the applicant’s response acceptable because: (1) the measured 

temperature data of the RTDs since 2005 confirm that the maximum temperature of the reactor 

hot-leg nozzles is less than the minimum threshold temperature 329 °C (625 °F) for Inspection 

Item A-1; (2) the applicant adequately assigned Inspection Item A-2 to the reactor vessel outlet 

nozzles based on the measured temperature data, consistent with ASME Code Case 770-1; 

and (3) the applicant confirmed that no cracks have been found in the RCS hot-leg nozzles, 

which indicates that the UPA did not cause an adverse effect on PWSCC of the hot-leg nozzles. 

The staff’s concern described in RAI B2.1.5-3 is resolved. 

LRA Section B2.1.5 addresses the operating experience regarding the reactor vessel lower 

head cladding by stating that an indication was visually detected in the reactor vessel lower 

head cladding in 2007, during the remote VT-3 examination of the vessel interior. The LRA also 

states that the indication was evaluated and additional volumetric and surface examinations 

were performed for better characterization. The LRA further states that the indication was 

determined to be acceptable as is.

During the audit, the staff noted that the applicant’s reactor vessel bottom head region has at 

least two indications of cladding degradation (detected in RFOs 13 and 15 respectively), as 

indicated in LRA Section 4.7.3. Therefore, the staff needed to clarify how many total indications 

of reactor vessel cladding degradation have been detected. In addition, the staff noted that the 
AGING MANAGEMENT REVIEW RESULTS

3-32

LRA does not clearly provide the following information: (a) the root cause analysis and 

corrective action for the cladding indications, (b) the previous inspection results to identify any 

change in the size and depth of the cladding indications, and (c) the inspection method and 

frequency to manage the degradation of the cladding and reactor vessel as well as the technical 

basis for the adequacy of the inspection method and frequency.

By letter dated July 18, 2012, the staff issued RAI B2.1.5-4 requesting the applicant to confirm 

how many total indications of reactor vessel cladding degradation have been detected. The 

staff also requested that the applicant describe the results of the root cause analysis for the 

cladding degradation (i.e., what caused the cladding degradation), and to confirm whether 

cladding degradation continues to progress. In addition, the staff requested that the applicant 

describe any corrective action taken to prevent additional cladding and vessel degradation and 

describe why the corrective action was adequate to manage degradation of cladding and 

reactor vessel.

Furthermore, the staff requested that the applicant provide the following information regarding 

the previous inspection results for each of the cladding indications: (a) clarification as to 

whether any of these cladding indications is associated with cracking, leakage, or other 

degradation of reactor vessel bottom head penetrations, (b) the results (size and depth data) of 

the previous inspections performed after the initial detections of cladding indications, including 

any change in the size and depth of the cladding indications in comparison with the initial size 

and depth that were detected for the first time, and (c) the comparison between the most recent 

depth data with the thickness of the non-degraded cladding and the thickness of the 

non-degraded reactor vessel steel (excluding the cladding), respectively.

The staff also requested that the applicant describe the inspection method and frequency of the 

subsequent inspections of the cladding indications as defined in the applicant’s program and 

describe the technical basis for why the inspection method and frequency are adequate to 

manage the degradation of cladding and reactor vessel.

In its response dated August 21, 2012, the applicant stated that the only indications are the two 

indications that were previously documented during RFO 13 (spring 2004) and RFO 15 

(spring 2007), and both indications were determined to be the result of damage during 

fabrication or construction. The applicant also indicated that a root cause analysis was 

performed for the indication identified during RFO 13, and the direct cause for the indication on 

the cladding is excessive grinding or buffing of the cladding. The applicant further indicated that 

as described in its corrective action documents, the exposure of the low alloy carbon steel base 

metal was caused by (1) grinding during repair activities, (2) grinding during the completion of 

the cladding application in the lower dome-to-torus weld, or (3) buffing or smoothing performed 

following onsite vessel installation. In addition, the applicant stated that the cause of the 

indication identified during RFO 15 is most likely grinding or similar activities during vessel 

construction. The applicant further stated that no corrective actions were taken to prevent 

additional occurrence of the cladding damage because the cladding indications were 

determined to be due to the fabrication or construction activities. 

The applicant also stated that stainless steel is highly resistant to erosion and other areas of the 

vessel seeing higher flow rates do not show similar indications. The applicant further stated that 

there is no metal-to-metal contact in this area of the vessel; therefore, rubbing is not the cause. 

Also, there are grinding or flapper wheel marks around the indication, which suggests that these 

indications are from fabrication. 
AGING MANAGEMENT REVIEW RESULTS

3-33

In its response regarding the previous inspection results, the applicant stated that neither 

indication is associated with cracking, leaking, or other degradation of reactor vessel bottom 

head penetrations. The applicant also stated that no further inspections have been done to the 

cladding indications as of RFO 18 in 2011. The applicant stated that the indications were 

planned to be inspected during RFO 18, but difficulties removing the lower internals prevented 

the inspections from taking place. 

In addition, the applicant indicated that based on the applicant’s drawings E-11173-171-004 and 

E-11173-171-005, the inside radius of the reactor vessel shell is 88.16 in. and the reactor vessel 

wall thickness is 5.38 in., including the cladding (0.22 in.). The applicant further stated that the 

degraded cladding area dimensions (length x height x depth) are 1.5 inch x 0.625 inch x 

0.28 inch and 0.53 inch x 0.3 inch x 0.10 inch, per UT reports from Wesdyne.

In its response regarding the applicant’s inspection schedule for the degraded cladding areas, 

the applicant stated that the indications are inspected opportunistically when the core barrel is 

pulled during an RFO, such as for ASME category B-N-3 examinations. The applicant also 

stated that the prior RF 13 and 15 evaluations of the indications determined that there is no 

growth expected and, based on these evaluations, the opportunistic inspections will be used to 

manage the degradation of the cladding and RPV. 

In its review, the staff found that the applicant’s response regarding the total number of the 

cladding indications and the root cause analysis is acceptable because the applicant clarified 

that only two indications of reactor vessel cladding degradation have been identified, and the

results of the applicant’s root cause analysis determined that the direct cause of the indications 

is excessive grinding or buffing of the cladding (i.e., not due to aging degradation). 

However, the staff identified a concern related to the applicant’s opportunistic inspections of the 

cladding indications. Specifically, the applicant’s opportunistic inspections do not specify the 

inspection frequency or inspection method. In addition, the staff needed justification for why the 

applicant’s inspections of the indications are not identified as a program enhancement. The 

staff also needed further clarification for why the size (1.5 inch x 0.625 inch) of the first 

indication discovered in 2004 was different from the size described in LRA Section 4.7.3 (1.5 

inch x 0.75 inch). The staff needed further clarification for why the conservative total depth for 

the indications is 0.28 inch rather than 0.36 inch, if the base metal reduction for the indication 

discovered in 2004 is assumed to be 0.14 inch beyond the reactor vessel cladding (0.22-inch 

nominal thickness). By letter dated October 12, 2012, the staff issued RAI 2.1.5-4a requesting 

the applicant to provide clarification on the issues above. The staff further requested that the 

applicant identify the inspection methods that will be used to manage loss of material of the 

degradation indications and justify why the opportunistic inspections without a specific 

inspection frequency are sufficient to manage the aging effect. In addition, the staff requested 

that the applicant justify why the applicant’s inspections of the degradation indications are not 

identified as a program enhancement. 

In its response dated November 8, 2012, the applicant stated that the previous reference to 

0.65 inch for the width of the first indication (discovered in 2004) was an error and corrective 

action was taken to clarify that the correct width value is 0.75 inch. The applicant also clarified 

that this corrective action did not affect the validity of the corrosion rate calculations. The 

applicant further stated that grinding during reactor vessel fabrication was the likely cause of the 

2004 indication, which reduced the cladding thickness to 0.14 inch at the edge of the indication. 

In addition, the applicant clarified that the actual measured depth of the first indication was a 

total of 0.14-inch and therefore, it is conservative to assume that the base metal depth is 
AGING MANAGEMENT REVIEW RESULTS

3-34

reduced by 0.14-inch in addition to the 0.14-inch cladding thickness, resulting in a conservative 

degradation depth of 0.28 inch. In its review, the staff found this portion of the applicant’s 

response acceptable based on the applicant’s clarifications regarding the correct width value 

(0.75 inch) of the indication and the actual total degradation depth (0.14 inch) in the vicinity of 

the indication, which is less than the applicant’s conservative value (0.28 inch). 

In its response, the applicant also clarified that the VT-3 examinations will be performed at least 

once every 10 years. The applicant further clarified that a program enhancement is not 

necessary since these visual examinations are consistent with the requirements of ASME Code 

Section XI, Table IWB-2500-1, Examination Category B-N-1 and the applicant’s ASME Section 

XI lnservice Inspection, Subsections IWB, IWC, and IWD Program. In its review regarding the 

inspection frequency and program enhancement, the staff found this portion of the response 

acceptable because the applicant clarified that the VT-3 visual examinations will be performed 

periodically to monitor the degradation indications and these examinations are consistent with 

the ASME Section XI lnservice Inspection, Subsections IWB, IWC, and IWD Program.

However, the staff noted the VT-3 examinations are not capable of monitoring the depths of the 

indications in the reactor vessel and the applicant’s response to RAI B2.1.5-4a does not clearly 

address how its examinations will monitor the depths and depth-related conditions of the 

indications for the period of extended operation. By letter dated January 30, 2013, the staff 

issued RAI 2.1.5-4b, requesting the applicant clarify how the applicant will monitor the depths 

and depth-related conditions of the indications. The staff also requested that such monitoring 

activities be clearly described in the summary description of the program in the FSAR 

supplement.

In its response dated February 14, 2013, the applicant stated that during the upcoming RFO 

(spring, 2013), an ultrasonic examination of each indication in the reactor vessel wall is planned 

and surface profile data will be collected in the area of the indication and the surrounding 

cladding. The applicant also stated the following:

[c]onsistent with the ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD [Program], future thickness measurements of the reactor vessel 

wall indications in the reactor vessel lower head will be determined by: (a) 

obtaining surface profile data of the indications and surrounding cladding using 

an ultrasonic examination from the inside of the reactor vessel, (b) using an 

ultrasonic examination from the outside of the reactor vessel, or (c) using remote 

mechanical gages inside the reactor vessel. 

In addition, the applicant revised LRA Appendix A1.1 (FSAR supplement for the ASME Section 

XI Inservice Inspection, Subsections IWB, IWC, and IWD Program) and LRA Section B2.1.1, 

consistent with its response. 

Based on its review, the staff finds the applicant’s response acceptable because the applicant 

clarified that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program will perform depth measurements of the indications using an examination method that 

is capable of measuring the depths, consistent with ASME Code Section XI, and the applicant 

appropriately revised the FSAR supplement to summarize the depth measurement activities. 

Therefore, the staff’s concerns described in RAIs B2.1.5-4, B2.1.5-4a and B2.1.5-4b are 

resolved.

Based on its audit and review of the application, and review of the applicant responses to 

RAIs B2.1.5-3, B2.1.5-4, B2.1.5-4a, and B2.1.5-4b, the staff finds that the applicant has 
AGING MANAGEMENT REVIEW RESULTS

3-35

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M11B was evaluated.

FSAR Supplement. LRA Section A1.5 provides the FSAR supplement for the Cracking of 

Nickel-Alloy Components and Loss of Material Due to Boric Acid-induced Corrosion in Reactor 

Coolant Pressure Boundary Components Program. The staff reviewed this FSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP LR Table 3.0 1. The staff finds that the information in the FSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Cracking of Nickel-Alloy 

Components and Loss of Material Due to Boric Acid-Induced Corrosion in Reactor Coolant 

Pressure Boundary Components Program, the staff concludes that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff reviewed the FSAR 

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 PWR Vessel Internals 

Summary of Technical Information in the Application. LRA Section B2.1.6 describes the new 

PWR Vessel Internals Program as consistent with GALL Report AMP XI.M16A, “PWR Vessel 

Internals.” The LRA states that the PWR Vessel Internals Program manages aging in those 

Callaway reactor vessel internal (RVI) components that provide core structural support for the 

reactor. 

The LRA states that the PWR Vessel Internals Program manages the following aging effects: 

(a) cracking induced by either SCC, PWSCC, irradiation-assisted SCC, fatigue or cyclical 

loading; (b) loss of material induced by wear; (c) loss of fracture toughness induced by either 

neutron irradiation embrittlement or thermal aging embrittlement; (d) changes in component 

dimensions induced by void swelling or distortion; and (e) loss of preload induced by thermal 

and irradiation-enhanced stress relaxation and creep. LRA Section 3.1.2, “Results,” and LRA 

Table 3.1.2-1, “Reactor Vessel, Internals, and Reactor Coolant System – Summary of Aging 

Management Evaluation – Reactor Vessel and Internals,” provide additional information in 

support of the PWR Vessel Internals Program. 

LRA Table 3.1.2-1 identifies that RVI components are exposed to an external reactor coolant 

environment; and that with the exception of the RVI clevis inserts and insert bolts and RVI radial 

support keys, the RVI components are made from stainless steel materials. LRA Table 3.1.2-1 

identifies that the RVI clevis inserts and insert bolts and RVI radial support keys are made from 

nickel alloy materials.

The LRA states that the PWR Vessel Internals Program implements the guidance of EPRI 

report No. 1016596, “Materials Reliability Program: Pressurized Water Reactor Internals 

Inspection and Evaluation Guideline (MRP-227, Revision 0),” and EPRI report No. 1016609, 

“Inspection Standard for PWR Internals (MRP-228, Revision 0).” The LRA also states that the 

PWR Vessel Internals Program has addressed those plant-specific action items, conditions, and 

limitations that were identified in the NRC’s safety evaluation for the MRP-227 report. The LRA 
AGING MANAGEMENT REVIEW RESULTS

3-36

further states that the PWR Vessel Internals Program inspects the following categories of RVI 

components:

• inspections of the “primary category” components in accordance with the components 

and inspection criteria specified in Table 4-3 of the MRP-227 report

• inspections of “expansion category” components in accordance with the components 

and inspection criteria specified in Table 4-6 of the MRP-227 report

• inspections of RVI components falling into the “existing program” category in accordance 

with existing programmatic requirement or recommended criteria, such as ASME Code 

Section XI, Examination Category B-N-3 requirements for core support structure 

components or LRA AMP B2.1.22, “Flux Thimble Tube Inspection,” for inspections of the

bottom-mounted instrumentation flux thimble tubes

The LRA states that the PWR Vessel Internals Program inspects these components using either 

visual VT-3 or enhanced visual EVT-1 inspection methods or ultrasonic volumetric inspection 

methods. The LRA also states that the remaining RVI components fall into a fourth “No 

Additional Measures” category and that the components in this category are not subject to the 

EPRI MRP’s augmented inspection recommendations in MRP-227-A. The LRA further states 

that the reactor vessel integral attachments are inspected in accordance with LRA AMP B2.1.1, 

“ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M16A. In addition, the staff 

observed that the PWR Vessel Internals Program is based on the approved version of the 

MRP-227 report (i.e., EPRI MRP Technical Report No. MRP-227-A [TR MRP-227-A], which was 

formally issued on January 9, 2012, and may be accessed in Agencywide Documents Access 

and Management System [ADAMS] Accession Nos. Ml12017A191, ML12017A193,

ML12017A194, ML12017A196, and ML12017A197).1

 The NRC endorsed the methodology in 

TR MRP-227-A in the NRC’s revised safety evaluation (SE, Revision 1) on the methodology 

dated December 16, 2011 (ML11308A770).

The staff also noted that in MRP-227-A, the EPRI MRP had indicated that the program would be 

implemented in accordance with the “confirmation process” and “administrative controls” 

program elements specified in the MRP-227-A report and that these controls would be 

implemented in accordance with the applicant’s process for implementing the methodology in 

Nuclear Energy Institute (NEI) Technical Report (TR) No. NEI 03-08, Revision 2, “Guideline for 

Management of Materials Issues,” dated January 2010. The staff also noted that the 

MRP-227-A report indicated that the applicant’s implementation of the “corrective actions” 

program element and disposition of relevant plant-specific or applicable generic operating 

experience would be implemented in accordance with Section 7 of the MRP-227-A report and 

the applicant’s NEI 03-08 process. Therefore, the staff also included a review of the “corrective 

actions,” “confirmation process,” and “administrative controls” program elements during its audit 

review of the applicant’s PWR Vessel Internals Program.

 

1 The MRP-227-A report includes the staff’s safety evaluation that was issued in approval of the report’s augmented 

inspection methodology for PWR RVI components.
AGING MANAGEMENT REVIEW RESULTS

3-37

The staff noted that Section 1 of the MRP-227-A report states that, for all RVI components that 

are defined in the PWR applicant’s CLB as core support structures components, the applicant 

must meet the ISI requirements of ASME Code Section XI, Examination Category B-N-3. 

The staff noted that the MRP-227-A report indicates that this applies to all RVI components that 

are classified as RVI core support structure components for the applicant’s CLB independent of 

whether the components have been classified and designated as “No Additional Measures” 

components in the MRP-227-A report methodology or were inadvertently omitted as being 

within the scope of the generic analysis for Westinghouse RVI designs in the MRP-227-A report. 

The staff also noted that the methodology in the MRP-227-A report cannot be used as the basis 

for establishing which RVI components are ASME Code Section XI, Examination 

Category B-N-3 components for the CLB. The staff’s review of the applicable AMR items for the 

RVI components in the Callaway design, as documented in SER Sections 3.1.2.1.2 and 

3.1.2.1.3, confirms that the applicant will be fulfilling its obligations for complying with these 

ASME Code Section XI inservice inspection (ISI) requirements.

For the “scope of program” program element, the staff determined the need for additional 

information, which resulted in the issuance of RAIs as discussed below. 

The staff noted that Table 4-3 of the MRP-227-A report identifies that the flexures in the thermal 

shield assembly are “Primary Category” RVI components for Westinghouse plants that will be 

implementing the MRP-227-A recommendations. During its audit, the staff noted that the basis 

document for the applicant’s PWR Vessel Internals Program stated that the RVI design does not 

include thermal shield flexures. Instead, the staff noted, the basis document stated that the RVI 

design includes neutron shield panels in lieu of thermal shield flexures. However, the staff 

noted that LRA Table 4.3-5, “Reactor Internals Design Basis Fatigue Analysis Results,” 

identifies that the applicant performed a fatigue analysis on the thermal shield flexures and 

calculated cumulative usage factor (CUF) value of 0.978 for the components. 

By letter dated July 18, 2012, the staff issued RAI B2.1.6-1, requesting that the applicant 

address this issue. In this RAI, the staff asked the applicant: (a) to justify why the PWR Vessel 

Internals Program would not implement inspections of the flexures consistent with the 

MRP-227-A recommendations, if the plant design includes thermal shield flexures; or (b) if the 

design does not include thermal shield flexures, to identify the RVI component or components 

that serve the same intended function as that for thermal shield flexure components in the 

generic Westinghouse design that was evaluated in the MRP-227-A report, and to justify why 

the alternative components would not need to be inspected in accordance with the 

recommendations in the MRP-227-A report, or as an augmentation of the applicant’s inspection 

protocols for the PWR Vessel Internals Program. 

The applicant responded to RAI B2.1.6-1 in a letter dated August 21, 2012 (ML12235A467 for 

the Cover Letter and ML12235A468 for the enclosures containing the RAI response and LRA 

amendments for LRA Amendment 7). In its response, the applicant stated that the thermal 

shield and thermal shield flexures described in MRP-227-A are not applicable to the Callaway 

design. The applicant stated that, instead, a neutron shield panel assembly is used to achieve 

the same neutron shielding function as do thermal shield flexures that are included in the 

designs of some other Westinghouse-designed PWRs. The applicant stated that a neutron 

shield panel assembly consists of four panels that are bolted and pinned to the outside of the 

core barrel. The applicant stated that the neutron shield panels are used to reduce the neutron 

fluence exposure to the reactor vessel welds and that the neutron shield panels and bolting are 

screened out as Category A in Table 7-2 of MRP-191, “Materials Reliability Program: 
AGING MANAGEMENT REVIEW RESULTS

3-38

Screening, Categorizing, and Ranking of Reactor Internals of Westinghouse and Combustion 

Engineering PWR Designs (MRP-191),” dated November 2006. The applicant further stated 

that, as defined in MRP-191, Section 2.0, the ASME Code Section XI, Category B-N-3 ISI visual 

inspections will be performed on these components, even though (as clarified in the response to 

RAI B2.1.6-3) the thermal shield panels are not strictly defined as ASME Section XI,

Examination Category B-N-3 components. The applicant also clarified that the CUF value 

provided in the LRA is that for the neutron shield panel bolts, and not for thermal shield flexures. 

The staff noted that, as part of its response to RAI B2.1.6-1, the applicant amended the LRA to 

reflect this change. The staff confirmed that the applicant appropriately amended LRA 

Table 4.3-5 to state that the CUF value was calculated for the neutron panel bolts, and not the 

thermal shield flexures. The staff also confirmed that, in the applicant’s letter of 

October 24, 2012 (ML12299A248 for the Cover Letter, ML12299A249 for Enclosure 1 

containing the RAI responses, and ML12299A250 for Enclosure 2 containing the associated 

LRA amendments for LRA Amendment 13), the applicant included the applicable AMR Item for 

managing cracking and loss of material due to wear in the thermal shield panels and credited 

the ASME Section XI, Subsection IWB, IWC, and IWD Program as the basis for managing the 

applicable aging effects for the components during the period of extended operation. The staff 

finds the applicant’s basis for managing cracking in the neutron shield panels acceptable 

because: (a) the applicant has used its CLB to define the appropriate aging management basis 

for managing cracking in the neutron shield panels and (b) the applicant will appropriately be 

using its ASME Section XI, Subsections IWB, IWC, and IWD Program to perform VT-3 

examinations of the neutron shield panels, even though this type of basis is not referenced in 

the MRP-227-A report for these components. The staff’s request in RAI B2.1.6-1 is resolved.

The staff noted that Table 4-9 in Technical Report No. MRP-227-A (TR MRP-227-A) identifies 

that the upper support rings or skirts in the upper internal assemblies of Westinghouse reactor 

designs are “Existing Program” RVI components and that the components will be inspected in 

accordance with the applicable ASME Section XI inservice inspection (ISI) requirements. 

During the audit, the staff noted that the program basis document for the applicant’s PWR 

Vessel Internals Program did not include proposed inspections of an upper support ring or skirt 

in upper internals assembly of the plant. It was not clear to the staff whether the RVI design at 

Callaway included an upper support ring or skirt.

By letter dated July 18, 2012, the staff issued RAI B2.1.6-2, requesting that the applicant 

address this issue. In this RAI, the staff asked the applicant to: (a) justify why the PWR Vessel 

Internals Program would not implement inspections of the component consistent with the 

MRP-227-A recommendations if the plant design does include an upper support ring or skirt, or 

(b) if the design does not include an upper support ring or skirt, to identify the RVI component 

that serves the same intended function as that for upper support ring or skirt components in the 

generic Westinghouse design that was evaluated in the MRP-227-A report, and to justify why 

the alternative component would not need to be inspected in accordance with the applicant’s 

PWR Vessel Internals Program. 

The applicant responded to RAI B2.1.6-2 in a letter dated August 21, 2012 (ML12235A467 for 

the Cover Letter and ML12235A468 for the enclosures containing the RAI response and LRA 

amendments for LRA Amendment 7). In its response, the applicant stated that the plant design 

does include an upper support skirt, which is a subcomponent of the upper support plate. The 

applicant stated that the LRA has been amended to include the upper support skirt as an 

“Existing Program” component consistent with the MRP-227-A recommendations. The staff 

confirmed that, in the letter of August 21, 2012, the applicant appropriately amended LRA 
AGING MANAGEMENT REVIEW RESULTS

3-39

Table 3.1.2-1 to include an AMR item on cracking of the RVI upper support skirt, and that the 

applicant is crediting the PWR Vessel Internals Program’s ASME Code Section XI “Existing 

Program” activities (along with the Water Chemistry Program) to manage cracking in the 

support skirt. The staff finds the applicant’s basis for managing cracking in the upper support 

skirt acceptable because the applicant’s basis is consistent with the recommendations of 

MRP-227-A for “Existing Program” components and the upper support skirt will be examined in 

accordance with the existing ASME Code Section XI ISI requirements. The staff’s request in 

RAI B2.1.6-2 is resolved.

The staff noted that Section 4.4.3 and Table 4-9 in TR MRP-227-A list those “Existing Program” 

components that are identified as ASME Code Section XI “Core Support Structure” 

components. The staff also noted that the MRP-227-A report states that these components are 

examined with the ISI requirements in ASME Code Section XI, Table IWB-2500-1, for 

removable core support structure components (i.e., Examination Category B-N-3 components). 

However, during the audit, the staff noted that the program basis documents for the applicant’s 

PWR Vessel Internals Program did not identify which RVI components are designated as ASME 

Code Section XI, Examination Category B-N-3 components for the Callaway CLB. In addition, 

the applicant did not explain: (a) whether the method of performing the VT-3 visual examination 

in accordance with this ASME Section XI examination category would actually achieve coverage 

of those RVI components that were designated as ASME Code Section XI, Examination 

Category B-N-3 components for the Callaway facility, and (b) whether there were any additional 

RVI components that were identified as ASME Code Section XI, Examination Category B-N-3 

components for the Callaway CLB, but that were not assumed in Table 4-9 of the generic 

MRP-227-A report. 

By letter dated July 18, 2012, the staff issued RAI B2.1.6-3, requesting that the applicant 

provide additional clarifications on the ASME Code Section XI, Examination Category B-N-3 

criteria that are used for the plant’s CLB. Specifically, the staff asked the applicant: (a) to 

identify all RVI component locations that are designated as ASME Code Section XI, 

Examination Category B-N-3 components; (b) to identify those additional component locations 

that were ASME Code Section XI, Examination Category B-N-3 components for the Callaway 

CLB but that were not assumed as ASME Code Section XI, Examination Category B-N-3 

components in Table 4-9 of the MRP-227-A report, and to identify those aging effects applicable 

to the additional ASME Section B-N-3 components for the facility; and (c) based on previous 

ASME Code Section XI examinations of B-N-3 component surfaces, to clarify and justify 

whether the implementation of VT-3 examinations of the B-N-3 components surfaces would 

actually achieve inspection coverage of those components that are designated as ASME Code 

Section XI B-N-3 components for the Callaway CLB. 

The applicant responded to RAI B2.1.6-3 in a letter dated August 21, 2012 (ML12235A467 for 

the Cover Letter and ML12235A468 for the enclosures containing the RAI response and LRA 

amendments for LRA Amendment 7). In its response, the applicant stated that all the RVI 

components listed in LRA Table 2.3.1-1, with the exception of the “RVI Neutron Shield Panel” 

and “RVI BMI Flux Thimbles,” are designated as ASME Code Section XI, Examination 

Category B-N-3 components and that these components are ASME Code Section XI “Existing 

Program” components for the AMP. The applicant also stated that it did not identify any aging 

effects that are not assumed in MRP-227-A, Table 4-9. The applicant stated that the VT-3 

examinations manage cracking and loss of material due to wear, which are aging effects 

assumed in Table 4-9 of MRP-227-A. The applicant further stated that as described in ASME 

Code Section XI Paragraph IWB-3520.2, its VT-3 examination method looks for evidence of loss 
AGING MANAGEMENT REVIEW RESULTS

3-40

of component integrity at bolted or welded connections, loose or missing parts, debris, 

corrosion, wear, or erosion in the components. 

The applicant stated that the VT-3 examination is capable of monitoring the aging effects 

addressed in MRP-227-A, Table 4-9, for “Existing Program” components. The staff finds this 

aging management basis, as supplemented in the applicant response to RAI B2.1.6-3, to be 

acceptable because the basis is consistent with (a) the applicant’s CLB for complying with 

10 CFR 50.55a requirements and (b) the basis in Section 1 of the MRP-227-A report that 

requires the applicant to examine all RVI components identified as ASME Code Section XI, 

Examination Category B-N-3 components. The staff also finds that the applicant may use either 

the PWR Vessel Internals Program or the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program to implement the applicable ASME Code Section XI 

ISI requirements for these components. The staff’s concern described in RAI B2.1.6-3 is 

resolved.

The staff noted that, by letter dated April 23, 2014 (ADAMS ML14114A113 for the Cover Letter 

and ML14114A110 for the enclosure containing the LRA amendment in LRA Amendment 34), 

the applicant identified that the design of the RVI components at Callaway does not include 

baffle-edge bolts in the plant’s core baffle assembly. The staff reviewed the plant design 

document and verified that the design of the plant’s core baffle assembly does not include 

baffle-edge bolts. As a result, the staff noted that these components are not within the scope of 

the applicant’s PWR Vessel Internals Program and that the “Primary Category” inspection 

recommendations for inspecting Westinghouse-designed baffle-edge bolts in TR MRP-227-A do 

not apply to the Callaway CLB. Based on this review, the staff reviewed the applicant’s claim 

and LRA amendment and finds it acceptable because the staff has confirmed that the RVI 

design does not include baffle-edge bolts.

Based on its audit of the PWR Vessel Internals Program and review of the applicant’s 

responses to RAIs B2.1.6-1, B2.1.6-2, and B2.1.6-3, the staff finds that program elements 1 

through 9 for which the applicant claimed consistency with the GALL Report are consistent with 

the corresponding program elements of GALL Report AMP XI.M16A, with the exceptions that 

have been noted, discussed, and accepted earlier in this evaluation. 

The staff’s review of the applicant’s bases for resolving applicable Applicant/Licensee Action 

Items on the methodology in TR MRP-227-A is given in the following subsection.

Review of License Renewal Applicant Action Items. In the staff’s revised Safety Evaluation 

(revised SE [ADAMS Accession No. ML11308A770]) for Topical Report MRP-227-A, the staff 

issued the following license renewal applicant or licensee action items (A/LAIs):

(1) Applicability of Failure Modes, Effects, and Criticality Analyses (FMECA) and 

Functionality Analysis Assumptions 

(2) PWR Vessel Internal Components within the Scope of License Renewal 

(3) Evaluation of the Adequacy of Plant-Specific Existing Programs 

(4) Babcock and Wilcox (B&W) Core Support Structure Upper Flange Stress Relief 

(5) Application of Physical Measurements as part of I&E Guidelines for B&W, CE, and 

Westinghouse RVI Components

(6) Evaluation of Inaccessible B&W Components
AGING MANAGEMENT REVIEW RESULTS

3-41

(7) Plant-Specific Evaluation of CASS Materials

(8) Submittal of Information for Staff Review and Approval

The above A/LAIs represent plant-specific aging management conditions to be addressed by 

the applicant as part of its program element criteria for implementing the PWR Vessel Internals 

Program.

The staff noted that NEI TR No. NEI-95-10, Revision 6, “Industry Guideline for Implementing the 

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

Appendix C of the LRA is the appropriate place for providing responses to these A/LAIs. 

However, the staff noted that Appendix C of the LRA did not include the applicant’s responses 

to the A/LAIs on MRP-227-A because the LRA was prepared and submitted to the NRC prior to 

the NRC’s issuance of the revised SE on MRP-227-A report. By letter dated 

September 25, 2012, the staff issued RAI B2.1.6-4, requesting the applicant to either provide 

the basis for omitting responses to the applicable A/LAIs on MRP-227-A or to amend its LRA to 

include the appropriate responses to the applicable A/LAIs on MRP-227-A. 

The applicant responded to RAI B2.1.6-4 in a letter dated October 24, 2012. In its response, 

the applicant stated that it will provide the specific responses to the A/LAIs on the MRP-227-A 

methodology in LRA Appendix C. The applicant stated that the LRA Appendix C supplement 

containing the A/LAI response bases will be provided consistent with Commitment No. 4 in LRA 

Table A4-1, in which the applicant commits to implementation of the PWR Vessel Internals 

Program within 24 months after the date of the EPRI MRP’s issuance of the MRP-227-A report 

(i.e., January 9, 2012, as submitted in ADAMS Accession Nos. ML12017A193, ML12017A194, 

ML12017A196, ML12017A197). The applicant also stated that Commitment No. 4 includes a 

commitment to submit the Callaway RVI inspection plan, as recommended in A/LAI #8, Item (2) 

of the NRC’s revised SE on the MRP-227-A methodology within 24 months after the date of the 

issuance of the MRP-227-A report. 

In its response to RAI B2.1.6-4, the applicant also provided the summaries of its response 

bases to these A/LAIs. The staff reviewed these A/LAI response summaries to determine which 

of the A/LAI response bases could be resolved and which of the applicant’s A/LAI response 

bases would require further RAIs. However, the staff noted that NRC Regulatory Information 

Summary (RIS) 2011-07, “License Renewal Submittal Information For Pressurized Water 

Reactor Internals Aging Management,” dated July 21, 2011 (ML111990086), provides guidance 

on the specific process that license renewal applicants or licensees would use to submit RVI 

aging management programs or inspection plans to the NRC for approval. The staff noted that, 

for plants like Callaway which would be submitting their LRAs in accordance with the guidelines 

in Revision 2 of the GALL Report (i.e., RIS 2011-07 Category D plants), the RIS identifies that 

the applicant is expected to submit an AMP for its PWR vessel internals that is consistent with 

MRP-227-A report for staff approval. Therefore, the staff noted that the applicant should resolve 

the A/LAIs on the MRP-227-A methodology as part of the staff’s review of the PWR Vessel 

Internals Program. The staff’s evaluations of the applicant’s A/LAI response bases are given in 

the italicized, underlined subsections that follow.

Evaluation of the Response Summary to A/LAI #1. In A/LAI #1, the staff recommended that 

applicants applying the MRP-227-A methodology should describe the process that would be 

used to determine whether the assumptions used to develop the methodology are bounding for 

the design of the RVI components at their PWR facility. In response to A/LAI #1, the applicant 

stated that the applicability of FMECA and Functionality Analysis Assumptions Applicability 

assumptions identified in MRP-227-A Section 2.4 are identified in the program element 1 

discussion of the applicant’s basis document for its PWR Vessel Internals Program. 
AGING MANAGEMENT REVIEW RESULTS

3-42

During the audit of the applicant’s PWR Vessel Internals Program, the staff noted that the 

applicant’s basis document for the AMP addressed why the CLB for Callaway was considered 

to be bounded by the following assumptions used to develop the MRP-227-A: (a) fuel loading 

assumptions, (b) base-load operation assumptions, and (c) RVI design change assumptions. 

Specifically, with regard to fuel loading patterns, the staff noted that the MRP-227-A report 

assumes a 60-year licensed life for the facility and that the reactor for the facility will operate at 

normal neutron leakage patterns (i.e., leakage rates) from the reactor core for the first 30 years 

of that operating term, followed by 30 years of operation with low neutron leakage patterns. 

In regard to plant operations, the staff also noted that the MRP-227-A report assumes that the 

plant operates using base load operations (i.e., the plant operates at fixed power levels and 

does not vary power on a calendar or load demand schedule) and the methodology assumes 

that the licensee for the facility has only implemented those RVI design changes that were 

recommended in industry generic communications or in vendor recommendations. 

In response to these assumptions, the applicant clarified that the CLB for the RVI components 

at Callaway is bounded by the assumptions because the plant has operated with low neutron 

leakage patterns for all operating cycles other than operating Cycle 1 (during which the plant 

operated with normal neutron leakage rates). The applicant also stated that the Callaway 

facility is a base-load facility and that the design basis for the RVI components only 

implemented those RVI design modifications that were recommended by Westinghouse as the 

nuclear steam supply system vendor for the facility (e.g., the decision to replace the control rod 

guide tube (CRGT) split pins, as recommended by Westinghouse). The staff noted that the 

applicant’s response was either consistent with the assumptions stated in the MRP-227-A report 

or bounded by them. However, the staff also noted that the FMECA and Functionality Analysis 

results that were established in the supporting EPRI MRP-191 report and used to develop the 

inspection and evaluation (I&E) recommendations for Westinghouse-designed RVI components 

in the MRP-227-A report were based on conformance with particular upper-bound component 

stress, temperature, and neutron fluence threshold values for these components. The staff 

noted that the applicant did not provide any discussion on whether the actual stress, 

temperature, and neutron fluence values for the design of the RVI components at Callaway 

were actually bounded by the threshold values for these parameters, as assumed in the 

MRP-191 report for the same components. 

By letter dated December 17, 2012, the staff issued RAI B2.1.6-4a, requesting, in part, that the 

applicant provide additional information and clarifications on how it would resolve this aspect of 

the request in A/LAI #1. The staff identified this issue as Open Item B2.1.6-1, Part (a).

The applicant responded to RAI B2.1.6-4a in a letter dated January 24, 2013. In its response, 

the applicant stated that it was addressing the request and amending Commitment No. 4 in LRA 

FSAR supplement Table A4-1 to indicate that the resolution of A/LAI #1 would be addressed as 

part of the applicant’s commitment and basis for implementing of the Reactor Vessel Internals 

Program and that the following actions would be taken relative to this commitment:

Each applicant/licensee is responsible for assessing its plant’s design and 

operating history and demonstrating that the approved version of MRP-227 is 

applicable to the facility. Each applicant/licensee shall refer, in particular, to the 

assumptions regarding plant design and operating history made in the FMECA 

and functionality analyses for reactors of their design (i.e., Westinghouse, CE, or 

B&W) which support MRP-227 and describe the process used for determining 

plant-specific differences in the design of their RVI components or plant 
AGING MANAGEMENT REVIEW RESULTS

3-43

operating conditions, which result in different component inspection categories. 

The applicant/licensee shall submit this evaluation for NRC review and approval 

as part of its application to implement the approved version of MRP-227.

The staff did not find the applicant’s response to RAI B2.1.6-4a (as made relative to the 

resolution of A/LAI #1) to be acceptable because the applicant did not submit any basis to 

demonstrate that the methodologies for Westinghouse components in the MRP-191 and 

MRP-227-A reports were applicable and bounding for the design of the RVI components at the 

Callaway facility and because Callaway is categorized as a RIS 2011-07 Category D plant. 

However, since a number of industry licensees (including Ameren Missouri) were establishing 

their efforts to resolve the NRC’s actions requested in A/LAI #1, the staff held a series of 

proprietary and public meetings with members of Westinghouse Electric Company 

(Westinghouse), the EPRI MRP, and NRC-licensed utilities in order to: (a) address the NRC’s 

regulatory bases for resolving this action item, (b) encourage the development of a generic 

approach that could be used to resolve the requests in A/LAI #1, and (c) establish a path for 

receiving comprehensive and consistent utility responses that would address the applicability of 

the MRP-227-A methodology for PWRs having either Westinghouse or Combustion Engineering 

RVI designs. As a result of these discussions, the staff agreed that a generic approach could 

be applied as a basis for resolving the action requests in A/LAI #1 if an applicant addressing the 

action item would respond to the following questions that relate to the unit’s reactor design:

Question 1: Does the plant have any nonwelded or bolted austenitic stainless steel (SS) 

components with 20 percent cold work or greater, and, if so, do the affected components

have operating stresses greater than 30 ksi? (If both conditions are true, additional

components may need to be screened in for stress corrosion cracking (SCC).)

Question 2: Does the plant have atypical fuel design or fuel management that could render

the assumptions of MRP-227-A, regarding core loading/core design, nonrepresentative for

that plant? 

By a letter dated October 14, 2013, the EPRI MRP issued EPRI MRP Letter 2013-025, 

“MRP-227-A Applicability Guidelines for Combustion Engineering and Westinghouse 

Pressurized Water Reactor Designs” (ML13322A454), which provided the industry licensees 

with a nonproprietary, generic methodology for responding to the two questions on A/LAI #1. 

The staff noted that, in regard to resolving the request in Question 1, the EPRI MRP letter 

provides the licensees with guidance for assessing whether the RVI components at their plant, 

other than those identified in the generic evaluation, would have the potential for cold work 

greater than 20 percent, and if so, whether the operating stresses for those components would 

be in excess of 30 ksi. Under this basis, nonwelded or bolted RVI components that have 

cold-work and stress levels in excess of these criteria would need to be considered for 

augmented inspections or evaluations under the MRP’s recommended protocols in EPRI MRP

Letter 2013-025. 

With respect to resolving Question 2, the staff noted that EPRI MRP Letter 2013-025 provided 

specific quantitative criteria that would allow a licensee to assess whether a particular plant has 

atypical fuel design or fuel management. For a Westinghouse-design plant like Callaway, the 

threshold criteria for assessing fuel load assumptions in EPRI MRP Letter 2013--025 and used 

to demonstrate conformance with the fuel loading assumptions in the MRP-227-A report are:

(1) The heat generation figure of merit must be less than or equal to 68 watts/cm3

.

(2) The average core power density must be less than 124 watts/cm3

.
AGING MANAGEMENT REVIEW RESULTS

3-44

(3) The distance from the top of the active fuel to upper core plate must be greater than 

12.2 in.

Therefore, the staff issued a second followup RAI that was based on conformance with the 

EPRI MRP’s generic methodology for resolving A/LAI #1, as given in EPRI MRP 

Letter 2013-025.

By letter dated December 2, 2013, the staff issued RAI B2.1.6-4d (Followup), Parts a. and b., to 

the applicant in order to request responses to these questions. In RAI B2.1.6-4d, Part a., the 

staff asked the applicant to clarify whether the design of RVI components at Callaway included 

any nonwelded or bolted austenitic stainless steel components whose design stresses are 

greater than 30 ksi and whose materials were cold worked to 20 percent or greater cold-work 

levels. If so, the staff asked the applicant to justify why the current I&E bases in MRP-227-A 

report are considered to be adequate for managing cracking or other applicable aging effects in 

these nonwelded components. Otherwise, the staff asked the applicant to clarify and justify how 

the MRP-227-A report’s I&E bases for these RVI components would be adjusted as part of the 

applicant’s basis for responding to A/LAI #2.

In RAI B2.1.6-4d (Followup), Part b., the staff asked the applicant to clarify whether Ameren has 

ever used atypical fuel designs or fuel management protocols that could make the assumptions 

in MRP-227-A for core design, core loading, and core leakage patterns nonrepresentative for 

the Callaway RVI design, including those that might have been approved for the facility in 

accordance with the NRC’s 10 CFR 50.90 process for reviewing a power uprate/power change 

license amendment request. If so, the staff asked the applicant to justify why the current I&E 

bases in MRP-227-A report were considered to be sufficient for managing cracking and other 

applicable aging effects in the plant’s RVI components based on the actual fuel loading patterns 

and fuel power conditions that were approved in the CLB. Otherwise, the staff asked the 

applicant to clarify and justify how the MRP report’s I&E bases for these RVI components would 

be adjusted as part of the applicant’s basis for responding to A/LAI #2. 

The applicant responded to RAI B2.1.6-4d, Parts a. and b., in a letter dated February 5, 2014 

(ML14036A360 for the Cover Letter and ML14036A359 for the enclosed responses to the RAI). 

On March 28, 2014, the applicant submitted a supplemental, copyrighted response to 

RAI B2.1.6-4d, Part a. (ML14087A092 for the Cover Letter and ML14087A092 for the enclosed 

supplemental response to RAI B2.1.6-4d, Part a.), that superseded the previous response to 

this RAI part in the applicant’s letter of February 5, 2014. 

In its response to RAI B2.1.6-4d, Part a., the applicant indicated that it used the EPRI MRP-191 

report bases and EPRI MRP Letter 2013-025 guidelines (ML13322A454) as the bases for 

comparing the stress levels of the RVI components at Callaway to those evaluated for the 

generic Westinghouse design plant that was assumed and assessed in the EPRI MRP-227-A 

and MRP-191 reports. The applicant stated that it contracted with Westinghouse to gather the 

necessary information needed to verify whether the stress levels in the RVI components and 

amount of cold work in the materials used to fabricate the RVI components were within the 

bounds assessed for these components in the MRP-191 report and to assist the applicant in its 

development of the response to this RAI.

2

 

 

2 The staff acknowledges that its summary of the applicant’s response to RAI B.2.1.6-4d, Part a., is a summary of the 

copyrighted response prepared for the applicant by the Westinghouse Electric Company and that the Westinghouse 

Electric Company has designated that the specific response to the RAI is copyrighted material that is copyright 

protected in accordance with the following Westinghouse designation: 
AGING MANAGEMENT REVIEW RESULTS

3-45

The applicant indicated that none of the RVI components made from CASS or hot-formed or 

annealed austenitic stainless steel materials had cold-work levels in excess of 20 percent

because the acceptable levels of cold work were addressed through conformance with the 

material specifications used to fabricate the components. The applicant stated that these levels 

of cold work were ensured through implementation of controlled fabrication processes that were 

used to make the components. The applicant also indicated that, for those fastened (bolted) or 

welded RVI components in which the applicant conservatively concluded the cold-work levels 

would be in excess of 20 percent, the MRP methodology was crediting either “Primary 

Category” or “Existing Program” category inspections of the components. The staff finds this 

basis to be acceptable because either the components had been appropriately screened out for 

inspection as “No Additional Measures” components for the program or the applicant is 

performing appropriate inspections of the components to account for the possibility that the 

stress levels for the components would be in excess of those assumed for the components in 

the MRP-191 and MRP-227-A reports. The concern raised in RAI B2.1.6-4d, Part a., is 

resolved.

In its response to RAI B.2.1.6-4d, Part b., the applicant stated that the methodology in 

TR MRP-227-A assumed that the degradation rate of the reactor internals would decrease 

during the second 30 years of operation. The applicant stated that this basis assumes the use 

of low-leakage reactor cores during this period, and thus precludes the use of out-in core 

loading patterns. The applicant also stated that Attachment 1 in EPRI Letter MRP 2013-025 

provides criteria for resolving the request in RAI B.2.1.6-4d, Part b. The applicant explained 

that, for Westinghouse PWRs, these criteria (as summarized above), if met, may be used to 

demonstrate that the fuel loading assumptions of the MRP-227-A report are bounding for the 

RVI components at Callaway.

In regard to meeting the criterion on average core power density for the reactor, the applicant 

clarified that, historically, the average core power density for Callaway has been 

111.7 watts/cm3 since Cycle 3, when licensed reactor power for the facility was uprated, and 

was 106.9 watts/cm3 prior to the power uprate; Therefore, since the the average core power 

density has always been less than 124 watts/cm3

, the applicant concluded that Callaway’s fuel 

loading pattern meets the limiting assumptions set forth in EPRI Letter MRP 2013-025. 

With regard to the heat generation figure of merit, the applicant stated that all reload fuel cycles 

met the limit of 68 watts/cm3

, with the exception of: (a) fuel cycles 2 and 13 for Type 1 corners; 

and (b) fuel cycle 3 for Type 2 corners. The applicant stated that the duration of fuel cycle 2, 

which ran from April 1986 to September 1987, amounted to 1.15 effective full power years 

(EFPY) of power operation; the duration of fuel cycle 3, which ran from November, 1987, to 

March, 1989, was 1.23 EFPY; and the duration of fuel cycle 13, which ran from November 2002 

to April 2004, amounted to 1.26 EFPY. The applicant stated that, although the heat generation 

figure of merit exceeded 68 watts/cm3 during operating cycles 2, 3, and 13, those fuel cycles 

occurred in the first 20 years of operation. The applicant stated that the heat generation figure 

of merit did not exceed this value during the next 10 years of operation, and is not expected to 

exceed it in the second 30 years of operation. The applicant stated that, since these three fuel 

cycles occurred in the first 20 years of operation, they do not invalidate the requirement to not 

use out-in loading patterns during the second 30 years of operation. The applicant also stated 

that the relatively short durations of these three fuel cycles in the first 30 years of operation are 

 

“© 2014 Westinghouse Electric Company LLC

All Rights Reserved”
AGING MANAGEMENT REVIEW RESULTS

3-46

offset by many more years of operation in which the heat generation figure of merit was below 

the limit established by the MRP. 

The applicant also stated that, although the distance from the active fuel to the upper core plate 

has varied as a result of changes in fuel design, this distance has always been greater than 

12.2 in., which meets the limit set by this parameter in EPRI Letter MRP 2013-025. The 

applicant stated that, to ensure that these limits are met in future core designs, it will continue to 

use in-out core loading patterns for Callaway in all future fuel cycles and that the core design 

procedure will be modified to include steps calling for the review of the following core loading 

pattern parameters:

(1) Distance between the top of the active fuel and the upper core plate greater than

12.2 in.

(2) Reactor average core power density less than 124 watts/cm3

(3) Reactor heat generation figure of merit less than or equal to 68 watts/cm3

The applicant stated that Commitment No. 43 was added to LRA FSAR supplement Table A4-1 

in the applicant’s letter of January 16, 2014 (ML14017A008 for the Cover Letter and 

ML14017A007 for the enclosure containing the commitment), in order to ensure that the core 

design procedure will be revised accordingly. 

The staff noted that, in its response to RAI B2.1.6-4d, Part b., the applicant provided the specific 

value of the maximum average core power density for Callaway over the last 30 years and 

demonstrated that this power density is less than the MRP Letter’s upper bound limit of

124 watts/cm3 for average core power densities of Westinghouse-designed reactor units. The 

staff noted that the applicant also provided specific information to demonstrate that, with the 

exception of operations during cycles 2, 3, and 13, the heat generation figure of merit values for 

the unit did not exceed the 68 watts/cm3 threshold limit established for Westinghouse-designed 

plants in EPRI Letter MRP 2013-025, and that, for at least the last 10 years, operations at 

Callaway have resulted in heat generation rates that are within this limit. The staff also noted 

that the applicant had assessed the nominal distance between the top of the active core and the 

upper core plate and had provided sufficient information to demonstrate that the minimum 

12.2-inch distance would be achieved in spite of any minor variations that may occur in the 

lengths of the actual fuel design configurations. 

In addition, the staff noted that, in the applicant’s letter of January 16, 2014 (ML14017A008 for 

the Cover Letter and ML14017A007 for the enclosure containing LRA Commitment No. 43), the 

applicant amended the LRA to include Commitment No. 43 in FSAR supplement Table A.4-1, 

which includes the following actions: 

The core design procedure will be modified to include a review for the following 

core design parameters to ensure that these limits are met in future core designs:

• Distance between the top of the active fuel and the upper core plate greater than

12.2 in.

• Reactor average core power density less than 124 watts/cm3

• Reactor heat generation figure of merit, F less than or equal to 68 watts/cm3

The staff verified that, by letter dated February 14, 2014, the applicant responded to indicate 

that Commitment No. 43 had been completed and that the core design procedure had been 
AGING MANAGEMENT REVIEW RESULTS

3-47

revised to include procedural steps to review the active fuel–upper core plate distance, average 

core power density, and heat generation figure of merit value parameters during future plant 

operations, and to compare these parameters against the EPRI MRP’s threshold values for 

these parameters in EPRI MRP Letter 2013-025. 

Based on this review, the staff finds that the applicant has provided adequate demonstration 

that the fuel loading patterns assumed in MRP-227-A are and will be representative of plant 

operations at Callaway because: (a) for all three parameters (with the exception of the heat 

generation figure of merit for Cycles 2 and 13), the applicant has demonstrated that the core 

loading parameters are within the thresholds set for these parameters in EPRI MRP 

Letter 2013-25; (b) this demonstrates that the core loading patterns for the reactor unit are 

bounded by the fuel loading assumptions for Westinghouse-designed internals in the 

MRP-227-A report; and (c) the applicant has amended its core operating procedures to perform 

reviews of the average core density, heat generation figure of merit, and active fuel–upper core 

plate distance parameters during the period of extended operation. The staff’s concern in 

RAI B2.1.6-4d, Part b, is resolved. 

Therefore, based on this review, the staff finds that the applicant has adequately addressed the 

actions requested in A/LAI #1 because the applicant has provided sufficient information to 

demonstrate that either the cold work-induced stress level and fuel loading patterns for the unit 

are within those established for Westinghouse-designed PWRs in EPRI MRP Letter 2013-025 

or has demonstrated that the program accounts for potential deviations from the EPRI MRP’s 

stress level or fuel loading pattern assumptions by inspecting the components in accordance 

with the EPRI MRP recommendations in TR MRP-227-A. Furthermore, the staff has confirmed 

that, consistent with the procedural changes that have been made in accordance with 

completion of LRA Commitment No. 43, the applicant will continue to assess plant performance 

against the fuel load pattern assumptions and criteria that were established in EPRI MRP Letter

2013-025 in order to demonstrate that future operations of the Callaway reactor will continue to 

conform with these limits during the period of extended operation. Therefore, the requested 

action in A/LAI #1 is resolved, and Open Item B2.1.6-1, Part (a) is closed. 

Evaluation of the Response Summary to A/LAI #2. In A/LAI #2, the staff requested that PWR 

applicants for license renewal should perform a review of the CLBs against the information in 

Tables 4-4 and 4-5 of the MRP-191 report and identify whether these tables contain all of the 

RVI components that are within the scope of license renewal for their facilities in accordance 

with 10 CFR 54.4. If the tables do not identify all the RVI components that are within the scope 

of license renewal for its facility, the staff recommended that the applicant identify the missing 

component(s) and propose any necessary modifications to the program defined in MRP-227-A 

when submitting its plant-specific AMP for staff review. The staff stated that the AMP should 

provide assurance that the effects of aging on the missing component(s) will be managed for 

the period of extended operation. In its response to A/LAI #2, the applicant stated that 

“Callaway AMR items for RVI components in LRA Table 3.1.2-1 have been updated to be 

consistent with MRP-191 and MRP-227-A report bases for Westinghouse reactor internals.” 

The staff noted that the applicant was already addressing some additional aging management 

issues in the CLB for the RVI components that would not specifically be addressed through the 

implementation of the MRP-227-A methodology and the response summary to these A/LAIs did 

not credit the additional conservatisms being applied due to aging management of its RVI 

internals. Specifically, the staff noted that in LRA Table 3.1.2-1, the applicant includes AMR 

items for the RVI components that credit one of the following three condition monitoring AMPs 

(i.e., inspection-based AMPs) for aging management of the plant’s RVI components: (a) PWR 
AGING MANAGEMENT REVIEW RESULTS

3-48

Vessel Internals Program, for those RVI components that are defined as Westinghouse-design 

“Primary Category,” “Expansion Category,” or ASME Section XI “Existing Program” components 

in the MRP-227-A report; (b) Flux Thimble Tube Inspection Program, for the RVI flux thimble 

tubes; and (c) ASME Section XI Inservice Inspection, Subsections, IWB, IWC, and IWD 

Program, for those components that are defined as ASME Code Section XI, Examination 

Category B-N-3 core support structure components for the CLB but are designated as “No 

Additional Measure” components under the EPRI MRP’s methodology in the MRP-227-A report. 

The staff noted that, between these three AMPs, the applicant will be applying a sampling basis 

to the inspection of its RVI components that is more conservative than what the EPRI MRP 

would have the applicant inspect in accordance with Tables 4-3, 4-6, and 4-9 in the MRP-227-A 

report. Examples of RVI components that would be omitted from inspection under the 

MRP-227-A methodology basis but will be inspected by the applicant in accordance with the 

ASME Code Section XI ISI requirements for Examination Category B-N-3 components include 

(but are not limited to) the support pins (split pins) in the control rod guide tube (CRGT) 

assemblies, the reactor vessel Charpy-impact specimen holders, and the neutron shield panel. 

The applicant’s response to RAI 3.1.2.1-1 identifies those RVI components that will be 

inspected as ASME Section XI, Examination Category B-N-3 requirements for the CLB, but 

would not be inspected in accordance with the MRP-227-A methodology basis due to their 

categorization as “No Additional Measures” components.

The staff also noted that, in the LRA, as amended by the applicant’s response to RAI 3.1.2.1-2, 

Parts a. and b., the applicant identified that the incore instrumentation (ICI) support structure 

upper and lower tie plates were additional plant-specific “Expansion Category” components for 

the applicant’s PWR Vessel Internals Program and that any plans to inspect these components 

as additional “Expansion Category” components would be tied to the inspection results of those 

“Primary Category” inspections that will be performed on the CRGT lower flanges during the 

period of extended operation. The staff noted that this is in addition to those “Expansion 

Category” inspections that would normally be applied to the BMI column bodies and lower 

support column bodies under the MRP-227-A methodology when warranted by the inspection 

results for the CRGT lower flange components. Thus, the staff noted that the applicant had 

adjusted its LRA to include the ICI support structure upper and lower tie plates as additional 

“Expansion Category” components for the program and its basis for resolving the request in 

A/LAI #2. 

Further clarifications on the applicant’s AMR item bases for the RVI components are given in 

the applicant’s responses to RAIs 3.1.2.1-2, 3.1.2.1-3, 3.1.2.1-4, 3.1.2.1-5, and 3.1.2.2-1. The 

staff reviews the adequacy of the AMR items for the RVI components in SER Sections 3.1.2.1.2, 

3.1.2.1.3, 3.1.2.2.10, and 3.1.2.2.14. The staff’s evaluations in these SER sections include the 

staff’s bases for: (a) resolving the staff’s requests that were issued in RAI Nos. 3.1.2.1-1, 

3.1.2.1-2, 3.1.2.1-3, 3.1.2.1-4, 3.1.2.1-5 and 3.1.2.2-1; and (b) accepting the applicant’s AMR 

items for these components, as given in LRA Table 3.1.2-1 and clarified in the RAI responses 

and in specific LRA amendments that were provided in the applicant’s letters dated 

April 25, 2012, and October 24, 2012. 

In addition, based on the staff’s review of the applicant’s response A/LAI #7 (refer to the 

Evaluation of the Response Summary to A/LAI #7 section that follows), the staff noted that the 

applicant does not need to make any programmatic adjustments for those RVI components at 

Callaway that are made from CASS, martensitic stainless steel, or precipitation-hardened 

martensitic stainless steel materials because: (a) the staff has confirmed that the components 

that are made from these materials have been dispositioned as “No Additional Measures” 
AGING MANAGEMENT REVIEW RESULTS

3-49

components in the MRP-227-A and MRP-191 reports, and (b) this is consistent with the staff’s 

basis for addressing A/LAI #7 in the staff’s revised SE on the MRP-227-A methodology (refer to 

the SE of December 16, 2011).

Based on this review, the staff finds that the applicant has adequately addressed the action 

requested in A/LAI #2 because: (a) the applicant has credited additional ASME Code 

Section XI inspections and Expansion Category inspections of the RVI components in the plant 

design as part of the applicant’s aging management bases for these components; (b) these 

plant-specific inspection bases were added to address the specific design configurations of the 

RVI upper and lower internals assemblies at the Callaway facility and are in addition to and go 

beyond the augmented inspection criteria that were recommended for the 

Westinghouse-designed RVI components in the MRP-227-A report; and (c) for the remaining 

RVI components, the applicant has provided sufficient demonstration that the EPRI MRP’s 

protocols for inspecting the components do not need to be altered or augmented beyond those 

recommended for the components in TR MRP-227-A. The request in A/LAI #2 is resolved.

Evaluation of the Response Summary to A/LAI #3. In A/LAI #3, the staff recommended that 

applicants applying the MRP-227-A methodology should perform a plant-specific analysis either 

to justify the acceptability of an applicant’s or licensee’s existing programs for its CRGT split 

pins, or else identify changes to the programs that should be implemented to manage the aging 

of these components for the period of extended operation. The staff requested that the results 

of this plant-specific analysis and a description of the plant-specific program being relied upon to 

manage aging of the CRGT split pins should be submitted as part of the applicant’s RVI 

management AMP that is provided in the LRA.

The applicant stated that the evaluation of the adequacy of plant-specific “Existing Programs” 

for the Callaway RVI components in the AMR items of LRA Table 3.1.2-1 have been updated to 

address the cracking of the CRGT pins (split pins) as Existing Program Components to be 

consistent with MRP-227-A. 

The staff verified that in the applicant’s letter of October 24, 2012 (ML12299A248 for the Cover 

Letter and ML12299A249 and ML12299A250 for the associated enclosures), the applicant 

amended its AMR item for the CRGT split pins to credit the ASME Code Section XI “Existing 

Program” inspections as the basis for managing cracking and loss of material due to wear that 

may occur in the CRGT split pin components during the period of extended operation. 

Therefore, the staff finds this basis to be acceptable because the applicant’s application of the 

ASME Code Section XI, Examination Category B-N-3 requirements to the CRGT split pins will 

ensure that the applicant will inspect the components even though they have already been 

replaced with split pins that are made from more fracture-resistant materials (i.e., the split pins 

from the more SCC susceptible Alloy X-750 Inconel materials have already been replaced with 

CRGT split pins made from cold-worked type 316 austenitic stainless steel). On the basis of 

this review, the staff concludes that the applicant has addressed the action requested in 

A/LAI #3 because the applicant will be inspecting the CRGT split pins in accordance with its 

ASME Section XI ISI Program requirements, as applied by inspection criteria equivalent to 

those for ASME Code Section XI, Examination Category B-N-3 components. The action 

requested in A/LAI #3 is resolved.

Evaluation of the Response Summary to A/LAI #4. In A/LAI #4, the staff recommended that 

B&W applicants or licensees should confirm that the core support structure upper flange weld 

was stress-relieved during the original fabrication of the RPV in order to confirm that the 

assumption for these welds in MRP-227-A basis is applicable to the fabrication of the weld in 

B&W applicant’s plant design. 
AGING MANAGEMENT REVIEW RESULTS

3-50

The applicant stated that the A/LAI on B&W core support structure upper flange stress reliefs is 

not applicable to the design of the RVI components at the Callaway. The staff finds this basis to 

be acceptable because the nuclear steam supply system for Callaway was designed by 

Westinghouse Corporation. 

The staff confirmed that LRA AMR Table 3.1.2-1 indicates that the analogous core barrel upper 

flange welds for the Callaway plant are within the scope of the applicant’s PWR Vessel Internals 

Program and that the AMP will be crediting the “Primary Category” inspections for these welds 

in the MRP-227-A methodology as the basis for aging management of these welds. On the 

basis of this review, the staff concludes that the applicant has addressed the action requested in 

A/LAI #4 because the action item is not applicable to the design of the RVI components at 

Callaway. The action requested in A/LAI #4 is resolved.

Evaluation of the Response Summary to A/LAI #5. In A/LAI #5, the staff recommended that 

Westinghouse-design applicants for renewal should identify the plant-specific acceptance 

criteria to be applied to evaluations of the results of physical measurement techniques that will 

be applied to the RVI hold-down spring for the facility, as recommended in Table 5-3 of the 

MRP-227-A report. The staff recommended that the applicant include its proposed acceptance 

criteria and explain how the proposed acceptance criteria are consistent with both the plant’s 

licensing basis and the need for maintaining the intended function of the hold-down spring under 

all licensing basis conditions of operation.

The applicant stated that the application of physical measure techniques are part of the I&E 

guidelines in MRP-227-A for specific Westinghouse-designed RVI components. The applicant 

stated that the physical measurements for the Callaway RVI hold-down spring are identified in 

program element 6 of GALL Report AMP XI.M16A, “PWR Vessel Internals,” and that Callaway 

will determine the acceptance criterion to be consistent with Table 5-3 of the MRP-227-A report. 

The applicant’s response to A/LAI #5 confirms that the applicable Callaway component that is 

within the scope of the A/LAI is the Callaway RVI hold-down spring. During the audit, the staff 

determined that the applicant’s PWR Vessel Internals Program appropriately included “detection 

of aging effects” program element criteria to: (a) perform direct physical measurements of the 

spring height for the hold-down spring and (b) perform additional measurements of hold-down 

spring height over the next two RFOs if the original spring height measurement was not 

sufficient to demonstrate adequate hold-down spring life during the period of extended 

operation. 

The staff finds this approach to be acceptable because it will provide the applicant with a 

reasonable basis for estimating the amount of hold-down spring height that will occur such that 

it will meet the criterion for this type of aging management in Table 5-3 of the MRP-227-A report 

to determine the amount of spring height. However, the staff noted that the applicant is 

deferring the establishment of the acceptance criteria that will be applied to the evaluation of the 

physical measurement results for the hold-down spring and that this does not resolve the 

request in A/LAI #5. 

By letter dated December 17, 2012, the staff issued RAI B2.1.6-4a, requesting, in part, that the 

applicant provide additional information and clarifications on how it would resolve the action item 

in A/LAI #5. The staff identified this issue as Open Item B2.1.6-1, Part (b).

By letter dated January 24, 2013 (ML13029A243 for the Cover Letter and ML13029A244 for the 

enclosures containing the RAI response and associated LRA amendments for LRA Amendment 

No. 20), the applicant provided its response to RAI B2.1.6-4a indicating that it has replaced the 

hold-down spring with a Type 403 martensitic stainless steel material and that under the 
AGING MANAGEMENT REVIEW RESULTS

3-51

methodology in the MRP-227-A report, hold-down springs made from Type 403 materials do not 

need to be subject to the EPRI MRP’s physical measurement inspections that are 

recommended for hold-down springs made from Type 304 austenitic stainless steel materials.

The staff noted that, during the development of the EPRI MRP’s recommended augmented 

inspection methodology for Westinghouse-designed RVI components in the MRP-227-A report 

and the staff’s endorsement of that methodology (refer to NRC’s revised SE on the MRP-227-A 

report dated December 16, 2011, as given in ADAMS ML11308A770), the staff endorsed the 

EPRI MRP’s basis that Westinghouse-designed hold-down springs made from Type 403 

martensitic stainless steel materials are not subject to stress relaxation such that the 

functionality of the component will be jeopardized during the period of extended operation under 

design basis loading conditions. Specifically, the NRC accepted the EPRI MRP’s position that 

loss of preload due to stress relaxation or wear would not need to be managed in hold-down 

springs made from Type 403 martensitic stainless steel materials due to better material stiffness 

properties of Type 403 materials, when compared to hold-down springs that are made from 

Type 304 austenitic stainless steel materials.

Therefore, based on this verification, the staff concluded that the applicant had provided an 

acceptable basis for concluding that loss of preload due to stress relaxation would not need to 

be managed in the hold-down spring at Callaway because: (a) the hold-down spring is made 

from Type 403 martensitic stainless steel material, and (b) the hold-down spring at Callaway is 

not within the scope of any MRP-defined augmented inspection criteria in the MRP-227-A 

report. Therefore, based on this review, the staff has confirmed that the applicant’s response to 

RAI B2.1.6-4a has adequately addressed the NRC’s recommended action in A/LAI #5. The 

action requested in A/LAI #5 is resolved and Open Item B2.1.6-1, Part (b) is closed.

Evaluation of the Response Summary to A/LAI #6. In A/LAI #6, the staff recommended that 

B&W-design applicants for renewal should justify the acceptability of certain B&W RVI 

components for continued operation through the period of extended operation by performing an 

evaluation, or by proposing a scheduled replacement of the components. 

The applicant stated that the A/LAI regarding the evaluation of inaccessible and noninspectable 

B&W RVI components is not applicable to the design of the RVI components at Callaway 

because the components were designed by Westinghouse. The staff finds this basis to be 

acceptable because the RVI components at Callaway were designed by Westinghouse and not 

by B&W. On the basis of this review, the staff concludes that the applicant has addressed the 

actions requested in A/LAI #6 because the action item is not applicable to the design of the RVI 

components at Callaway. The action requested in A/LAI #6 is resolved.

Evaluation of the Response Summary to A/LAI #7. In A/LAI #7, the staff recommended that 

license renewal applicants for Westinghouse reactors should develop plant-specific analyses to 

demonstrate that lower support column bodies made from cast austenitic stainless steel 

(CASS), martensitic stainless steel, or precipitation-hardened stainless steel materials will 

remain functional during the period of extended operation. The staff also recommended that 

these analyses should consider the possibility of loss of fracture toughness occurring in these 

components as a result of thermal aging and neutron irradiation embrittlement and should 

consider any limitations on accessibility of the components to inspection and the resolution and 

sensitivity of the inspection techniques that would be applied to these components. The staff 

recommended that the plant-specific analysis should be consistent with the plant’s licensing 

basis and the need to maintain the functionality of the components being evaluated under all 

licensing basis conditions of operation. The staff also recommended that the applicant should 

include the plant-specific analysis as part of the PWR Vessel Internals Program that would be 
AGING MANAGEMENT REVIEW RESULTS

3-52

submitted in accordance with A/LAI #8, Item (1) or as part of the inspection plan that would be 

submitted in accordance with A/LAI #8, Item (2).

The applicant stated that this A/LAI is not applicable to Callaway. The applicant stated that the 

design of the RVI components at Callaway does not include lower support column bodies that 

are made from CASS materials. 

The staff noted that the MRP-227-A report identifies that the following RVI components in 

Westinghouse-designed PWRs may be fabricated from CASS materials (e.g., CF8 CASS 

materials): (a) CRGT assembly lower flanges, (b) bottom mounted instrumentation (BMI) 

column cruciform, (c) lower internals assembly lower support casting, and (d) lower support 

assembly lower support column bodies. 

The staff reviewed FSAR Section 4.5.2, “Reactor Internals Materials,” and noted that the FSAR

indicates that RVI components at Callaway are typically made from either wrought or forged 

stainless steel grades (i.e., from Type 304 or 316 austenitic stainless steels) or Alloy X-750 

Inconel materials. Therefore, staff noted that the topic and issue raised in A/LAI #7 would not 

be applicable to the design of the lower core support column bodies because they are not made 

from CASS materials. However, the staff also noted that the scope of A/LAI #7 also applies to 

any other component that is made from a CASS, martensitic stainless steel, or 

precipitation-hardened martensitic stainless steel material and was not considered and 

evaluated in the development of the MRP-227-A report (i.e., not considered or evaluated in 

either MRP-227-A or the supporting MRP-191 background document). The staff confirmed that 

FSAR Table 5.2-4 identifies that the Callaway RVI design includes RVI components made from 

CF8 or CF8A CASS materials. Thus, it was not evident which of the RVI components in the 

plant design were made from these types of CASS materials, or for each RVI component made 

from CASS, why the applicant would not need to provide a supporting flaw tolerance analysis, 

functionality analysis, or CASS susceptibility analysis for the component, as recommended in 

A/LAI #7. 

By letter dated September 20, 2013, the staff issued RAI B2.1.6-4b, requesting that the 

applicant consider the information in FSAR Table 5.2-4 and, based on this information, identify 

those RVI components that are specifically fabricated from CF8 or CF8A CASS materials. For 

those RVI components that are made from these materials, the staff asked the applicant to 

clarify whether the components were considered in the development of the MRP-227-A 

recommendations for management of thermal aging embrittlement and neutron irradiation 

embrittlement effects and dispositioned in accordance with applicable component category 

recommendations for the components in the MRP-227-A report. If it is determined that any RVI 

CASS component was not considered in the development of the MRP-227-A report and 

appropriately dispositioned in the report, the staff asked the applicant to clarify and justify how 

the PWR Vessel Internals Program will be adjusted under A/LAI #2 to manage loss of fracture 

toughness in the components as a result of potential neutron irradiation embrittlement and 

thermal aging embrittlement mechanisms; consistent with the position in A/LAI #7, if it is 

determined that the basis for aging management (as applicable) will be by implementation of a 

component-specific evaluation, the staff requested that the applicant submit the evaluation for 

NRC review and approval as part of the LRA review. The staff identified this issue as Open 

Item B2.1.6-1, Part (c).

The applicant responded to RAI B2.1.6-4b in a letter dated January 16, 2014 (ML14017A008 for 

the Cover Letter and ML14017A007 for the enclosures containing the RAI response and 

associated LRA amendments for LRA Amendment No. 29). The applicant stated that there are 

only two RVI components at Callaway that are fabricated from CASS: (a) the BMI column 
AGING MANAGEMENT REVIEW RESULTS

3-53

cruciforms and (b) an offset instrumentation column cruciform that was evaluated in accordance 

with the criteria in MRP-191 for evaluating BMI column cruciforms. The applicant stated that the 

MRP-227-A functionality assessment for these CASS components placed the components in 

the “No Additional Measures” assessment category. The applicant also stated that the 

remaining RVI components that were identified in MRP-191 as possibly being fabricated from 

CASS materials (i.e., the CRGT assembly intermediate and lower flanges, upper support 

column bases in the upper internals assembly, lower support column bodies and lower support 

in lower internals assembly) were fabricated from non-cast austenitic stainless steel materials. 

Therefore, the applicant stated that aging management of thermal aging embrittlement and 

neutron embrittlement effects of CASS RVI components at Callaway is not required.

The staff noted that the applicant’s response to RAI B2.1.6-4b clarified that the BMI column 

cruciform (including the offset instrumentation column cruciform) are the only RVI components 

at Callaway that are made from CASS materials and that these components were dispositioned 

as “No Additional Measures” components in accordance with MRP’s methodologies in 

MRP-227-A and MRP-191. The staff verified that the MRP has evaluated these CASS 

components in MRP-227-A and MRP-191 reports and placed these components in the MRP’s 

“No Additional Measures” category. The staff also noted that, in the NRC’s SE of 

December 16, 2011, the NRC established the following position in regard to the need for 

performing augmented aging management of CASS components in the “No Additional 

Measures” category:

. . . , the requirement [ . . for augmented analysis . . ] may not apply to 

[. .CASS . .] components that were previously evaluated as not requiring aging 

management during development of MRP-227. That is, the requirement would 

apply to components fabricated from susceptible materials for which an individual 

licensee has determined aging management is required, for example during their 

review performed in accordance with Applicant/Licensee Action Item 2.

Therefore, based on this review, the staff finds that the applicant has provided an acceptable 

basis for concluding that these CASS components do not need to be subjected to augmented 

inspections or analyses beyond those recommended in the MRP-227-A report because the staff 

has confirmed that these RVI components at Callaway have been dispostioned in the 

MRP-227-A report as “No Additional Measures” components and, consistent with the staff’s 

revised SE on MRP-227-A, CASS components falling into the “No Additional Measures” 

category do not require aging management in accordance with the criteria in A/LAI #7. On the 

basis of this review, the staff concludes that the applicant has adequately addressed the action 

requested in A/LAI #7 because the staff has verified that the CASS RVI components, as “No 

Additional Measures” components, do not need to be within the scope of any augmented 

inspections or evaluations, as defined in accordance with the methodology in MRP-227-A. The 

action requested in A/LAI #7 is resolved and Open Item B2.1.6-1, Part (c) is closed.

Evaluation of the Response Summary to A/LAI #8, Items (1) – (5). MRP-227-A, A/LAI #8, is 

divided into five items. The applicant’s responses are evaluated as follows.

• A/LAI #8, Item (1). In A/LAI #8, Item (1), the staff recommended that PWR applicants for 

renewal submit an AMP in the LRAs that addresses the 10 AMP program elements for 

aging management of PWR RVI components in GALL Report AMP XI.M16A, “PWR 

Vessel Internals.” 

The applicant stated that Callaway has provided the PWR Vessel Internals Program for 

NRC audit that addresses the 10 program elements of GALL Report AMP XI.M16A. The 
AGING MANAGEMENT REVIEW RESULTS

3-54

applicant clarified that the basis documents for the PWR Vessel Internals Program have 

been updated to conform with the recommendations in the MRP-227-A report and the 

NRC’s revised SE on this report dated December 16, 2011 (ML11308A770). 

During the audit of the PWR Vessel Internals Program, the staff verified that the basis 

document for the AMP was based on a direct comparison to the 10 program elements that 

are defined for these types of AMPs in GALL Report AMP XI.M16A, “PWR Vessel 

Internals.” The staff also noted that the applicant has addressed the action requested in 

A/LAI #8, Item (1) because the staff has confirmed that: (a) the applicant has included an 

RVI management AMP in the LRA that is based on the 10 program elements 

recommended for PWR RVI management AMPs in GALL Report AMP XI.M16A, and 

(b) the inclusion of this AMP in the LRA conforms to the action that is recommended and 

requested in A/LAI #8, Item (1). On the basis of its review, the staff concludes that the 

applicant has conformed to the action recommended in A/LAI #8, Item (1). The staff’s 

audit evaluation of the PWR Vessel Internals Program is given in the audit report for this 

LRA and supplements the evaluation of the PWR Vessel Internals Program in this SER 

section. The action requested in A/LAI #8, Item (1) is resolved.

• A/LAI #8, Item (2). In A/LAI #8, Item (2), the staff recommended that, to ensure the 

MRP-227-A program and the plant-specific action items will be carried out by PWR license 

renewal applicants, the applicant should submit an inspection plan which addresses the 

identified plant-specific action items for staff review and approval consistent with the 

licensing basis for the plant. In this A/LAI, the staff stated that, if an applicant plans to 

implement an AMP that deviates from the guidance provided in the MRP-227-A report, the 

applicant should identify where its AMP deviates from the recommendations of 

MRP-227-A report and should provide a justification for any deviation that impacts the 

report’s recommendations for “Primary” and “Expansion” inspection category components.

The applicant stated that it will provide the inspection plan consistent with LRA 

Commitment No. 4 within 24 months after the issuance of MRP-227-A. The applicant 

stated that the inspection plan will address plant-specific action items and identify any 

deviations to MRP-227-A with justification. However, as has been stated previously in the 

introduction to the overall A/LAI evaluation section, the staff did not permit the applicant to 

use LRA Commitment No. 4 as a basis for resolving any A/LAIs that remained as open 

items for the program because: (a) Callaway is identified as a Category D facility under 

the RVI review categorizations in NRC RIS 2011-07; and (b) under this categorization, the 

applicant would have to resolve any potential issues with the inspection bases for the AMP 

(including resolution of any applicable A/LAIs) as part of the basis for getting the LRA’s 

PWR Vessel Internals Program approved by the staff. 

The staff noted that the applicant has provided an acceptable basis for resolving all A/LAIs 

on the MRP-227-A methodology that apply to the design of the Westinghouse-designed 

RVI components at Callaway and has made applicable adjustments of the program based 

on the actual design of the RVI components at Callaway. Examples of this are: (a) the 

applicant’s identification in its April 23, 2014, letter that the Callaway baffle-former 

assembly design does not include baffle-edge bolts, which otherwise would need to be 

inspected under the MRP’s recommended program if they were present in the plant 

design; (b) the applicant’s identification that its Inservice Inspection Program (LRA 

AMP B2.1.1) will be used to inspect those RVI components that are identified as being “No 

Additional Measures Components” under the MRP-227-A methodology but will be 

inspected using criteria equivalent to those for ASME Code Section XI, Examination 

Category B-N-3 removable core support structure components in the CLB; and (c) the 

applicant’s identification of the incore instrumentation (ICI) support structure upper and 
AGING MANAGEMENT REVIEW RESULTS

3-55

lower tie plates as additional plant-specific “Expansion Category” components for the 

applicant’s Program and plans to inspect these components as additional “Expansion 

Category” components based on the inspection results of those “Primary Category” 

inspections that will be performed on the control rod guide tube (CRGT) lower flanges in 

the plant design. 

Therefore, based on this review, the staff concludes that the applicant will not need to 

submit an inspection plan for staff approval in accordance with an LRA commitment in the 

FSAR supplement and that, instead, the staff’s reviews of the AMR items for the Callaway 

RVI components, as given in applicable subsections of SER Sections 3.1.2.1 and 3.1.2.2, 

and the applicant’s PWR Vessel Internals Program and responses to applicable A/LAIs on 

the MRP-227-A methodology, as given in this evaluation section, serve as an acceptable 

basis for either confirming consistency of the AMP with the recommendations of the 

MRP-227-A methodology (as applied to the Callaway design), or else that the applicant 

has adjusted the program accordingly based on the actual design of the RVI components 

in the site and the recommended actions in A/LAI No. 2. The action requested in A/LAI 

#8, Item (2) is resolved.

• A/LAI #8, Item (3). In A/LAI #8, Item (3), the staff stated that 10 CFR 54.21(d) requires 

that an FSAR supplement for the facility contain a summary description of the programs 

and activities for managing the effects of aging and the evaluation of time-limited aging 

analyses (TLAAs) for the period of extended operation. 

In this A/LAI, the staff stated that license renewal applicants referencing the MRP-227-A 

report for their RVI management AMP shall ensure that the programs and activities 

specified as necessary in the MRP-227-A report are summarily described in the FSAR 

supplement.

The applicant stated that the Callaway FSAR supplement described in LRA Section A1.6 

includes an FSAR supplement summary description for the applicant’s PWR Vessel 

Internals Program and that it is consistent with the MRP-227-A report and with the NRC’s 

revised SE on the MRP-227-A report’s methodology (ML11308A770). The applicant 

clarified that the FSAR supplement summary description for the RVI metal fatigue TLAAs 

does not credit the PWR Vessel Internals Program as the basis for accepting the TLAAs in 

accordance with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(iii).

The staff confirmed that the applicant has included the FSAR supplement summary 

description for the PWR Vessel Internals Program in LRA Section A1.6 and the FSAR 

supplement summary description for the RVI metal fatigue TLAAs in LRA Section A3.2.2, 

“ASME Section III Subsection NG Fatigue Analysis of Reactor Pressure Vessel Internals.” 

The staff finds that the applicant has addressed the request in A/LAI #8, Item (3) because: 

(a) the staff confirmed that the applicant has included the applicable FSAR supplement 

summary descriptions for the applicant’s PWR Vessel Internals Program in Appendix A of 

the LRA and (b) this demonstrates compliance with the requirement in 

10 CFR 54.21(c)(2). The action requested in A/LAI No. 8, Item (3) is resolved.

• A/LAI #8, Item (4). In A/LAI #8, Item (4), the staff stated that 10 CFR 54.22 requires each 

license renewal applicant to submit any technical specification (TS) changes (and the 

justification for the changes) that are necessary to manage the effects of aging during the 

period of extended operation as part of its LRA. In this A/LAI, the staff recommended that, 

for those plant CLBs that include mandated inspection or analysis requirements for the 

RVI components either in the operating license for the facility or in the facility TS, the 

applicant perform a comparison of the mandated requirements with the recommendations 

in the MRP-227-A report. The staff stated that, if the mandated requirements differ from 
AGING MANAGEMENT REVIEW RESULTS

3-56

the recommended criteria in MRP-227-A report, the conditions in the applicable license 

conditions or TS requirements take precedence over the MRP recommendations and must 

be complied with. 

In response to this A/LAI, the applicant stated the CLB does not include any TS 

requirements that would need to be changed as a result of the implementation of the 

augmented I&E recommendations in the MRP-227-A report.

The staff reviewed Callaway Operating License No. NPF-30 and TS for operating license 

conditions or TS requirements that relate to aging management bases for the RVI 

components in the plant design. The staff did not note any specific operating license or 

TS requirements related to design or integrity of the Callaway RVI components. The staff 

also did not find any operating license or TS requirements for the Callaway that would 

need to be amended as a result of the applicant’s plans to implement the augmented 

inspection criteria in the MRP-227-A report or the ISIs that are mandated by 

10 CFR 50.55a and the ASME Code Section XI for those RVI components that are defined 

in the Callaway CLB as ASME Code Section XI, Examination Category B-N-3 core support 

structure components or B-N-2 components such as the clevis insert bolts. 

Based on this review, the staff finds that the applicant has addressed the request in 

A/LAI #8, Item (4) because the staff has confirmed that: (a) the CLB does not include any 

operating license conditions or TS requirements that relate to the design or structural 

integrity of the applicant’s RVI components and (b) the CLB does not include any 

operating license conditions or TS requirements that would need to be amended as a 

result of the applicant’s plans to implement the augmented inspection criteria in the 

MRP-227-A report. The action requested in A/LAI #8, Item (4) is resolved.

• A/LAI #8, Item (5). In A/LAI #8, Item (5), the staff stated that license renewal applicants 

are required by 10 CFR 54.21(c)(1) to identify all analyses in the CLB for their RVI

components that conform to the definition of a TLAA in 10 CFR 54.3. The staff stated that 

the MRP-227-A report does not specifically address the resolution of TLAAs that may 

apply to a PWR license renewal applicant’s RVI components. Thus, in A/LAI #8, Item (5), 

the staff recommended that PWR license renewal applicants that reference and will be 

implementing the recommendations in the MRP-227-A report should evaluate the CLB for 

their facilities to determine if they have any plant-specific TLAAs for the RVI components 

that need be addressed. If so, the staff recommended that the applicants submit the 

applicable TLAAs for NRC review along with the AMPs that will be used to implement the 

MRP-227-A report recommended activities for RVI components at their facilities.

In A/LAI #8, Item (5), the staff also stated that, for those CUF analyses on RVI 

components that are TLAAs, the applicant may use the PWR Vessel Internals Program as 

the basis for accepting these TLAAs in accordance with 10 CFR 54.21(c)(1)(iii) only if the 

RVI components within the scope of the CUF analyses are periodically inspected for 

fatigue-induced cracking in the components during the period of extended operation. The 

staff stated that the periodicity of the inspections of these components requires adequate 

justification to resolve the TLAA. Otherwise, staff recommended that the acceptance of 

these TLAAs shall be done in accordance with either 10 CFR 54.21(c)(1)(i) or (ii), or in 

accordance with 10 CFR 54.21(c)(1)(iii) using the applicant’s program that corresponds to 

GALL Report AMP X.M1, “Fatigue Monitoring.” The staff also stated that, to satisfy the 

evaluation requirements of ASME Code, Section III, Subsection NG-2160 and NG-3121, 

the existing fatigue CUF analyses shall include the effects of the RCS water environment.

The applicant stated that the only TLAAs for the Callaway RVI components are the metal 

fatigue TLAAs for the Callaway core support structure components. The applicant stated 
AGING MANAGEMENT REVIEW RESULTS

3-57

that these TLAAs are addressed in LRA Section 4.3.3 and are dispositioned in accordance 

with 10 CFR 54.21(c)(1)(iii). The applicant stated that it does not credit the PWR Vessel 

Internals Program as the basis for accepting the metal fatigue TLAAs in accordance with 

10 CFR 54.21(c)(1)(iii). The staff confirmed that LRA Section 4.3.3 does address the 

metal fatigue TLAA that is applicable to those RVI components at Callaway that are 

defined as ASME Code Section III core support structure components. The staff also 

confirmed that the applicant identifies that these TLAAs are acceptable in accordance with 

10 CFR 54.21(c)(1)(iii) and that the applicant will use the Fatigue Monitoring Program to 

manage the impacts of metal fatigue (cumulative fatigue damage) on the intended function 

of the RVI core support structure components during the period of extended operation. 

The staff evaluated the metal fatigue analyses for these components in SER Section 4.3.3. 

However, the staff also noted that the applicant’s response to A/LAI #8, Item (5) did not 

address how exposure to the RCS environment would be evaluated for impact on: (a) the 

CUF analyses for these components and (b) the applicant’s basis for accepting these 

TLAAs in accordance with the TLAA acceptance requirement in 10 CFR 54.21(c)(1)(iii).

By letter dated December 17, 2012, the staff issued RAI B2.1.6-4a, requesting, in part, 

that the applicant provide additional information and clarifications on how it would resolve 

the action item in A/LAI #8, Item (5). The staff identified this issue as Open Item B.2.1.6-1, 

Part (d).

By letter dated January 24, 2013 (ML13029A243 for the Cover Letter and ML13029A244 

for the enclosures containing the RAI response and associated LRA amendments for LRA 

Amendment No. 20), the applicant provided its response to RAI B2.1.6-4a proposing to 

address A/LAI #8, Item (5) in a future submittal of an inspection plan that would be 

submitted in accordance with LRA Commitment No. 4, as given in FSAR supplement 

Table A4-1. 

The staff noted that, in the applicant’s letter of April 26, 2013, the applicant amended the 

LRA to resolve the request in A/LAI #8, Item (5) by superseding the existing Commitment 

No. 4 with the following amended commitment:

Applicant/Licensee Action Item (A/LAI) #8 Item #5. Enhance the Fatigue Monitoring 

program to evaluate the effects of the reactor coolant system water environment on 

the reactor vessel internal components with existing fatigue CUF analyses to satisfy 

the evaluation requirements of ASME Code, Section Ill, Subsection NG-2160 and 

NG-3121.

Upon further review, the staff determined that the neither the FSAR supplement for the 

Fatigue Monitoring Program, as given in LRA FSAR supplement Section A2.1, “Fatigue 

Monitoring,” nor Commitment No. 31 on the Fatigue Monitoring Program in FSAR

Table A4-1 had been amended to include the stated enhancement. Therefore, the staff 

noted that it would need additional justifications on why FSAR supplement Section A2.1 

and Commitment No. 31 in FSAR supplement Table A4-1 had not been enhanced 

consistent with the commitment change in FSAR supplement Table A4-1, Commitment 

No. 4. The staff also noted that it would need additional clarification on how the program 

elements of the Fatigue Monitoring Program would be adjusted to evaluate (account for) 

the effects of the reactor coolant environment on the acceptability of the CUF analyses for 

the applicable RVI components. 

By letter dated September 20, 2013, the staff issued RAI B2.1.6-4c, requesting that the 

applicant provide its basis why Commitment No. 31 in FSAR Table A4-1 and FSAR

Section A2.1, “Fatigue Monitoring,” had also not been amended to include this 
AGING MANAGEMENT REVIEW RESULTS

3-58

enhancement. The staff also asked the applicant to clarify and justify how the program 

elements of the Fatigue Monitoring Program will be adjusted to evaluate the effects of the 

reactor environment on the CUF analyses for the applicable RVI components. 

The applicant responded to RAI B2.1.6-4c in a letter dated October 17, 2013. In its 

response, the applicant stated that LRA Table A4-1 Commitment No. 4 was revised to 

delete the A/LAI #8 Item #5 commitment on effects of the reactor water environment on 

the reactor vessel internals locations with fatigue usage calculations and that, instead, the 

commitment provisions have been incorporated into LRA Table A4-1 Commitment No. 31. 

The applicant also stated that the implementation of the commitment is described in LRA 

Appendix A2.1, LRA Section A3.2.3, and LRA Section B3.1. The applicant stated that it

will recalculate each of the reactor vessel internals CUFs identified in LRA Table 4.3-5, 

Reactor Internals Design Basis Fatigue Analysis Results, to consider the reactor water 

environmental effect factors (Fen factors) using the methods of analysis in 

NUREG/CR-5704 or NUREG/CR-6909, and that consistent with the corrective actions 

specified in its Fatigue Monitoring program (LRA Section B3.1), corrective actions include 

fatigue reanalysis, repair, or replacement of the affected components prior to the adjusted 

usage factor “Uen” reaching a value of 1.0. The applicant stated that LRA AMP B3.1, 

“Fatigue Monitoring Program,” Commitment Nos. 4 and 31 in FSAR supplement Table 

A4-1, and FSAR supplement Sections A2.1 and A3.2.3 have been amended as shown in 

Enclosure 2 of LRA Amendment 27 to consider the effects of the reactor water 

environment on the reactor vessel internals locations with fatigue usage calculations.

The staff reviewed the applicant’s response to RAI B2.1.6-4c, as given in its letter of 

October 17, 2013, and determined that in its amendment of Commitment No. 31, the 

applicant had committed to performing environmental adjustments of the CUF analyses for 

the applicable RVI components that had been evaluated in accordance with a fatigue 

analysis and to using the Fatigue Monitoring Program as the basis for managing 

environmentally assisted fatigue in those components. The staff noted that the amended 

basis in this letter was consistent with the staff’s position in A/LAI #8, Item (5) because the 

applicant has committed to assessing the CUF of these components for environmental Fen

adjustments and using the Fatigue Monitoring Program as the basis for monitoring against 

those assessments, which is consistent with the staff’s program element bases in GALL 

Report AMP X.M1, “Fatigue Monitoring Program.” The staff also confirmed that the 

applicant has made the appropriate changes to LRA Commitment Nos. 4 and 31, LRA 

AMP B3.1, and FSAR supplement Sections A2.1 and A3.2.3, to ensure that the Fatigue 

Monitoring Program will be the basis for ensuring the CUF calculations for the RVI 

components will be evaluated for environmental effects. On this basis, the staff concludes 

that the applicant has addressed the action requested in A/LAI #8, Item (5), because the 

applicant has sufficiently clarified how the Fatigue Monitoring Program will be used to 

manage environmentally assisted fatigue in these RVI components and has demonstrated 

that its use of the Fatigue Monitoring Program will be consistent with the staff’s

recommendations for managing environmentally assisted fatigue in GALL Report 

AMP X.M1. A/LAI #8, Item (5) and RAI B2.1.6-4c are resolved, and Open Item B2.1.6-1, 

Part (d) is closed.

On the basis of this review, the staff finds that the applicant has resolved the staff’s RAIs related 

to the applicable A/LAIs on the MRP-227-A methodology, including those in RAI Nos. B2.1.6-4, 

B2.1.6-4a, B2.1.6-4b, B2.1.6-4c, and B2.1.6-4d. Open Item B2.1.6-1, Parts (a) through (d) are 

closed.
AGING MANAGEMENT REVIEW RESULTS

3-59

Operating Experience. LRA Section B2.1.6 summarizes operating experience related to the 

PWR Vessel Internals Program. The applicant stated that it replaced the Alloy X-750 CRGT 

support pins with strain hardened 316 stainless steel pins during RFO 13 (spring 2004) to 

reduce the susceptibility for SCC in the support pins. The applicant stated that this replacement 

was based on industry operating experience. The applicant noted that no cracked Alloy X-750 

support pins were discovered during the replacement process. However, the staff noted that, in 

LRA Table 3.1.2-1, the applicant identified that it would manage cracking of its stainless steel 

CRGT support pins using its ASME Section XI Inservice Inspection, Subsection IWB, IWC, and 

IWD Program. The staff noted that this basis would be acceptable because it would address 

the inspection basis that the staff recommended in A/LAI #5 on the MRP-227-A methodology.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation, other than possibly the applicant’s bases for resolving the generic 

operating experience with clevis insert bolt cracking, which had occurred in another 

U.S. Westinghouse-designed reactor in 2010. The following paragraphs address the applicant’s 

basis for evaluating the applicability of the generic clevis insert bolt operating experience on the 

applicant’s bases for inspecting the components in accordance with the applicable ASME 

Section XI ISI requirements for Examination Category B-N-2 components.

By letter dated February 12, 2014, the staff issued RAI No. 3.1.2.1-6, Parts (a) and (b), to the 

applicant to address the clevis insert bolt operating experience on the program element criteria 

for the PWR Vessel Internals AMP. In RAI 3.1.2.1-6, Part (a), the staff asked the applicant to 

describe the configuration of clevis insert assembly design at Callaway, including the number of 

bolts used in the assemblies. The staff also asked the applicant to specify the material of 

fabrication, including any applicable heat treatments, that were used for the design of the clevis 

insert bolts at Callaway. In RAI 3.1.2.1-6, Part (b), the staff asked the applicant to discuss and 

justify whether the operating experience associated with cracking of the clevis insert bolts is 

applicable to clevis insert assembly designs at Callaway.

The applicant responded to RAI 3.1.2.1-6, Parts (a) and (b), in a letter dated April 3, 2014 (as 

given in ML14093A781 for the Cover Letter, Non-Proprietary ML14093A780 for Westinghouse’s

associated nonproprietary response bases to the RAI). The applicant indicated that part of the 

response was prepared for Callaway by Westinghouse, and included some proprietary 

information that Westinghouse had identified as trade secrets and would need to be protected in 

accordance with the requirements in 10 CFR 2.390 from disclosure to members of the general 

public. The applicant therefore submitted both proprietary and nonproprietary versions of the 

responses to RAI 3.1.2.1-6, Parts (a) and (b), in which only a very limited amount of information 

in the proprietary version of the response had been marked for protection from public 

disclosure.

In the nonproprietary response, Westinghouse clarified that there are some similiarities between 

the material used in the design of the clevis insert bolts at Callaway and those at the plant with 

the operating experience. Westinghouse stated that although there is some potential for 

cracking to occur in clevis insert bolts of both facilities, if cracking did lead to a failure of a clevis 

insert bolt, the bolt would be held in place by the locking bar in the design. Westinghouse also 

stated that, if a clevis insert bolt head was to separate from its shaft, the locking bar could, over 
AGING MANAGEMENT REVIEW RESULTS

3-60

time, wear and separate, causing the clevis insert bolt head to become loose in the counterbore 

recess. However, Westinghouse explained that the as-built radial gaps measured between the 

core barrel radial keys and the inserts are all less than the height of the clevis insert bolt heads, 

and therefore, the clevis insert bolt heads would remain captured, unless over a long period of 

time, potential wear of the bolt heads were to reduce the height of the heads by this amount. 

Westinghouse explained, however, that the bolt head wear is expected to be small because the 

bolt material is much harder than material used to fabricate the clevis insert assembly inserts 

and radial keys. Westinghouse therefore concluded that any effects of potential loose parts 

would be captured or would have a minimal impact on the lower internals design. 

In its response to RAI 3.1.2.1-6, Parts (a) and (b), the applicant also stated that it performs VT-3 

inspections on 100 percent of the accessible clevis insert assembly components in accordance 

with ASME Code Section XI, Examination Category B-N-2 requirements, with the most recent 

inspection performed during Refueling Outage No. 19 in spring 2013. The applicant stated that 

the examinations inspected 100 percent of the clevis insert bolt heads and locking bars and that 

the inspections did not identify any evidence of degradation or damage in the clevis insert bolts 

or locking bars. The applicant stated that, based on these considerations and results of the 

inspections during Refueling Outage No. 19, the PWR Vessel Internals Program protocols for 

applying the ASME Code ISI inspections of the clevis insert assemblies and their bolts do not 

have to be augmented for the purpose of managing cracking or loss of material due to wear in 

the clevis insert bolts for the facility. 

The staff noted that the information in Westinghouse’s nonproprietary response to 

RAI 3.1.2.1--6, Parts (a) and (b), when coupled with the applicant’s response to the RAI, was 

sufficient to make a determination on whether the ISI interval for performing ASME Code 

Section XI visual examinations of the clevis insert bolts would need to be augmented to a 

frequency more frequent than the 10-year ISI interval required by the Code. The staff also 

noted that, based on Westinghouse’s assessment, the cracking in the clevis insert bolts at the 

reference plant was detected using the 10-year ASME Code Section XI visual VT-3 methods 

before the clevis insert bolts could fail and induce a loss of the intended structural integrity 

function of the clevis insert assemblies or other RVI components in the lower internal assembly 

at the plant, even with the small amount of wear that was detected in the locking bars in the 

clevis insert bolt design. The staff also noted the operating experience and apparent cause 

assessment for the reference plant with the clevis insert bolt experience demonstrated that the 

frequency of performing the ASME Code Section XI visual examinations will be capable of 

detecting crack-induced clevis insert bolt failures prior to any loss of function in a clevis insert 

assembly or the generation of a postulated loose part with the potential to impact the intended 

function of other RVI components in the lower internals assembly.

Therefore, based on the Westinghouse assessment provided in the response to RAI 3.1.2.1-6, 

and the lack of any cracking or wear detected in the clevis insert assemblies at Callaway to 

date, the staff noted that the 10-year ASME Code Section XI visual VT-3 inspections performed 

on the clevis insert assemblies and their bolts will be capable of detecting any cracking or loss 

of material due to wear in the clevis insert bolts prior to generation of a loose part that could 

potentially impact the intended functions of the clevis insert assemblies or other internals in the 

RVI lower internals assembly. Based on this review, the staff finds that the applicant has 

addressed the impact of the generic operating experience on the ability of the ASME visual 

examination methods to detect and manage potential cracking and loss of material due to wear 

in the clevis insert assemblies and clevis insert bolts at Callaway because the applicant has 

provided a sufficient basis for concluding that the existing ASME inspections will be capable of 

detecting the postulated age-related effects prior to any postulated loss of the intended 
AGING MANAGEMENT REVIEW RESULTS

3-61

structural integrity function of the clevis insert assemblies or other components in the lower 

internals assembly. RAI 3.1.2.1-6, Parts (a) and (b), are resolved.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M16A was evaluated.

FSAR Supplement. LRA Section A1.6, as amended by letter dated April 25, 2012, provides the 

FSAR supplement for the PWR Vessel Internals Program. The staff reviewed this FSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff confirmed that the applicant’s FSAR supplement 

summary description provided an acceptable summary of the program with regard to: 

(a) referencing the MRP-227-A report as being within the scope of the applicant’s PWR Vessel 

Internals Program, (b) identifying the aging effects that will be managed in accordance with the 

applicant’s plans to implement the program, (c) identifying that the PWR Vessel Internals 

Program is a new AMP that will be implemented within 24 months of EPRI’s issuance of the 

MRP-227-A reports (i.e., by January 9, 2014), and (d) identifying that the applicant’s review of 

relevant generic industry and plant-specific operating experience will be factored into the 

development and implementation of the program.

The staff also noted that the applicant committed (Commitment No. 4) to implement the new 

PWR Vessel Internals Program as described in LRA Section B2.1.6 within 24 months after the 

issuance of MRP-227-A. The staff noted that Commitment No. 4 was captured in Table A4-1 of 

the applicant’s FSAR supplement. However, the staff also noted that, in the applicant’s 

response to RAI B2.1.6-4, dated October 24, 2012, the applicant made the following statement 

with respect to its plans to provide the NRC staff with the applicant’s responses to the A/LAIs on 

the MRP-227-A methodology:

Callaway will provide specific responses to the Applicant/Licensee Action Items (A/LAIs) 

identified in the December 16, 2011, NRC Safety Evaluation on the MRP-227-A 

methodology in LRA Appendix C. The LRA Appendix C supplement for the NRC Safety 

Evaluation A/LAIs will be provided consistent with the LRA Table A4-1 item #4 commitment 

to implement the PWR Vessel Internals [P]rogram as described in LRA Section B2.1.6 within 

24 months after the issuance of MRP-227-A. LRA Table A4-1 item #4 also includes the 

Callaway [RVIs] inspection plan noted in part (b) of A/LAI item 8 of the NRC Safety 

Evaluation on the MRP-227-A methodology. The Callaway [RVIs] inspection plan will be 

provided within 24 months after the issuance of MRP-227-A. 

By letter dated December 17, 2012, the staff issued RAI B2.1.6-4a, requesting that the applicant 

provide the basis for not modifying Commitment No. 4 in a manner that is consistent with the 

bases for this commitment as provided in its response to RAI B2.1.6-4 and that would address 

the activities or aspects of the applicant’s PWR Vessel Internals Program related to its 

responses to A/LAI Nos. 1, 5, 7, and 8 Item (5). This is identified as Open Item B2.1.6-1, 

Part (e). 

As has been discussed in the “Review of License Renewal Applicant Action Items” section of 

this evaluation, the staff noted that the applicant resolved the requests in A/LAI Nos. 1, 5, 7, and 

8, Item (5) in the following Ameren correspondence letters to the staff:

• Resolved the issues in A/LAI #1 and demonstrated that the methodology in 

TR MRP--227-A is applicable to the design of the RVI components at Callaway in 
AGING MANAGEMENT REVIEW RESULTS

3-62

Ameren Missouri Letter No. ULNRC-05950, dated January 24, 2013, as 

supplemented with information provided in Ameren Missouri Letter Nos. 

ULNRC-06072, dated January 16, 2014; ULNRC-06079, dated February 5, 2014; 

ULNRC-06080, dated February 14, 2014; ULNRC-06090, dated March 13, 2014; 

ULNRC-06106, dated March 28, 2014; and ULNRC-06117, dated April 23, 2013.

• Resolved the issue in A/LAI #5 and demonstrated that augmented aging 

management is not needed for the design of the Callaway hold-down spring in 

Ameren Missouri Letter No. ULNRC-05950, dated January 24, 2013.

• Resolved the issue in A/LAI #7 and demonstrated that supplemental evaluations 

would not need to be performed for those components that are made from CASS, 

martensitic stainless steel or precipitation-hardened stainless steels in Ameren 

Missouri Letter No. ULNRC-06072, dated January 16, 2014.

• Resolved the issue in A/LAI #8, Subitem 5, and demonstrated that the RVI 

components with fatigue analyses would be adequately managed by the Fatigue 

Monitoring Program, including bases for managing the impacts of environmental 

effects on the fatigue analyses, in Ameren Missouri Letter No. ULNRC-05950, dated 

January 24, 2013, as supplemented by the response in Ameren Letter 

No. ULNRC-06050, dated October 17, 2013.

The staff noted that in the applicant’s letter of December 20, 2013, the applicant had 

implemented and closed Commitment No. 4. Based on this review, the staff finds that the 

applicant has provided an acceptable basis for resolving those A/LAIs that were issued 

regarding the applicant’s basis for implementing the augmented inspection and evaluation 

activities recommended in the MRP-227-A, such that the applicant would not need to submit an 

RVI inspection plan to the staff for approval in accordance with the request in A/LAI No. 8, Item 

(2) or LRA Commitment No. 4. 

The staff also noted that the FSAR supplement Table A4-1 included the following additional 

LRA Commitments for implementing the PWR Vessel Internals Program that were included in 

the LRA subsequent to the resolution and closure of LRA Commitment No. 4 in the applicant’s 

letter of December 20, 2013 (Ameren Missouri Letter No. ULNRC-06057): 

• LRA Commitment No. 43, as proposed in the applicant’s letter of January 16, 2014, in 

which the applicant committed to updating the procedures for the program to incorporate 

the MRP’s new criteria for demonstrating that future operations of the plant will be within 

the bounds of the assumptions used for the methodology in the MRP-227-A report.

• LRA Commitment No. 44, as proposed in the applicant’s letter of February 5, 2014, in 

which the applicant had committed to the implementation of specific actions or activities 

in order to resolve the staff’s requests in A/LAI #1. 

The staff noted that the applicant had implemented and closed Commitment No. 43 in the 

applicant’s letter of January 16, 2014, and implemented and closed Commitment No. 44 in the 

applicant’s letter of April 23, 2014. 

Based on this review, the staff finds that the information in the FSAR supplement, as amended 

by letters dated January 24, 2013, October 17, 2013, December 20, 2013, January 16, 2014, 

February 5, 2014, February 14, 2014, March 13, 2014, March 28, 2014, and April 23, 2013, is 

an adequate summary description of the program. The requests in RAI B2.1.6-4a are resolved 

and Open Item B2.1.6-1, Part (e) is closed.
AGING MANAGEMENT REVIEW RESULTS

3-63

Conclusion. On the basis of its audit and review of the applicant’s PWR Vessel Internals 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent with those recommended in GALL Report 

AMP XI.M16A. The staff also concludes that the applicant has appropriately augmented the 

program based on the applicant’s bases for resolving those A/LAIs that were issued in the 

augmented inspection and evaluation methodology in MRP-227-A and plant-specific 

considerations that have been evaluated in this SER section and resulted in an adjustment of 

the MRP’s recommended program in accordance with the actions requested in A/LAI #2. 

Based on these considerations, the staff also concludes that the applicant has demonstrated 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Flow-Accelerated Corrosion 

Summary of Technical Information in the Application. LRA Section B2.1.7 describes the 

existing Flow-Accelerated Corrosion Program as consistent with GALL Report AMP XI.M17, 

“Flow-Accelerated Corrosion.” The program manages wall thinning of carbon or low alloy steel 

piping components in single-phase and two-phase, high energy fluids. The LRA states that the 

program implements the guidance of EPRI NSAC-202L, Revision 3, “Recommendations for an 

Effective Flow-Accelerated Corrosion Program.” The LRA also states that the program predicts 

critical locations using a computer code (CHECWORKSTM), identifies wall thinning with baseline 

inspections, and performs followup inspections using ultrasonic, visual or other approved testing 

techniques. The LRA further states that in conjunction with CHECWORKSTM, the program also 

uses a computer code (FAC Manager Web Edition) to calculate component wear rates for 

scheduling future inspections, or for determining the need to take corrective actions, such as 

repair, replacement, or reevaluation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M17. 

For the “scope of program,” “detection of aging effects,” and “acceptance criteria” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs as discussed below.

The “scope of program” program element in GALL Report AMP XI.M17 recommends that the 

program includes procedures and administrative controls to maintain the structural integrity of all 

carbon steel lines containing high-energy fluids. During its audit, the staff noted that Callaway 

Report No. 4501-01, “Callaway Nuclear Plant FAC System Susceptibility Evaluation,” excluded 

the chemical and volume control (CVC) system from the scope of the Flow-Accelerated 

Corrosion Program because the system components are constructed from non-susceptible 

materials. However, LRA Table 3.3.2-10, “Auxiliary Systems - Summary of Aging Management 

Evaluation - Chemical and Volume Control System,” includes carbon steel piping that is being 

managed for wall thinning by the Flow-Accelerated Corrosion Program. Based on this, it was 

not clear to the staff whether the CVC system has susceptible material that was not evaluated in 

Callaway’s FAC system susceptibility evaluation report or whether other systems have been 
AGING MANAGEMENT REVIEW RESULTS

3-64

excluded, which also contain components made from susceptible materials. By letter dated 

July 18, 2012, the staff issued RAI B2.1.7-1, requesting that the applicant clarify this apparent 

discrepancy. 

In its response dated August 21, 2012, the applicant stated that LRA Table 3.3.2-10 incorrectly 

included carbon steel piping in the CVC system as being managed by the Flow-Accelerated 

Corrosion Program and that the site’s FAC system susceptibility evaluation included these 

carbon steel components within the auxiliary steam system. The applicant also stated that 

during its review to determine if there were other similar errors in the LRA, it identified one 

additional occurrence and consequently revised the appropriate tables in LRA Amendment 7 to

remove the two erroneous items. The applicant further stated that these lines were excluded 

from the FAC program because they operate less than two percent of the time, not because 

their material is not susceptible to FAC. The staff finds the applicant’s response acceptable 

because the applicant amended the LRA to remove the incorrect information and explained that 

the system susceptibility evaluation report included the subject carbon steel components within 

the auxiliary steam system. The staff noted that LRA Table 2.2-1, “Callaway Plant Scoping 

Results,” includes the auxiliary steam system with the main steam supply system and that LRA 

Section 3.4.2.1.2, “Main Steam Supply System,” credits the Flow-Accelerated Corrosion 

Program for managing wall thinning in carbon steel piping. The staff’s concern described in RAI 

RAI B2.1.7-1 is resolved.

The “scope of program” program element in GALL Report AMP XI.M17 states that the program 

is described by EPRI guideline NSAC-202L. EPRI NSAC-202L states that the program 

addresses wall thinning caused by flow-accelerated corrosion (FAC) and that it does not 

address other thinning mechanisms, such as cavitation and erosive wear. During its review of 

program’s operating experience report, the staff identified several Callaway Action Requests 

(CARs) indicating that the program addresses wall thinning due to erosion mechanisms. Based 

on this, the staff had questions regarding the scope of the program. By letter dated 

July 18, 2012, the staff issued RAI B2.1.7-4 requesting the applicant to clarify whether the 

program addressed mechanisms other than FAC or whether components that experienced wall 

thinning because of erosion mechanisms are being managed by another program. In its 

response dated August 21, 2012, the applicant stated that its Flow-Accelerated Corrosion 

Program does not manage aging mechanisms other than FAC and that none of the CARs cited 

in the RAI identified wall thinning due to mechanisms other than FAC in components within the 

scope of license renewal. In addition, the applicant discussed CAR 200703776, which 

addressed erosion/corrosion in an essential service water pipe, and stated that this component 

is monitored for erosion mechanisms by the Open-Cycle Cooling Water System Program.

In its review of the applicant’s response, the staff noted that all of the CARs cited in the RAI 

were initially cited by the applicant in its operating experience review for this AMP. In addition, 

since the operating experience review report comprises one of the records documenting 

compliance with 10 CFR Part 54, the portions stating that the Flow-Accelerated Corrosion 

Program manages loss of material due to erosion in a raw water system appears to be 

incorrect. In a separate but related effort, the staff noted that in its response to IE 

Bulletin 87-01, “Thinning of Pipe Walls in Nuclear Power Plants,” the applicant stated that its 

erosion and corrosion program, which was the predecessor of the Flow-Accelerated Corrosion 

Program, included inspections of stainless steel pipe for erosion due to cavitation. To address 

these concerns, by letter dated October 12, 2012, the staff issued RAI B2.1.7-4a, requesting the 

applicant to address the apparent incorrect information in the operating experience review 

documentation and to discuss the CLB associated with the erosion/corrosion program and how 

it correlates to the Flow-Accelerated Corrosion Program. 
AGING MANAGEMENT REVIEW RESULTS

3-65

In its response dated November 8, 2012, the applicant stated that CAR 200608992 and 

CAR 201004190 incorrectly assigned the Flow-Accelerated Corrosion Program as the AMP 

relevant to the condition prompting the action requests and that it had revised the operating 

experience review documentation for these two CARs to correct this error. In addition, the 

applicant explained that although its original response to IE Bulletin 87-01 included raw water 

components subject to wall thinning due to mechanisms other than FAC, it moved all of these 

inspections to the new program in response to NRC Generic Letter (GL) 89-13, “Service Water 

System Problems Affecting Safety-Related Equipment.” The applicant stated that it moved the 

inspections for wall thinning in raw water systems to the GL 89-13 program because the 

operating conditions such as temperature and oxygen levels of raw water systems are not 

consistent with those causing FAC. The staff finds the response acceptable because the 

applicant corrected its operating experience documentation to indicate that the 

Flow-Accelerated Corrosion Program does not manage aging mechanisms other than FAC. In 

addition, the applicant clarified that the inspections for wall thinning in raw water systems that it 

initially included in response to IE Bulletin 87-01 are now part of its GL 89-13 program, which it 

implements through the Open-Cycle Cooling Water System Program. The staff’s concerns 

described in RAIs B2.1.7-4 and B2.1.7-4a are resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M17 states that the 

program uses ultrasonic or radiographic testing to detect wall thinning. The LRA states that the 

Flow-Accelerated Corrosion Program uses ultrasonic, visual or other approved techniques 

during baseline and followup inspections. During its review, the staff could not find 

documentation describing how the applicant uses visual inspections to detect wall thinning or 

whether visual inspections are used in lieu of volumetric techniques to detect wall thinning. 

By letter dated July 18, 2012, the staff issued RAI B2.1.7-2 requesting the applicant to clarify 

how visual inspections will be used to detect wall thinning and whether visual inspections will be 

used in lieu of volumetric examinations. 

In its response dated August 21, 2012, the applicant stated that visual examinations may be 

used for very large diameter piping and for components such as valves that are not suitable for 

ultrasonic examination because of their shape and thickness. The applicant also stated that 

visual examinations provide qualitative indications of FAC and are not used to determine wall 

thickness. The staff notes that NSAC-202L discusses the use of visual observations with 

followup ultrasonic examinations of areas where damage is observed or suspected. The staff 

finds the applicant’s response acceptable because the applicant clarified how visual 

examinations are used and that visual examinations do not take the place of volumetric 

examinations for determining wall thickness. The staff’s concern described in RAI B2.1.7-2 is 

resolved.

The “acceptance criteria” program element in GALL Report AMP XI.M17 states that inspection 

results are input for a predictive code to calculate the remaining number of operating cycles 

before a component reaches its minimum allowable wall thickness. Industry guidance, EPRI 

NSAC 202L, Revision 2, “Recommendations for an Effective Flow-Accelerated Corrosion 

Program,” states that a minimum safety factor should never be less than 1.1 to account for wear 

rate inaccuracies when calculating the remaining service life of a component. Although the 

program’s implementing procedure, EDP-ZZ-01115, “Flow-Accelerated Corrosion of Piping and 

Components Predictive Performance Manual,” specifies a safety factor of 1.1 in calculating an 

“inspection index,” LRA Section B2.1.7 states that FAC Manager Web Edition is utilized to 

calculate wear, wear rates and the next scheduled inspection. During its review of onsite 

documentation related to FAC Manager Web Edition, the staff could not verify that the 

applicant’s program used a minimum safety factor of 1.1 in calculating the next scheduled 
AGING MANAGEMENT REVIEW RESULTS

3-66

inspection. By letter dated July 18, 2012, the staff issued RAI B2.1.7-3 requesting the applicant 

to confirm that calculations use a minimum safety factor of 1.1 to determine the remaining 

service life or to schedule the next inspection. 

In its response dated August 21, 2012, the applicant stated that the user defines the safety 

factor for FAC Manager Web Edition, and it uses a 1.1 safety factor in the calculations of 

remaining service life. The applicant also stated that it initiated a corrective action request to 

revise procedure EDP-ZZ-01115, to clarify that a safety factor of no less than 1.1 is to be used 

to calculate remaining service life. The staff finds the applicant’s response acceptable because 

the applicant confirmed that it uses a safety factor of 1.1 to schedule a component’s next 

inspection, which is consistent with the guidance given in NSAC-202L. In addition, the applicant 

initiated corrective actions to clarify this requirement in its implementing procedure. The staff’s 

concern described in RAI B2.1.7-3 is resolved.

The “acceptance criteria” program element in GALL Report AMP XI.M17 states that if 

calculations indicate that an area will reach the minimum allowed wall thickness before the next 

scheduled outage, corrective action should be considered. During its review of plant-specific 

operating experience, the staff identified CAR 200403322, which stated that “this calculation 

decreased the design minimum thickness required by utilizing the measured ultimate tensile 

stress listed in the certified materials test report [(CMTR)].” In justifying the use of CMTR data 

during the staff’s audit, the applicant’s personnel provided engineering design guide, ME 013, 

“Pipewall Thickness,” which states, “the use of CMTR data [in] lieu of using the published 

allowable stress for the material is permissible to further refine the minimum wall thickness 

analyses.” The design guide defines the minimum wall thickness as the thickness that will meet 

the applicable code requirements for a given application and states that this process applies to 

ASME Code Class 2 and Class 3 and to American National Standards Institute (ANSI) B31.1 

piping. Based on this, the staff questioned the applicant’s acceptance criteria for meeting 

ASME Code minimum allowable wall thickness, since the ASME Code does not address the 

use of CMTR data for this purpose. By letter dated July 18, 2012, the staff issued RAI B2.1.7-5 

requesting the applicant to provide information regarding its use of CMTR data to reduce the 

ASME Code-required minimum wall thickness during the period of extended operation. 

In its response dated August 21, 2012, the applicant stated that the bases for determining the 

allowable stress limits are defined in ASME Code Section III, Appendix III, Article 3000, and 

would be applicable to situations where acceptance limits must be established for a material 

that is not listed in the stress tables. Based on this concept, the applicant stated that CMTR 

data can be applied when the documented material strength is greater than the minimum 

required strength for that particular standard and that use of CMTR data does not result in any 

reduction of conservatism. The applicant also stated that engineering evaluations performed on 

inservice components for reduced thickness or unanticipated loads are beyond the scope of 

ASME Code Section III and that such evaluations should be based on engineering judgment. 

In its review of the applicant’s response, the staff noted that in addition to the use of CMTR data 

for calculating the minimum wall thickness, engineering design guide ME-013 also specifies that 

the ASME Code allowable stresses may be increased by a factor of 1.1. The staff notes that 

this would result in a less conservative wall thickness, and there did not appear to be any 

restriction in combining the use of CMTR data with the additional stress increase. By letter 

dated October 12, 2012, the staff issued RAI B2.1.7-5a requesting the applicant to further clarify 

its use of CMTR data and to also address the apparent use of the 1.1 stress increase factor with 

respect to meeting the ASME Code requirements. 
AGING MANAGEMENT REVIEW RESULTS

3-67

In its response dated November 8, 2012, the applicant stated that it had revised ME-013 to limit 

its applicability to operability determinations and evaluations of reduced wall thickness due to 

corrosion and erosion to support continued plant operation until repairs could be implemented. 

In addition, the applicant supplemented its response by letter dated December 20, 2013, and 

clarified that ME-013 is not used for the design of piping, piping systems, or components. The 

staff finds the response acceptable because the applicant clarified the applicability of ME-013 to 

ensure that current licensing bases regarding ASME Code minimum allowable wall thicknesses 

will be maintained during the period of extended operation. The staff’s concerns described in 

RAI B2.1.7-5 and B2.1.7-5a are resolved.

Based on its audit of the applicant’s Flow-Accelerated Corrosion Program and review of the 

applicant’s responses to RAIs B2.1.7-1, B2.1.7-2, B2.1.7-3, B2.1.7-4, B2.1.7-4a, B2.1.7-5, and 

B2.1.7-5a, the staff finds that program elements one through six for which the applicant claimed 

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

GALL Report AMP XI.M17.

Operating Experience. LRA Section B2.1.7 summarizes operating experience related to the 

Flow-Accelerated Corrosion Program. The LRA discussed the 1999 event for the rupture of a 

6-inch drain line from a moisture separator reheater drain tank to high pressure feedwater 

heater. The applicant stated that, based on the small predicted wear rate from 

CHECWORKSTM, the component was scheduled to be inspected during the next RFO. The 

applicant also stated that corrective actions for this event included the immediate inspections of 

40 locations with similar geometry and fluid conditions, with no similar problem being identified. 

The staff noted that this event is cited in the GALL Report AMP XI.M17 as operating experience 

for this AMP. In addition, the LRA discussed the identification in 2001 of unexpected wall 

thinning in feedwater piping, which required expansion of the inspection scope and extensive 

replacement of the piping. According to the applicant, a personnel error caused these locations 

to not be modeled in CHECWORKSTM. The staff noted that the associated CAR 200102270, 

was upgraded to a significance level 1, which required a formal root cause and extensive 

corrective actions 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. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI, as 

discussed below.

The Callaway operating experience report, CAR 200500411, describes the failure of a flow 

venturi component due to FAC, which resulted in the blockage of downstream equipment. The 

flow meter’s flow tube separated from its venturi throat and migrated down the pipe, blocking the 

minimum recirculation flow line. The applicant had inspected the spool piece containing the flow 

venturi in 2004 and had projected that it would last more than 50 years; however, the 

configuration of the flow element does not allow it to be inspected from the outside of the pipe 

using UT methods. The staff noted that this operating experience was unique because normal 

inspections cannot monitor the loss of material for the internal component, and failure of the flow 

venuri resulted in macrofouling, which is not an aging mechanism that is associated with the 

Flow-Accelerated Corrosion Program. Since this plant-specific operating experience is not 

bounded by the industry experience for which the GALL Report AMP XI.M17 was evaluated, by 
AGING MANAGEMENT REVIEW RESULTS

3-68

letter dated July 18, 2012, the staff issued RAI B2.1.7-6 requesting the applicant to address 

whether this aging mechanism needs to be managed and, if so, how it intends to manage it and 

through which AMP. 

In its response dated August 21, 2012, the applicant stated that it replaced the flow elements in 

both heater drain lines with an all stainless steel design and that the extent of condition 

identified five other locations with similarly designed flow elements. The applicant also stated 

that its corrective actions taken in response to CAR 200500411 are adequate to prevent failure 

of the flow elements and that the components identified during the extent of condition are not 

within the scope of license renewal. In its review of the response, the staff noted that the 

applicant issued an industry-wide operating-experience report in 2005 documenting the 

unexpected flow element failure. The staff finds the response acceptable because the 

applicant’s corrective actions eliminated the concern for managing this plant-specific operating 

experience in all in-scope components. The staff’s concern described in RAI B2.1.7-6 is 

resolved.

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

RAI B2.1.7-6, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective action. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M17 was 

evaluated.

FSAR Supplement. LRA Section A1.7 provides the FSAR supplement for the Flow-Accelerated 

Corrosion Program. The staff reviewed this FSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

finds that the information in the FSAR supplement is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s Flow-Accelerated Corrosion 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report 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 FSAR 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 Steam Generators 

Summary of Technical Information in the Application. LRA Section B2.1.9, as amended by 

letter dated October 24, 2012, describes the existing Steam Generators Program as consistent 

with GALL Report AMP XI.M19, “Steam Generators.” The LRA states that the Steam 

Generators Program manages cracking, loss of material, wall thinning, and loss of heat transfer

of the steam generators; and that this program is applicable to the steam generator tubes, 

plugs, sleeves, and secondary side steam generator internal components. The LRA also states 

that aging is managed through assessment of potential degradation mechanisms, inspections, 

tube integrity assessments, plugging and repairs, primary to secondary leakage monitoring, 

maintenance of secondary side component integrity, primary side and secondary side water 

chemistry, and foreign material exclusion. The LRA further states that Callaway’s procedural 

guidance implements the performance criteria for tube integrity, condition monitoring 
AGING MANAGEMENT REVIEW RESULTS

3-69

requirements, inspection scope and frequency, acceptance criteria for the plugging or repairs of 

flawed tubes, acceptable tube repair methods, leakage monitoring requirements, operational 

leakage, and accident induced leakage requirements of applicant’s TSs.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M19. For the “preventive 

actions” program element, the staff determined the need for additional information, which 

resulted in the issuance of RAIs as discussed below.

The “preventive actions” program element in GALL Report AMP XI.M19 recommends 

preventive and mitigative actions for addressing degradation. Preventive and mitigative 

measures that are part of GALL Report AMP XI.M19 include foreign material exclusion 

programs and other primary and secondary side maintenance activities. The program should 

include foreign material exclusion as a means to inhibit wear degradation and secondary side 

maintenance activities, such as sludge lancing, for removing deposits that may contribute to 

degradation. Primary side preventive maintenance activities include replacing plugs made with 

corrosion susceptible materials with more corrosion resistant materials and preventively 

plugging tubes susceptible to degradation. Guidance on foreign material exclusion is provided 

in NEI 97-06, Revision 3, “Steam Generator Program Guidelines.” Guidance on maintenance of 

secondary side integrity is provided in the EPRI document “Steam Generator Integrity 

Assessment Guidelines.” During its audit, the staff found that the applicant’s Steam Generators 

Program had several administrative inconsistencies when compared to the documents

referenced by GALL Report AMP XI.M19. By letter dated July 5, 2012, the staff issued 

RAIs B2.1.9-1 through B2.1.9-6 requesting the applicant to address these inconsistencies. The 

staff’s evaluation of the applicant responses to RAIs B2.1.9-1 through B2.1.9-6 is provided 

below. 

The staff noted that NEI 97-06, Revision 3, was to be implemented by September 1, 2011. The 

TS for steam generator maintenance services (S-1032) was used for the RFO 18 steam 

generator tube inspections (which commenced after October 15, 2011). The staff noted that 

document S-1032, “Technical Specification for Steam Generator Maintenance Services,” 

references NEI 97-06, Revision 2, in Section 4.2.A.4. By letter dated July 5, 2012, the staff 

issued RAI B2.1.9-1 requesting that the applicant discuss whether NEI 97-06, Revision 2, or 

NEI 97-06, Revision 3, was used during RFO 18 inspections. If NEI 97-06 Revision 2, was 

used, the staff requested that the applicant provide the deviation supporting this exception to the 

industry guidelines.

In its response dated August 6, 2012, the applicant stated that prior to RFO 18, document 

S-1032 was approved before the implementation of NEI 97-06, Revision 3. The applicant also 

stated that document S-1032 is a specification for a contractor to provide steam generator 

inspection services and is not used as a procedure to perform steam generator inspections. 

The applicant further stated that all implementation procedures for steam generator inspections 

conducted during RFO 18 references were governed by NEI 97-06 Revision 3, and future 

revisions of document S-1032 will reference NEI 97-06, Revision 3.

The staff finds the applicant’s response acceptable because the applicant clarified that it 

followed the guidance in NEI 97-06, Revision 3, during its RFO 18 steam generator inspection 

which is consistent with the guidance provided in the GALL Report AMP XI.M19. The staff’s 

concern described in RAI B2.1.9-1 is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-70

The staff found that the term “active degradation” is used in EDP-BB-01341, “Steam Generator 

Surveillance.” This term, as originally defined, was misleading and is no longer used in the 

EPRI document, “Pressurized Water Reactor Steam Generator Examination Guidelines,” which 

were issued in 2007. By letter dated July 5, 2012, the staff issued RAI B2.1.9-2 requesting the 

applicant to discuss its plans for removing this term from its procedures.

In its response dated August 6, 2012, the applicant stated that EDP-BB-01341, “Steam 

Generator Surveillance,” procedure Sections 4.4.1.a.4, 4.9.6.c.3, 4.9.7.c, 4.9.7.e.3, 4.10.2.a, 

and 7.1 have been revised to remove references to the term "active degradation" and reference 

the term “existing degradation,” "degradation," or "degradation mechanism" to be consistent 

with EPRI 1019038, “Steam Generator Integrity Assessment Guidelines,” and EPRI 1013706, 

“Pressurized Water Reactor Steam Generator Examination Guidelines.”

The staff finds the applicant’s response acceptable because the applicant removed the term 

“active degradation” from EDP-BB-01341 procedure and replaced it with terms consistent with 

EPRI 1019038 and EPRI 1013706 which makes the applicant’s program consistent with the 

guidance provided in the GALL Report AMP XI.M19. The staff’s concern described in 

RAI B2.1.9-2 is resolved.

The staff noted that Section 4.1.2.c.3 of EDP-BB-01341, “Steam Generator Surveillance,” 

indicates that if implementation of a guideline change cannot be performed within 3 months of 

the due date, then a deviation should be processed. The staff finds that this appears to permit 

implementing the guideline change 3 months after the due date. By letter dated July 5, 2012, 

the staff issued RAI B2.1.9-3 requesting the applicant clarify where the 3-month “extension” is 

permitted by the industry guidelines (i.e., if the forwarding letter indicates the guideline change 

should be implemented by a specific date, it is not clear that a 3-month automatic extension is 

justified). If the 3-month “extension” is not permitted by industry guidance documents, the staff 

requested the applicant discuss its plans to change its procedures.

In its response dated August 6, 2012, the applicant stated that Section 4.1.2.c.3 of procedure 

EDP-BB-01341 has been revised to remove the 3-month extension for implementation of a 

guideline change and now states “IF implementation CANNOT be performed PROCESS a 

deviation.”

The staff finds the applicant’s response acceptable because its revision of procedure 

EDP-BB-01341 makes the applicant program consistent with the guidance provided in the GALL 

Report AMP XI.M19. The staff’s concern described in RAI B2.1.9-3 is resolved.

The staff noted that EDP-BB-01341 Section 4.5.1 deals with secondary side inspections; 

however, Section 4.5.1.a refers to primary side maintenance activities. By letter dated 

July 5, 2012, the staff issued RAI B2.1.9-4 requesting the applicant clarify if this was a 

typographical error. 

In its response, dated August 6, 2012, the applicant stated that EDP-BB-01341 Section 4.5.1.a 

has been revised to correct a typographical error and reference the secondary side.

The staff finds the applicant’s response acceptable because the applicant clarified that it was a 

typographical error and revised EDP-BB-01341 Section 4.5.1.a accordingly which makes the 

applicant program consistent with the guidance provided in the GALL Report AMP XI.M19. The 

staff’s concern described in RAI B2.1.9-4 is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-71

The staff noted that EDP-BB-01341 Section 4.10.3 requires the condition monitoring report to 

be completed within 30 days following completion of the outage; however EDP-BB-01341 

Section 4.9.6.a.1 requires the condition monitoring report to be completed before Mode 4 after a 

steam generator inspection. The EPRI document “Steam Generator Integrity Assessment 

Guidelines” (Section 11.2.2) requires the condition monitoring assessment to be completed 

before entering Mode 4. By letter dated July 5, 2012, the staff issued RAI B2.1.9-5 requesting 

the applicant to discuss its plans to make its procedures consistent with the industry guidelines.

In its response dated August 6, 2012, the applicant stated that EDP-BB-01341 Section 4.10.3.c 

has been revised to ensure the condition monitoring report is completed before entering 

Mode 4.

The staff finds the applicant’s response acceptable because its revision of EDP-BB-01341 

Section 4.10.3.c makes the applicant program consistent with the guidance provided in GALL 

Report AMP XI.M19. The staff’s concern described in RAI B2.1.9-5 is resolved.

The staff noted that EDP-BB-01341 Section 4.8.5.e refers to “degradation of interest” rather 

than “existing and potential degradation,” as discussed in the EPRI document, “Steam 

Generator Integrity Assessment Guidelines” (Section 6.2). By letter dated July 5, 2012, the staff 

issued RAI B2.1.9-6 requesting the applicant discuss whether “degradation of interest” is 

defined in its procedures. If not, the staff requested the applicant to discuss its plans to modify 

its procedures to ensure they are consistent with the industry guidelines.

In its response, dated August 6, 2012, the applicant stated that the EDP-BB-01341 

Section 4.8.5.e has been revised to refer to existing and potential degradation mechanisms and 

now states, “IDENTIFY the limiting structural integrity performance criteria and the appropriate 

loading conditions for existing and potential degradation mechanisms (i.e. 3 Delta P vs. 

1.4 times accident pressure including primary vs. secondary loading).”

The staff finds the applicant’s response acceptable because the applicant revised 

EDP-BB-01341 Section 4.8.5.e to make it consistent with EPRI guidelines, and this makes the 

applicant program consistent with the guidance provided in the GALL Report AMP XI.M19. 

The staff’s concern described in RAI B2.1.9-6 is resolved.

Based on its audit of the applicant’s Steam Generators Program and review of the applicant’s 

responses to RAIs B2.1.9-1 through B2.1.9-6, the staff finds that program elements one through 

six for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M19.

Operating Experience. LRA Section B2.1.9 summarizes operating experience related to the 

Steam Generators Program. The LRA states, in part, the following regarding operating 

experience:

[d]uring [RFO] 14 (Fall 2005), [steam generators] were replaced with AREVA 

designed steam generators with alloy 690 thermally treated tubes. Pre-service 

eddy current inspections found 77 small dings, four tubes with signals similar to 

outside diameter axial cracking, and 33 tubes with a spiral signal pattern. After 

analyzing the signals and the tubes containing indications, the tubes were found 

to have no detectable degradation. One tube was plugged due to manufacturing 

defects. Visual inspections of the [steam generator] secondary side were 

performed to identify any foreign objects that may have been left behind after up 

righting and installation of the steam generators. Several foreign objects were 
AGING MANAGEMENT REVIEW RESULTS

3-72

found during these inspections and removed prior to placing the steam 

generators in service. 

The LRA states that during RFO 15 (spring 2007), the first ISI of the new steam generators 

identified a total of 92 anti-vibration bar (AVB) wear indications. The LRA also states that the 

largest indication was a 14 percent through-wall flaw. The LRA further states that, consistent 

with Callaway’s RFO 15 operational assessment, the structural integrity performance criteria for 

AVB wear is not expected to be exceeded before the next scheduled steam generator 

inspection in RFO 18 (fall 2011).

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of RAIs, as 

discussed below.

The staff noted that that AREVA NP Inc., document No. 51-9172264-000, “Callaway Unit 1 SG 

[Steam Generator] Condition Monitoring for Cycles 16, 17, and 18 and Final Operational 

Assessment for Cycles 19, 20, and 21,” does not appear to justify the length of the operating 

interval for secondary side degradation. The staff also noted that Section 10.3 of the EPRI

document, “Steam Generator Integrity Assessment Guidelines,” indicates that the operational 

assessment shall include a justification for operating the planned interval between secondary 

side inspections, as well as primary side inspections. By letter dated July 5, 2012, the staff 

issued RAI B2.1.9-7 requesting the applicant discuss whether there is a justification for the 

planned operating interval that addresses degradation of secondary side internals. 

In its response, dated August 6, 2012, as supplemented by letter dated September 18, 2012, 

the applicant stated that the following:

The first paragraph of Section 10 of [AREVA NP, Inc.,] document 51-9172264-00 

identifies the forms of degradation detected in the Callaway Unit-1 replacement 

steam generators at the 1R18 outage [RFO 18]. These mechanisms were AVB 

and TSP [tube support plate] wear. There was no degradation associated with 

the secondary side findings (inner bundle or steam drum).

The applicant stated that the intent of the operational assessment was to address currently 

detected and/or previously detected degradation mechanisms located on the primary and 

secondary sides of the steam generators. The applicant also stated the secondary side findings 

revealed no degradation, and, therefore, discussion was limited to the condition monitoring 

results located in Section 6.2 of AREVA NP Inc., document 51-9172264-00.

The applicant stated that AREVA NP Inc., document No. 51-9172264-00 Section 6.2 identifies 

the secondary side activities performed in RFO 18. These activities included steam drum 

inspections in steam generators B and C, foreign object and possible loose part (PLP) 

inspections in all four steam generators, and sludge lancing in all four steam generators. The 

applicant stated that no loose part or loose hardware was detected in the steam drum of either 

steam generator as a result of the steam drum inspections. The applicant also stated that the 

only anomaly noted was a pre-existing condition which consisted of two buckles on one of the 

sectors associated with the loose part trapping screens. The applicant further stated that 
AGING MANAGEMENT REVIEW RESULTS

3-73

foreign object and possible loose part inspections revealed no possible loose parts or foreign 

object degradation detected in any steam generator based on eddy current inspections. In 

addition, the applicant stated that only a small piece of scale in the cold-leg of steam 

generator A was detected by the foreign object search and retrieval inspections (post-lancing) 

and only minimal amounts of sludge were contained within each of the four steam generators as 

revealed by the sludge lancing results. The applicant stated that “the findings at [RFO] 18 

echoed the findings at [RFO] 15 (with exception of the single small piece of scale detected in 

the cold leg of [steam generator] A)” and concluded that “[b]ased on two consecutive outages of 

exceptional secondary side inspection results, any projected secondary side degradation is 

expected to be minimal and to not compromise tube integrity for the planned operating interval.” 

In its supplemental response dated September 18, 2012, the applicant stated that it is updating 

the steam generator surveillance procedure to explicitly state the requirement for the condition 

monitoring report to include projection data to justify operation for the planned interval between 

secondary side inspections and that this includes degradation of secondary side internals.

The staff reviewed the applicant response as supplemented and finds it acceptable because the 

applicant’s assessment of the secondary side component degradation is in line with industry 

guidance. Furthermore, revising the steam generator surveillance procedure to more accurately 

reflect the guidance in the EPRI document, “Steam Generator Integrity Assessment Guidelines,” 

will ensure that a justification for the planned operating interval will include secondary side 

component degradation in the applicant’s condition monitoring reports for the future. The staff’s 

concern described in RAI B2.1.9-7 is resolved.

The staff noted that Section 8.6 of the EPRI document, “Steam Generator Integrity Assessment 

Guidelines,” indicates, in part, that (1) failure to meet condition monitoring requirements means 

that the projections of the previous operational assessment were not conservative and that 

necessary corrective actions shall be identified; and (2) even if condition monitoring 

requirements are met, a comparison of condition monitoring results with the projections of the 

previous operational assessment shall be performed, and this comparison shall be completed 

before issuance of the final operational assessment since adjustment of input parameters may 

be required. AREVA NP Inc., Document No. 51-9172264-000, "Callaway Unit 1 SG [Steam 

Generator] Condition Monitoring for Cycles 16, 17, and 18 and Final Operational Assessment 

for Cycles 19, 20, and 21,” states that the latter must be performed, but then the report went on 

to indicate that the assumptions and uncertainties included in the previous operational 

assessment are validated since none of the detected indications approach the condition 

monitoring limit and that additional discussions below provide further details. The staff could not 

locate these additional discussions. In addition, in reviewing the previous operational 

assessment, the staff could not locate any specific projections such that a comparison of the 

as-found and previously projected conditions could be compared. It is not clear to the staff that 

the intent of the EPRI requirement has been met. The staff noted that the operational 

assessment is supposed to be conservative. As a result, even if the actual detected conditions 

are near (including “slightly” below) the projections from the prior operational assessment, this 

could indicate a potential nonconservative assessment that may lead to issues in the future if 

not corrected. By letter dated July 5, 2012, the staff issued RAI B2.1.9-8 requesting the 

applicant clarify these discrepancies. 

In its response dated August 6, 2012, the applicant stated that additional discussions, although 

not specifically referenced, are located in Section 7.2, “Structural Results,” and Section 7.3, 

“Leakage Results,” of AREVA NP Inc., Document No. 51-9172264-000, “Callaway Unit 1 SG 

[Steam Generator] Condition Monitoring for Cycles 16, 17, and 18 and Final Operational 
AGING MANAGEMENT REVIEW RESULTS

3-74

Assessment for Cycles 19, 20, and 21.” Furthermore, the applicant stated that the implied 

projections of the RFO 15 operational assessment (both growth rates and end of cycle percent 

through wall) were satisfied with adequate margin, at end of cycle 18, as demonstrated by the 

condition monitoring results. In a supplemental response dated September 18, 2012, the 

applicant stated that “[t]he Callaway’s steam generator surveillance procedure is being updated 

to explicitly state the requirement for the [c]ondition [m]onitoring report to include a definitive 

comparison between the current condition monitoring results with the projections of the previous 

operational assessment.”

The staff reviewed the applicant’s response as supplemented and finds it acceptable because 

the applicant’s assessment of the structural results, leakage results, and operational 

assessment meet the industry guidance as provided by EPRI. Furthermore, revising the Steam 

Generator Surveillance procedure to ensure that the condition monitoring report more 

accurately reflects the guidance in the EPRI document, “Steam Generator Integrity Assessment 

Guidelines,” will ensure that a definitive comparison between the current condition monitoring 

results with the projections of the previous operational assessment and that the comparison will 

be documented in the applicant’s condition monitoring reports in the future. The staff’s concern 

described in RAI B2.1.9-8 is resolved.

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

RAIs B2.1.9-7 and B2.1.9-8, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience, and that implementation of the program has 

resulted in the applicant taking corrective action. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which GALL Report 

AMP XI.M19 was evaluated.

FSAR Supplement. LRA Section A1.9 provides the FSAR supplement for the Steam 

Generators Program. The staff reviewed this FSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

finds that the information in the FSAR supplement is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s Steam Generators Program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. The staff concludes that the applicant has demonstrated 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 One-Time Inspection

Summary of Technical Information in the Application. LRA Section B2.1.18 describes the new 

One-Time Inspection Program as consistent with GALL Report AMP XI.M32, “One-Time 

Inspection.” The LRA states that the One-Time Inspection Program verifies the system-wide 

effectiveness of the Water-Chemistry, Fuel Oil, and Lubricating Oil Analysis programs through 

the use of inspections to confirm that aging effects are either not occurring or are progressing so 

slowly as to have a negligible effect on the intended function of each component.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 
AGING MANAGEMENT REVIEW RESULTS

3-75

to the corresponding program elements of GALL Report AMP XI.M32. Based on its audit of the 

applicant’s One-Time Inspection Program, the staff finds that program elements one through six 

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M32. 

Operating Experience. LRA Section B2.1.18 summarizes operating experience related to the 

One-Time Inspection Program. The LRA states that a review of 10 years of operating 

experience associated with the Water Chemistry, Fuel Oil, and Lubricating Oil Analysis 

programs confirmed that aging effects are either not occurring or are progressing so slowly as to 

have a negligible effect on the intended function of each component and are adequately 

managing aging effects. The LRA also states that RPV inservice inspections revealed an 

original construction weld flaw in the “C” inlet nozzle of the RPV and ongoing monitoring of this 

flaw will use state-of-the-art NDE techniques. The LRA further states that these examples 

demonstrate that inspections associated with this program will be capable of detecting and 

identifying aging effects before a loss of intended function during the period of extended 

operation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M32 was evaluated.

FSAR Supplement. LRA Section A1.18 provides the FSAR supplement for the One-Time 

Inspection Program. The staff reviewed this FSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 14) to implement the new One-Time 

Inspection Program six months before entering the period of extended operation. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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

3-76

3.0.3.1.9 One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

Summary of Technical Information in the Application. LRA Section B2.1.20 describes the new 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program as consistent with 

GALL Report AMP XI.M35, “One-Time Inspection of ASME Code Class 1 Small-Bore Piping.” 

The LRA states that the program manages cracking of ASME Code Class 1 piping less than 

4 in. and greater than or equal to 1-inch nominal pipe size (NPS) in a reactor coolant 

environment. 

The LRA states that there are 340 ASME Code Class 1 small-bore butt welds within the scope 

of the program at the applicant’s facility. The LRA states that at least 25 butt welds will be 

included in the examination population. The LRA also states that the program will include a 

volumetric or opportunistic destructive examination of socket welds and butt welds to identify 

potential cracking. The LRA further states that two small-bore ASME Code Class 1 socket 

welds will be selected for examination, which represents 10 percent of the population of 

19 socket welds covered by the program. In addition, the LRA states that for socket welds, if a 

demonstrated volumetric examination technique endorsed by industry or the NRC, and 

incorporated into ASME Code Section XI is not available by the time of the inspections, then a 

qualified plant procedure for volumetric examination of ASME Code Class 1 small-bore piping 

socket welds will be used. The LRA also states that the program includes implementation of a 

plant-specific periodic inspection AMP, should evidence of ASME Code Class 1 small-bore 

piping cracking be confirmed by review of plant-specific operating experience.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M35. For the “scope of 

program” program element, the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below.

LRA Section B2.1.20 originally stated that there were 19 Class 1 small-bore socket welds in the 

population of ASME Code Class 1 piping less than NPS 4 and greater than or equal to NPS 1. 

However, during the audit the applicant stated that its recount, performed subsequent to the 

LRA submission, had indicated that there were 23 Class 1 small-bore socket welds within the 

scope of the program. The staff noted that recent review of LRAs of other similar facilities have 

shown the number of in-scope socket welds to be significantly greater than 19 or 23. By letter 

dated July 18, 2012, the staff issued RAI B2.1.20-1 requesting that the applicant clarify the total 

population of ASME Code Class 1 socket welds within the scope of the program. 

In its response dated August 21, 2012, the applicant stated that there are 77 small-bore socket 

welds in the scope of the AMP. The applicant also amended LRA Sections B2.1.20 and A1.20 

to reflect the correct number of socket welds. In addition, the applicant revised the AMP to 

indicate that eight small-bore Class 1 socket welds will be inspected. During its review of the 

applicant’s revised AMP the staff noted that the revised LRA is not clear on how each 

destructive test will be credited. Specifically, if the applicant chooses to perform opportunistic 

destructive examinations on socket welds in lieu of volumetric examinations, it is not clear to the 

staff what the ratio of those tests will be. GALL Report AMP XI.M35 states that when 

opportunistic destructive examinations are used for socket welds, the applicant may take credit 

for each weld destructively examined as equivalent to having volumetrically examined two 

welds. By letter dated October 3, 2012, the staff issued RAI B2.1.20-1a, requesting that the 

applicant clarify how each destructive test will be credited and also when and if opportunistic 

destructive examinations are included in the applicant’s AMP.
AGING MANAGEMENT REVIEW RESULTS

3-77

In its response dated October 31, 2012, the applicant stated that, consistent with the guidance 

provided in the GALL Report, it will credit each destructive examination of a socket weld as 

equivalent to having volumetrically examined two. As part of its response, the applicant 

amended LRA Sections B2.1.20 and A1.20 to specifically state that when opportunistic 

destructive examinations are used, each destructive examination will be considered equivalent 

to having volumetrically examined two welds. The staff finds the applicant’s response 

acceptable because it clarified that, if opportunistic destructive tests are performed, each 

destructive test will be credited as having performed two volumetric examinations, consistent 

with the GALL Report. The staff’s concern described in RAI B2.1.20-1a is resolved.

During a telephone conference call held on April 11, 2013, the staff requested the applicant to 

explain the reasons for the large discrepancy between the different counting results for the 

number of socket welds, and whether any error in the process has been corrected. The 

applicant stated that the information would be provided to the staff in a supplemental response 

to RAI B2.1.20-1. The applicant’s need to explain the discrepancy between the different 

counting results was identified as OI B2.1.20-1. 

By letter dated April 16, 2013, the applicant supplemented its response to RAI B2.1.20-1. The 

supplemental response provided an explanation of how the error occurred during counting the 

number of socket welds. In its response, the applicant stated that the list of socket welds was 

developed from its Inservice Inspection database, using the fields for ASME Category and Item 

Number. The error occurred because some small-bore socket welds were not assigned any 

ASME Category and Item Numbers since they are exempt from ASME Code Section XI ISI 

volumetric and surface examinations. The staff noted that a similar error could have also 

occurred when counting in-scope items for other aging management programs in the LRA. By 

letter dated July 12, 2013, the staff issued followup RAI B2.1.20-2, requesting that the applicant 

verify that the issue of reporting the incorrect number of socket welds was entered in its 

corrective actions program, or justify why a similar error could not and did not occur elsewhere 

in the LRA.

In its response dated August 2, 2013, the applicant stated that the issue of reporting the 

incorrect number of ASME Code Class 1 small-bore socket welds in the LRA was entered in the 

applicant’s Corrective Action Program as an adverse condition. The applicant also stated that 

an extent of condition review was performed. Since the error was introduced during the process 

of developing a sample population, the extent of condition for the error was determined to 

include all instances where sample population numbers are cited in the LRA, and the applicant 

searched for instances of sample, sampling, and population. The applicant further stated that 

this search only provided two instances where sample population was developed in support of 

an AMP and cited in the LRA, and that both instances were related to the One-Time Inspection 

of ASME Code Class 1 Small-Bore Piping Program. The applicant also stated that the number 

of butt welds and socket welds were re-counted for accuracy; the examination populations

remained unchanged at 25 butt welds and 8 socket welds. The staff finds the applicant’s 

response acceptable because: (1) the applicant entered the error in its Corrective Action 

Program; (2) the applicant’s extent of condition for the error verified that a similar error had not 

occurred elsewhere in the LRA; and (3) as part of corrective actions the applicant re-counted 

the total number of in-scope butt welds and socket welds and confirmed the numbers. The 

staff’s concern described in RAI B2.1.20-2 is resolved. The staff concludes that the concerns 

identified in OI B2.1.20-1 have been resolved. Open Item B2.1.20-1 is closed.

Based on its audit of the applicant’s One-Time Inspection of ASME Code Class 1 Small-Bore 

Piping Program and review of the applicant’s responses to RAIs B2.1.20-1, B2.1.20-1a, and 
AGING MANAGEMENT REVIEW RESULTS

3-78

B2.1.20-2, the staff finds that program elements 1 through 6, for which the applicant claimed 

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

GALL Report AMP XI.M3. 

Operating Experience. LRA Section B2.1.20 summarizes operating experience related to the 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program. The LRA states that 

in 1995 cracking was observed on an ASME Code Class 1 small-bore pipe butt weld less than 

NPS 4. Specifically, a Class 1 butt weld on a 2-inch CVC system excess letdown line 

developed a crack. The reported failure was attributed to high stresses because of interference 

and system vibrations. As part of its corrective actions, the applicant removed the interference 

and subsequent volumetric examinations performed in 2010 that did not identify any indication. 

The applicant also stated that there have been no additional failures of ASME Code Class 1 

small-bore piping since 1995.

The staff noted that the applicant has performed design changes to mitigate the cause of the 

reported failure, and performed additional inspections to determine the extent of condition. In 

addition, there have been no additional similar failures of ASME Code Class 1 small-bore piping 

welds since the implementation of the applicant’s corrective actions. Therefore, consistent with 

GALL Report AMP XI.M35, the use of the applicant’s One-Time Inspection of ASME Code 

Class 1 Small-Bore Piping Program is appropriate, because the reported failure of 1995 was 

successfully mitigated. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M35 was evaluated. 

FSAR Supplement. LRA Section A1.20 provides the FSAR supplement, as amended by letters 

dated August 21, 2012, October 31, 2012, and February 28, 2013, for the One-Time Inspection 

of ASME Code Class 1 Small-Bore Piping Program. The staff reviewed this FSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 16) to 

implement the new One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program six 

months before entering the period of extended operation. 

The staff finds that the information in the FSAR supplement, as amended by letters dated 

August 21, 2012, October 31, 2012, and February 28, 2013, is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection of 

ASME Code Class 1 Small-Bore Piping Program, the staff concludes that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 
AGING MANAGEMENT REVIEW RESULTS

3-79

managed so that the intended 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 

FSAR 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 External Surfaces Monitoring of Mechanical Components 

Summary of Technical Information in the Application. LRA Section B2.1.21 describes the new 

External Surfaces Monitoring of Mechanical Components Program as consistent with 

GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components.” The 

LRA states that the AMP manages loss of material and cracking for metallic components; 

cracking and changes in material properties for cement board; and loss of material, cracking, 

changes in material properties, hardening, and loss of strength for polymeric components. The 

LRA also states that the AMP proposes to manage these aging effects using visual inspections 

that are performed at least every RFO for normally accessible locations. In addition, the LRA 

states that manual or physical manipulation will supplement visual inspections to identify aging 

effects for polymeric components. The LRA further states that surfaces not readily visible 

during plant operations and RFO are inspected when they are made accessible and at intervals 

that would ensure the components’ intended functions are maintained.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M36. Based on its audit of the 

applicant’s External Surfaces Monitoring of Mechanical Components Program, the staff finds 

that program elements one through six for which the applicant claimed consistency with the 

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

AMP XI.M36.

Operating Experience. LRA Section B2.1.21 summarizes operating experience related to the 

External Surfaces Monitoring of Mechanical Components Program. The LRA states that 

cracking was found in 2006 on a rubber expansion joint between ESW piping and the diesel 

generator intercooler heat exchanger. The joints between the components were replaced and 

the maintenance procedure for the heat exchanger tubes was revised to include inspections of 

the expansion joints. The LRA also states that loss of material was identified on ESW supply 

line piping in 2006. The LRA further states that ultrasonic testing determined that the piping met 

minimum wall thickness. The piping coating was completely restored on all bare metal surfaces 

of piping related to this finding.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff identified operating experience for which it determined the need for 

additional clarification and which resulted in the issuance of an RAI, as discussed below.

LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric 

Storage Tanks, and Corrosion Under Insulation,” revised GALL Report AMP XI.M36 to address 

recent industry operating experience associated with corrosion under insulation. For insulated 

outdoor components and insulated indoor components operated below the dew point, GALL 
AGING MANAGEMENT REVIEW RESULTS

3-80

Report AMP XI.M36 was revised to recommend that an initial representative sample of external 

surfaces be inspected after the insulation is removed. If the initial examinations do not reveal 

evidence of component aging, water intrusion, or damage to the insulation, the revised guidance 

allows for subsequent examinations to focus only on indications of damage to the insulation 

jacketing or protective outer layer rather than removing the insulation. By letter dated 

October 7, 2013, the staff issued RAI 3.0.3-5, requesting that the applicant describe how 

corrosion under insulation would be managed for insulated outdoor components and insulated 

indoor components operated below the dew point.

In its response dated December 20, 2013, as supplemented by letter dated March 13, 2014, the 

applicant stated that the External Surfaces Monitoring of Mechanical Components Program will 

include all of the new inspection recommendations in LR-ISG-2012-02 associated with corrosion 

under insulation. The staff finds the applicant’s response acceptable because the applicant 

incorporated the new inspection guidance provided in LR-ISG-2012-02, such that the External 

Surfaces Monitoring of Mechanical Components Program will be consistent with the revised 

GALL Report AMP XI.M36. The staff’s concern described in RAI 3.0.3-5 is resolved.

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

RAI 3.0.3-5, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M36 was 

evaluated.

FSAR Supplement. LRA Section A1.21 provides the FSAR supplement for the External 

Surfaces Monitoring of Mechanical Components Program. The staff reviewed this FSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed 

(Commitment No. 17) to implement the new External Surfaces Monitoring of Mechanical 

Components Program six months before entering the period of extended operation for 

managing aging of applicable components during the period of extended operation. The staff 

finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s External Surfaces Monitoring 

of Mechanical Components Program, the staff concludes that those program elements for which 

the applicant claimed consistency with the GALL Report are consistent. The staff concludes 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Flux Thimble Tube Inspection

Summary of Technical Information in the Application. LRA Section B2.1.22 describes the 

existing Flux Thimble Tube Inspection Program as consistent with GALL Report AMP XI.M37, 

“Flux Thimble Tube Inspection.” The LRA states that the Flux Thimble Tube Inspection 

Program manages loss of material by performing wall thickness eddy current inspection of all 

flux thimble tubes that form part of the RCS pressure boundary. The LRA also states that the 

eddy current testing is performed on the portion of the tubes inside the reactor vessel. The LRA 

further states that the AMP implements the recommendations of NRC Bulletin 88-09, “Thimble 

Tube Thinning in Westinghouse Reactors.” The LRA states that the flux thimble tubes are 
AGING MANAGEMENT REVIEW RESULTS

3-81

inspected during each RFO and that inspection may be deferred by using an evaluation that 

considers the actual wear rate. The LRA further states that wall thickness measurements are 

trended, wear rates are calculated, and if the measured wear exceeds the acceptance criteria or 

if the predicted wear (as a measure of percent through-wall) for a given flux thimble tube is 

projected to exceed the acceptance criteria before the next RFO, corrective actions are taken to 

reposition, cap, or replace the tube. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M37. The staff also reviewed 

the plant conditions to determine if they are bounded by the conditions for which the 

GALL Report was evaluated. 

The LRA states that the applicant’s reactor vessel lower internals have instrumentation column 

sleeves installed that reduce the instrument column inside diameter. The flux thimble tubes 

have an outer diameter of 0.313 in. The combination of reduced inside diameter of the 

instrument columns and large outer diameter of the flux thimble tubes results in a smaller 

annular gap. The smaller gap minimized tube vibration fretting wear and, therefore, reduced 

wear rates. The staff noted that based on industry experience as documented in Westinghouse 

Commercial Atomic Power (WCAP)-12866, “Bottom Mounted Instrumentation Flux Thimble 

Wear,” the existing configuration of the applicant’s flux thimble tubes has very low wear rates, 

as a result of the minimal clearance between the instrument column and the tube. This is 

consistent with the applicant’s operating record that no flux thimble tubes have been removed 

from service or repositioned due to wear during the past 25 years of plant operation.

The LRA also states that the flux thimble tubes are scheduled to be inspected during each RFO 

and that inspection may be deferred by using an evaluation that considers the actual wear rate. 

The staff noted that the applicant’s Flux Thimble Tube Inspection Program is an existing 

program that is based on the recommendations in NRC Bulletin 88-09, “Thimble Tube Thinning 

in Westinghouse Reactors.” The staff also noted that the applicant’s program trends wall 

thickness measurements and calculates actual wear rates. If the measured wear exceeds the 

acceptance criteria or if the predicted wear (as a measure of percent through-wall) for a given 

flux thimble tube is projected to exceed the acceptance criteria before the next RFO, corrective 

actions are taken to reposition, cap, or replace the tube. The staff finds that the continued 

implementation of the Flux Thimble Tube Inspection Program provides reasonable assurance 

that aging effects will be managed such that the systems and components within the scope of 

this program will continue to perform their intended functions.

Based on its audit, and review of the applicant’s Flux Thimble Tube Inspection Program, the 

staff finds that program elements one through six for which the applicant claimed consistency 

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

AMP XI.M37. 

Operating Experience. LRA Section B2.1.22 summarizes operating experience related to the 

Flux Thimble Tube Inspection Program. The LRA states that the applicant had to reposition flux 

thimble tubes only twice because of reasons other than wear. In one case, a thimble tube was 

repositioned because detectors could not be inserted past the seal table. In the second case, a 

thimble tube was repositioned because of galled fittings and because installation of new fittings 

required the thimble tube to be repositioned. During the review and onsite audit, the staff 

reviewed details of the two cases and confirmed that the repositioning was not caused by wear. 

The staff also reviewed the operating history and inspection results of the applicant’s Flux 
AGING MANAGEMENT REVIEW RESULTS

3-82

Thimble Tube Inspection Program and noted that the applicant has not experienced any 

wear-related failures in its flux thimble tubes. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M37 was evaluated.

FSAR Supplement. LRA Section A1.22 provides the FSAR supplement for the Flux Thimble 

Tube Inspection Program. The staff reviewed this FSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff finds that the information in the FSAR supplement is an adequate summary description of 

the program.

Conclusion. On the basis of its audit and review of the applicant’s Flux Thimble Tube Inspection 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.1.12 ASME Code Section XI, Subsection IWL 

Summary of Technical Information in the Application. LRA Section B2.1.27 describes the 

existing ASME Section XI, Subsection IWL Program as consistent with GALL Report 

AMP XI.S2, “ASME Section XI, Subsection IWL.” The LRA states that the ASME Section XI, 

Subsection IWL Program addresses concrete of containment building and post-tensioning 

system exposed to atmosphere and weather to manage the aging effects of cracking, loss of 

material, loss of bond, loss of strength, and increase in porosity and permeability through visual 

inspections, supplemented by testing.

The LRA states that acceptance criteria, corrective actions, and expansion of the inspection 

scope, when degradation exceeding the acceptance criteria is found, are performed in 

accordance with ASME Code Section XI, Subsection IWL. The LRA states that the IWL 

containment inservice inspections satisfy the requirements of the 2001 Edition of ASME Code 

Section XI (including 2002 and 2003 addenda), supplemented with the applicable requirements 

of 10 CFR 50.55a(b)(2). In conformance with 10 CFR 50.55a(g)(4)(ii), the Callaway 

Containment Inservice Inspections Program will be updated during each successive 120-month 

inspection interval to comply with the requirements of the latest edition and addenda of the 

ASME Code specified 12 months before the start of the inspection interval.
AGING MANAGEMENT REVIEW RESULTS

3-83

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S2. For the “acceptance 

criteria” program element, the staff determined the need for additional information, which 

resulted in the issuance of an RAI as discussed below.

GALL Report AMP XI.S2, “ASME Section XI, Subsection IWL,” program element six, 

“acceptance criteria,” recommends that the program use acceptance criteria provided in 

IWL-2510, which references American Concrete Institute (ACI) 201.1R and ACI 349.3R for 

identification of concrete degradation. The LRA AMP basis document for program element six, 

“acceptance criteria,” states that Callaway acceptance criteria for concrete degradation is in 

accordance with IWL-2510, and consistent with ACI 201.1R and ACI 349.3R. 

However, during its onsite audit, the staff reviewed plant procedures applicable to the 

applicant’s IWL Program and could not find a reference to ACI 349.3R in any plant procedures. 

The staff also reviewed results of previous IWL examinations and noted that the evaluation 

criteria specified in ACI 349.3R Chapter 5, “Evaluation Criteria,” were not used during the 

examinations of the concrete containment building. 

By letter dated July 9, 2012, the staff issued RAI B2.1.27-1 requesting that the applicant state 

whether plant procedures reference ACI 349.3R, and if so, how the procedures incorporate the 

guidance in ACI 349.3R. Also, the staff requested that the applicant provide clarification on 

whether the evaluation criteria specified in ACI 349.3R Chapter 5 are used during IWL 

examinations or that they provide justification for not using the ACI 349.3R criteria during the 

examinations of the concrete containment building.

In its response dated August 9, 2012, the applicant stated that LRA Appendix B2.1.27 was 

revised and LRA Table A4-1, Commitment No. 40 was added as a new commitment to specify 

that acceptability of concrete surfaces is based on the evaluation criteria provided in 

ACI-349.3R. The applicant also revised LRA Section B2.1.27 to include a new enhancement to 

the “acceptance criteria” program element. In this enhancement, the applicant stated that plant 

procedures will be enhanced to specify that acceptability of concrete surfaces is based on the 

evaluation criteria provided in ACI-349.3R.” 

The staff reviewed the RAI response and the new enhancement against the corresponding 

program element in GALL Report AMP XI.S2 and finds the response and the enhancement 

acceptable because when implemented it will align the applicant’s acceptance criteria with that 

provided in ACI 349.3R-96, and recommended in GALL Report AMP XI.S2. The staff finds that 

the applicant’s enhanced “acceptance criteria” program element will be consistent with the 

GALL Report program element. The staff’s concern described in RAI B2.1.27-1 is resolved.

Based on its audit of the applicant’s ASME Section XI, Subsection IWL Program and review of 

the applicant’s response to RAI B2.1.27-1, the staff finds that program elements one through six 

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S2. 

Operating Experience. LRA Section B2.1.27 summarizes operating experience related to the 

ASME Section XI, Subsection IWL Program. 

The applicant provided the following discussion of operating experience that offers objective 

evidence that the ASME Section XI, Subsection IWL Program will be effective in ensuring that 

intended functions are maintained consistent with the CLB for the period of extended operation: 
AGING MANAGEMENT REVIEW RESULTS

3-84

(1) The 15th year tendon surveillance began in May 1999 and was completed in June 1999. 

Based on the data gathered during the 1999 physical surveillance and visual inspection, 

the conclusion was reached that no abnormal degradation of the post-tensioning system 

had occurred at the Callaway containment building.

(2) The 20th year tendon surveillance began in July 2004 and was completed in 

September 2004. All tendons were resealed and regreased. One tendon accepted less 

grease than was removed, and one tendon accepted more than 10 percent of the 

tendon duct volume. Nonconformance reports were written to record these findings and 

these conditions were found to be acceptable by engineering evaluation, as allowed by 

ASME [Code] Section XI, Subsection IWL-3310. Based on these evaluations and the 

other data gathered during the 2004 physical surveillance and visual inspection, the 

conclusion was reached that no abnormal degradation of the post-tensioning system 

had occurred at the Callaway containment building.

(3) The 25th year tendon surveillance began in March 2010 and was completed in 

April 2010. Sample wires were removed from one tendon in each group for physical 

testing. The test results on one of the wire samples indicated elongation values under 

the minimum prescribed in Callaway specifications. A nonconformance report was 

written to record this finding, and this condition was found to be acceptable by 

engineering evaluation, as allowed by ASME [Code] Section XI, Subsection IWL-3310. 

Based on this evaluation and the other data gathered during the 2010 physical 

surveillance and visual inspection, the conclusion was reached that no abnormal 

degradation of the post-tensioning system had occurred at the Callaway containment 

building.

Furthermore, the applicant stated that “[o]ccurrences that would be identified under the ASME 

Section XI, Subsection IWL Program will be evaluated to ensure there is no significant impact to 

safe operation of the plant and corrective actions will be taken to prevent recurrence. Guidance 

for re-evaluation, repair, or replacement is provided for locations where aging is found.”

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff also 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, and resulted in the issuance of RAIs, as discussed below.

GALL Report AMP XI.S2, “ASME Section XI, Subsection IWL,” program element 10, “operating 

experience,” references NUREG-1522, “Assessment of Inservice Condition of Safety-Related 

Nuclear Power Plant Structures,” dated June 1995. NUREG-1522 describes instances of 

cracked, spalled, and degraded concrete for reinforced and prestressed concrete containments. 

During the staff’s onsite walkdown on May 2, 2012, mapped cracks in concrete were identified 

around the vertical tendon casings in the tendon gallery.

Callaway’s 25th year containment IWL inspection report identified the referenced cracks as 

“hair-line cracks,” less than 0.040 in. in width. The second-tier evaluation criteria of ACI 349.3R 

is 0.04 in. for “passive cracks.” It is not clear to the staff whether those cracks were determined 

to be “passive cracks,” and whether the “Evaluation Criteria” of ACI 349.3R was used to 
AGING MANAGEMENT REVIEW RESULTS

3-85

evaluate the findings. ACI 349.3R defines passive cracks as those having an absence of recent 

growth and an absence of other degradation mechanisms at the crack.

By letter dated July 9, 2012, the staff issued RAI B2.1.27-2 requesting that the applicant provide 

justification regarding whether the mapped cracks in concrete around the vertical tendon 

casings in the tendon gallery are “passive cracks” and provide the evaluation criteria used for 

accepting those conditions. 

In its response dated August 9, 2012, the applicant stated that “[t]he 20th year IWL inspection 

report noted concrete cracks less than 0.010 in. surrounding the bearing plates. The 25th year 

IWL inspection report also noted concrete cracks less than 0.010 in. surrounding the bearing 

plates.” The applicant also stated that there is no indication that these cracks have experienced 

any recent growth, and the inspections have not identified any other degradation mechanisms at 

the cracks. Therefore, the applicant identified these cracks as passive. Furthermore, the 

applicant stated that:

[t]he 25th year IWL inspection report contains the vendor’s procedure that 

specifies the inspection criteria. This procedure specifies that visual 

examinations will identify concrete deterioration and distress as defined in 

ACI 201.1 and ACI 349.3R. The section of the 25th year inspection report that 

noted cracks less than 0.040 inches was the general visual examination 

performed on the exterior surface of the containment. Describing the cracks as 

“less than 0.040 inches” denotes that they do not exceed the second-tier limits 

provided in ACI 349.3R. These cracks were then inspected with a detailed visual 

examination and found to be less than 0.010 inches in width and, therefore, 

within the first-tier limits of ACI 349.3R and require no further evaluation.

The staff finds the applicant’s response acceptable because acceptance criteria of the ASME 

Section XI, Subsection IWL Program at Callaway is consistent with that provided in 

ACI 349.3R-96, and, therefore, is consistent with GALL Report XI.S2 acceptance criteria. In 

addition, the identified cracking was below the first tier acceptance criteria; therefore, additional 

evaluation was unnecessary. The applicant also inspected the cracks during two consecutive 

inspections (5-year interval) and did not identify any change in the crack width, which indicates 

the cracks are passive. In addition, the applicant will continue to inspect these areas every 

5 years during the period of extended operation and if any degradation is found the applicant 

will evaluate the indications and incorporate them into the CAP. The staff finds that this is 

consistent with the ASME Section XI, Subsection IWL Program. Therefore, the staff’s concern 

described in RAI B2.1.27-2 is resolved. 

During its walkdown on May 2, 2012, the staff observed the exterior section of the containment 

structure at various elevations and noted that the containment vent duct installation was 

blocking a section of the containment exterior surface. The staff could not determine how the 

area of concrete that is obstructed by the containment vent duct installation has been or will be 

visually inspected in accordance with the code. 

By letter dated July 9, 2012, the staff issued RAI B2.1.27-3 requesting that the applicant 

describe how the area of concrete containment that is obstructed by the containment vent duct 

has been or will be examined during the scheduled IWL inspections to ensure that the effects of 

aging of the containment concrete are adequately managed. 

In its response dated August 9, 2012, the applicant stated that in accordance with 

10 CFR 50.55a(b)(2)(viii)(E), ASME Section XI, Subsection IWL Program requires: 
AGING MANAGEMENT REVIEW RESULTS

3-86

[t]hat if concrete inspections determine that conditions exist in accessible areas 

that could indicate the presence of or result in degradation to inaccessible areas, 

for each inaccessible area identified, the following information shall be provided 

in the owner’s activity report:

(a) [d]escription of the type and estimated extent of degradation, and the 

conditions that led to the degradation

(b) [e]valuation of each area, and the result of the evaluation

(c) [d]escription of necessary corrective actions

Furthermore, the applicant stated that a review of ASME Section XI, Subsection IWL Program 

inspection reports indicates that no conditions exist in accessible areas that could indicate the 

presence of degradation in inaccessible areas.

The staff finds the applicant’s response acceptable because ASME Section XI, Subsection IWL 

Program inspection reports do not identify conditions in accessible areas that may indicate the 

presence of degradation in inaccessible areas. In the future, if degradation is identified in 

accessible areas that indicates the potential presence of degradation in inaccessible areas, the 

applicant will evaluate the indications and enter them into the CAP as necessary. The staff 

finds that this practice aligns with the guidance in GALL Report AMP XI.S2. The staff’s concern 

described in RAI B2.1.27-3 is resolved.

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

RAIs B2.1.27-2 and B2.1.27-3, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience, and that implementation of the program has 

resulted in the applicant taking corrective action. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which GALL Report AMP XI.S2 

was evaluated.

FSAR Supplement. LRA Section A1.27 provides the FSAR supplement for the ASME 

Section XI, Subsection IWL Program. The staff reviewed this FSAR supplement description of 

the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 40) to 

enhance, six months before the period of extended operation, the ASME Section XI, Subsection 

IWL program to specify that acceptability of concrete surfaces is based on the evaluation criteria 

provided in ACI-349.3R. The staff finds that the information in the FSAR supplement, as 

amended by letter dated February 28, 2013, is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI, 

Subsection IWL Program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff also reviewed the 

enhancement and confirmed that its implementation, through Commitment No. 40, will make the 

AMP adequate to manage the applicable aging effects. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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

3-87

3.0.3.1.13 10 CFR Part 50, Appendix J

Summary of Technical Information in the Application. LRA Section B2.1.29 describes the 

existing 10 CFR Part 50, Appendix J Program as consistent with GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J.” The LRA states that the 10 CFR Part 50, Appendix J Program 

manages cracking, loss of material, loss of leak tightness, loss of sealing, and loss of preload to 

ensure leakage through the primary containment, and systems and components penetrating the 

primary containment, does not exceed allowable leakage rate limits specified in the TS. 

The LRA also states that the program does not prevent degradation due to aging effects but 

provides measures for monitoring to detect the degradation before the loss of intended function. 

Periodic monitoring of leakage from the containment, containment isolation valves, and 

containment penetrations ensures proper maintenance and repairs can be performed before the 

loss of intended function. The LRA further states that the program is in accordance with the rule 

and guidance provided in 10 CFR Part 50 Appendix J, Option B, NRC Regulatory Guide 

(RG) 1.163, “Performance-Based Containment Leak-Test Program,” NEI 94-01, “Industry 

Guideline for Implementing Performance Based Option of 10 CFR Part 50 Appendix J,” and 

ANSI/American Nuclear Society (ANS) 56.8, “Containment System Leakage Testing 

Requirements.”

The LRA states that, as part of the integrated leak rate test (ILRT) pretest requirements, a 

general inspection of the accessible interior and exterior surfaces of the containment SCs is

performed for evidence of structural deterioration before initiating Type A testing. The LRA also 

states that these inspections are also performed during two other RFOs before the next Type A 

test, if the test interval has been extended to 10 years. The LRA further states that evidence of 

structural deterioration is corrected before the Type A test is performed. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S4. 

For the “scope of program,” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below.

The “scope of program” program element in GALL Report AMP XI.S4 recommends the program 

to include all containment boundary pressure-retaining components. However, during its audit, 

the staff found that Callaway’s FSAR-Standard Plant (SP) and ESP-SM-01001, “Containment 

Leakage Rate Testing Program,” procedure indicated that a number of penetrations and 

containment isolation valves have been excluded from local leak rate tests (LLRTs) or 

Type B and C testing. Furthermore, the audited plant’s operating experience database 

indicated that the applicant has substituted LLRTs in lieu of visual inspections (VT-2). It was not 

clear how the applicant proposed to manage the aging effects for any components not included 

in the 10 CFR Part 50, Appendix J, “scope of program,” program element. By letter dated 

July 9, 2012, the staff issued RAI B2.1.29-1 and requested the applicant to identify how aging 

effects will be managed for those components (valves, penetrations, and other components) 

that have been excluded from the 10 CFR Part 50 Appendix J Program, during the period of 

extended operation. In addition, the staff requested the applicant to also indicate which AMPs 

will be used to manage the aging effects for each of the excluded components or to justify why 

an AMP is not necessary for the period of extended operation.

In its response dated August 9, 2012, the applicant stated that pressure-retaining components 

whose failure (loss of leak-tightness) could contribute to an increase in the overall integrated 

leakage rate of the containment system are subjected to Type A tests. The applicant stated that 
AGING MANAGEMENT REVIEW RESULTS

3-88

containment penetrations that are provided with double seal closures and connections to allow 

for pressurization between the seals are subjected to Type B LLRTs. The applicant further 

stated that containment isolation valves are subjected to Type C LLRTs when they meet the 

following criteria: 

(1) [t]he penetrating system provides a direct connection between the inside and outside 

atmospheres of the containment under normal operation

(2) [t]he system is isolated by containment isolation valves that close automatically to effect 

containment isolation in response to a [containment isolation] signal

(3) [t]he system is not an ESF system consisting of a closed piping system outside of the 

containment

The applicant also stated that FSAR-SP, Section 6.2.6.1.2, states that “[f]or penetrations that 

are exempt from Type B or C tests, the leakage testing requirement of Appendix J is 

accomplished by the Type A test.” Accordingly, the applicant concluded that the scope of the 

10 CFR Part 50, Appendix J Program includes all pressure-retaining components of the 

containment structure, and all of these components will be age-managed under this program 

during the period of extended operation.

The staff reviewed the applicant’s response to RAI B2.1.29-1 and noted that the applicant’s 

enumerated selectivity criteria for LLRTs for the containment isolation valves (Type C tests) are 

identical and therefore in accordance with FSAR-SP Section 6.2.6.3, “Containment Isolation 

Valve Leakage Rate Tests (Type C tests).” However, the staff noted that the response did not 

address age management of the exempted or excluded pressure boundary components. It was 

not clear in the response how the applicant through the infrequent leakage testing of the overall 

containment, associated with 10 CFR Part 50, Appendix J, Option B Type A test, could identify 

aging effects of the exempted or excluded pressure boundary components. The staff needed 

clarification on the applicant’s approach and how it planned to manage aging effects of the 

exempted or excluded Type B and C tests of pressure boundary components from 10 CFR 50 

Appendix J LLRTs. By letter dated October 11, 2012, the applicant supplemented the original 

response to RAI B2.1.29-1 where it specified how containment isolation valves excluded from 

Type C testing will be age managed during the period of extended operation. The applicant 

stated that these valves are included in Type A leakage testing and are to be managed by 

AMPs based on their materials and environments applicable to their respective systems (e.g., 

RHR, RCS, CTMT, boron and safety injection) as detailed in Table 1 of the supplemental 

response to RAI B2.1.29-1. The applicant also stated that all of these valves are constructed of 

stainless steel and are exposed to an external environment of either plant indoor air or borated 

water leakage, neither of which produces any aging effect for stainless steel. Therefore, the 

applicant concluded that no aging management is required for the external surfaces. For the 

internal environments, the applicant stated that the valves are managed by Water Chemistry 

Program (evaluated in SER Section 3.0.3.1.2) , One-Time Inspection Program (evaluated in 

SER Section 3.0.3.1.8), ASME Section XI Inservice Inspection, Subsections IWB, IWC, and 

IWD Program (evaluated in SER Section 3.0.3.1.1), or Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program (evaluated in SER Section 3.0.3.2.12). 

The staff reviewed the supplemental response provided on October 11, 2012, and found that it 

did not adequately address Type B testing. By letter dated November 20, 2012, the applicant 

supplemented its response to RAI B2.1.29-1. In the supplemental response, the applicant 

stated that Type B tests are performed on the following containment penetrations: personnel 

access hatches; equipment hatch; fuel transfer tube; electrical penetrations; penetration 34, 
AGING MANAGEMENT REVIEW RESULTS

3-89

containment pressurization line; penetration 51, ILRT pressurization pressure sensing line; and 

penetrations 36, 50 and 68, maintenance spare air and electrical access penetrations. 

For penetrations other than those listed, the applicant stated that in addition to the ILRT, 

management of aging effects for all containment pressure-retaining components is performed 

by visual examination prior to ILRTs and at least once every 3 years. The applicant further 

stated that ASME Section XI, Subsection IWE Program performs a general visual examination 

of 100 percent of the accessible surfaces of the steel liner plate that includes penetrations, 

integral attachments, connection welds, and bolting and that any aging effects identified during 

these examinations will be managed in accordance with the applicant’s ASME Section XI, 

Subsection IWE Program. The staff’s evaluation of the ASME Section XI, Subsection IWE 

Program is documented in SER Section 3.0.3.2.15. 

The staff reviewed the applicant’s supplemental response and FSAR-SP Table 16.6-1, 

“Containment Isolation Valves,” and verified that the valves excluded from LLRTs, as listed in 

Table 1 of RAI B2.1.29-1 response are subject to Type A testing. The staff also reviewed 

FSAR-SP Section 1.2.4, “Nuclear Steam Supply System,” and verified that all of the nuclear 

steam supply system metal surfaces that are in contact with the reactor water, which include the 

excluded valves, are made of stainless steel and declared to be “corrosion-resistant” per 

FSAR-SP Section 3.1.6, “Fluid Systems.” The staff noted that the aging effects for the excluded 

containment isolation valves are to be managed by other AMPs, the adequacy of which are 

evaluated in this SER as noted above.

For the containment penetrations excluded from LLRTs, the staff reviewed FSAR-SP 

Section 16.24, “Inservice Inspection,” and confirmed that the containment pressure boundary 

inspections are done through procedure ESP-ZZ-01016, "ASME Section XI, IWE Containment 

Pressure Boundary Inspection." The staff audited the procedure and noted the comprehensive 

nature of the program regarding inspection of penetrations. The staff also noted that the 

program is not limited to evaluating the condition and performance of accessible penetrations 

but of inaccessible penetrations as well, acceptability of which rests on inspections and 

observations of relevant/nearby areas for prevalent conditions as indicators of degradation for 

the inaccessible areas/penetrations, in accordance with 10 CFR 50.55a(b)(2)(ix). The staff also 

noted that the procedure mandates inspection of 100 percent of the accessible containment 

pressure boundary areas to be performed at least triennially with increased frequency when 

deemed necessary. For any pressure boundary component not meeting the acceptance 

criteria, the procedure states that a corrective action report will be generated. Aging effects, 

during the period of extended operation, are to be managed per the applicant’s ASME 

Section XI, Subsection IWE Program as noted above and evaluated in SER Section 3.0.3.2.15. 

The staff finds the applicant’s response acceptable, because it clarifies the scope of the 

program and explains how the applicant will manage the aging effects for penetrations and 

containment isolation valves that have been excluded from the 10 CFR Part 50 Appendix J 

Program Option B for Type B and C testing. The staff’s concern described in RAI B2.1.29-1 is 

resolved. The staff determines that the “scope of the program” program element satisfies the 

criteria defined in the GALL Report and SRP-LR; therefore, the staff finds it acceptable.

Based on its audit of the applicant’s 10 CFR Part 50 Appendix J Program and review of the 

applicant’s response to RAI B2.1.29-1, the staff finds that program elements one through six for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S4. 
AGING MANAGEMENT REVIEW RESULTS

3-90

Operating Experience. LRA Section B2.1.29 summarizes operating experience related to the 

10 CFR Part 50, Appendix J Program. The LRA states that the 1999 ILRT showed that as-left 

leakage was 0.0577 weight percent per day (wt%/day), which is approximately 29 percent of the 

technical specification limit of 0.2 wt%/day. The LRA states that for Type B and C tests, the 

2008 total maximum path leakage rate (MXPLR) was 107,308.6 standard cubic centimeters per 

minute (SCCM) or 43 percent of the technical specification limit of 252,028 SCCM. The LRA 

also states that the 2010 MXPLR was 79,208.5 SCCM, or approximately 31 percent of the 

technical specification limit. The existence of a significant margin between the technical 

specifications allowable limits and the as-tested values for the primary containment boundary 

indicates that the containment and its penetration, associated valves, and ancillary equipment 

are adequately maintained, and their aging effects are effectively managed. 

The staff also audited Callaway’s operating experience database and noted the containment 

hatch leak rate test was not satisfactory and failed the retest in 2004. Upon notification, the 

control room entered the appropriate TS and initiated an immediate action to evaluate the 

overall containment leakage rate, verify that the door is closed within 1 hour, and the affected air 

lock is operable within 24 hours. The root cause analysis, however, indicated that these leak 

rate test failures were not age-related but due to improper shaft seal alignment, incorrect 

reassembly sequencing, and bumping of the shafts because of equipment traffic through the 

hatch during unit outages. 

The staff also confirmed that the applicant performed a review of NRC Generic Communications 

of industry operating experience and confirmed the applicability of the following INs:

• IN 85-08, “Industry Experience on Certain Materials Used in Safety-Related Equipment,” 

for loss of sealing due to wear, damage, erosion, tear, surface cracks, and other defects

• IN 2004-09, “Corrosion of Steel Containment and Containment Liner,” for loss of material 

due to erosion, general pitting, and crevice corrosion

• IN 2010-12, “Containment Liner Corrosion,” for loss of material caused by corrosion

These INs apply to the plant’s 10 CFR Part 50, Appendix J Program for management of the 

pertinent aging effects (loss or lack of sealing, corrosion, cracking, etc.). 

The staff reviewed operating experience information in the application and during the audit to

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience, and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.S4 was evaluated. 

FSAR Supplement. LRA Section A1.29 provides the FSAR supplement for the 10 CFR Part 50, 

Appendix J Program. The staff reviewed this FSAR supplement description of the program and 
AGING MANAGEMENT REVIEW RESULTS

3-91

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

finds that the information in the FSAR supplement is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s 10 CFR Part 50, Appendix J 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Masonry Walls

Summary of Technical Information in the Application. LRA Section B2.1.30 describes the 

existing Masonry Wall Program as consistent with GALL Report AMP XI.S5, “Masonry Walls.” 

The LRA states that the Masonry Wall Program addresses concrete masonry walls in proximity 

to safety-related systems. The LRA further states that the walls are monitored for cracking 

during structural inspections implemented as part of the Structures Monitoring Program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S5.

For the “acceptance criteria” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below.

The “acceptance criteria” program element in GALL Report AMP XI.S5 recommends that further 

evaluation be conducted if the extent of cracking and loss of material is sufficient to impact the 

intended function of the wall or invalidate its evaluation basis. However, during its audit, the 

staff found that the applicant’s Masonry Walls Program provided quantitative acceptance 

criteria, but no basis was provided for the acceptance criteria or how the criteria related to the 

recommended acceptance criteria in GALL Report AMP XI.S5. Therefore, by letter dated 

July 9, 2012, the staff issued RAI B2.1.30-1 requesting that the applicant provide the basis for 

the acceptance criteria and explain how the criteria meet the recommendations in program 

element six, “acceptance criteria,” of the GALL Report AMP XI.S5.

In its response dated August 9, 2012, the applicant stated that the acceptance criteria described 

in the plant procedure are based on the criteria for concrete provided in ACI 349.3R, modified 

as necessary for masonry construction. The applicant further noted that procedures require an 

action request be written when other than very minor degradation is noted on the inspection 

report. 

The staff reviewed the applicant’s response and noted that plant procedures require an action 

request be created whenever greater than minor degradation is noted. This is similar to the 

guidance provided in program element six, “acceptance criteria,” of the GALL Report 

AMP XI.S5, which recommends further evaluation if the extent of cracking and loss of material 

is sufficient to impact the intended function of the wall or invalidate its evaluation basis. The 

staff finds the applicant’s response acceptable because it states that the acceptance criteria are 

based on an accepted reference (ACI 349.3R), and it further states that any degradation beyond 
AGING MANAGEMENT REVIEW RESULTS

3-92

minor is identified for further review, as recommended in the GALL Report. The staff’s concern 

described in RAI B2.1.30-1 is resolved.

Based on its audit of the applicant’s Masonry Walls Program and review of the applicant’s 

response to RAI B2.1.30-1, the staff finds that program elements one through six for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.S5.

Operating Experience. LRA Section B2.1.30 summarizes operating experience related to the 

Masonry Walls Program. The LRA states that a review of structures monitoring reports from the 

last 10 years indicates that in-scope masonry walls are in good condition. Instances of cracking 

in masonry walls have been identified, but none have been severe enough to require corrective 

actions. These indications of degradation are identified and recorded for future trending 

purposes.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.S5 was evaluated. 

FSAR Supplement. LRA Section A1.30 provides the FSAR supplement for the Masonry Walls 

Program. The staff reviewed this FSAR supplement description of the program against the 

recommended description for this type of program as described in SRP-LR Table 3.0-1 and 

noted that the maximum inspection interval of 5 years was not discussed in the summary 

description. The licensing basis for this program for the period of extended operation may not 

be adequate if the applicant does not incorporate this information into its FSAR supplement. 

By letter dated July 9, 2012, the staff issued RAI B2.1.31-1 requesting that the applicant include 

a discussion of the inspection interval in the FSAR supplement summary description.

In its response dated August 9, 2012, the applicant stated that masonry wall inspections are 

performed at intervals of no more than 5 years. The applicant also revised the FSAR 

supplement summary description to include the 5-year inspection interval. 

The staff finds the applicant’s response acceptable because the applicant updated the FSAR 

supplement description to include the necessary level of detail regarding the recommended 

5-year inspection interval. Therefore, based on the applicant’s response, the FSAR supplement 

for the Masonry Walls Program is an acceptable summary of the program and is consistent with 

the corresponding program description in SRP-LR Table 3.0-1. The staff’s concern described in 

RAI B2.1.31-1 is resolved. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

August 9, 2012, is an adequate summary description of the program.
AGING MANAGEMENT REVIEW RESULTS

3-93

Conclusion. On the basis of its audit and review of the applicant’s Masonry Wall Program, the 

staff concludes that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. The staff concludes that the applicant has demonstrated that 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for this AMP and concludes 

that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.1.15 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

Summary of Technical Information in the Application. LRA Section B2.1.32 describes the 

existing RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Program as consistent with GALL Report AMP XI.S7, “RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants.” The LRA states that the AMP 

is implemented as part of the Structures Monitoring Program and manages the following aging 

effects:

• cracking; loss of bond; and loss of material (spalling, scaling)

• increase in porosity and permeability; loss of strength

• loss of material

• loss of material (spalling, scaling) and cracking

• loss of material; loss of form

The LRA also states that the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program proposes to manage structural steel and structural bolting 

associated with water-control structures. The LRA further states that Callaway performs algae 

treatment and riprap inspections along the ultimate heat sink (UHS) retention pond, and 

maintains benchmarks for monitoring settlement in any of the Category 1 structures, including 

the UHS cooling tower.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S7.

Based on its audit of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program, the staff finds that program elements one 

through six for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.S7.

Operating Experience. LRA Section B2.1.32 summarizes operating experience related to the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program. The LRA provides the following two examples as objective evidence that this AMP is 

capable of both monitoring and detecting the aging effects associated with the program:

• In 2005, water that entered open electrical boxes that were part of the abandoned 

lighting system, corroded the embedded conduits in the concrete wall, eventually 

causing spalling on the plant north face of the wall separating the ‘A’ and ‘B’ UHS fan 

deck rooms. The spalled area was patched with cement grout in 2006.
AGING MANAGEMENT REVIEW RESULTS

3-94

• Similar spalling was noted on the south wall in the ‘D’ UHS cooling tower due to 

rainwater seeping through an abandoned electrical conduit. To prevent recurrence, 

before installing the grout patch, a hole was drilled to drain any water remaining in the 

abandoned conduits.

The LRA states that occurrences that would be identified under the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program, will be evaluated to 

ensure there is no significant impact to safe operation of the plant and corrective actions will be 

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. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.S7 was evaluated.

FSAR Supplement. LRA Section A1.32 provides the FSAR supplement for the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program. The 

staff reviewed this FSAR supplement description of the program against the recommended 

description for this type of program as described in SRP-LR Table 3.0-1 and noted that the 

maximum inspection interval of 5 years was not discussed in the summary description. The 

licensing basis for this program for the period of extended operation may not be adequate if the 

applicant does not incorporate this information into its FSAR supplement. By letter dated 

July 9, 2012, the staff issued RAI B2.1.31-1 requesting that the applicant include a discussion of 

the inspection interval in the FSAR supplement summary description.

In its response dated August 9, 2012, the applicant stated that inspections of water-control 

structures are performed at intervals of no more than 5 years. The applicant also revised the 

FSAR supplement summary description to include the 5-year inspection interval. 

The staff finds the applicant’s response acceptable because the applicant updated the FSAR 

supplement description to include the necessary level of detail regarding the recommended 

5-year inspection interval. Therefore, based on the applicant’s response, the FSAR supplement 

for the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program, is an acceptable summary of the program and is consistent with the corresponding 

program description in SRP-LR Table 3.0-1. The staff’s concern described in RAI B2.1.31-1 is 

resolved.

The staff finds that the information in the FSAR supplement, as amended by letter dated 

August 9, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program, the staff concludes 
AGING MANAGEMENT REVIEW RESULTS

3-95

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 FSAR 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 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

Summary of Technical Information in the Application. LRA Section B2.1.37 describes the new 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program as consistent with GALL Report AMP XI.E6, “Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The 

LRA states that the Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program manages increased resistance of connection to ensure 

that either aging of metallic cable connections does not occur and that the existing preventive 

maintenance program is effective such that a periodic inspection is not required. The LRA also 

states that the one-time test confirms the absence of age-related degradation of cable 

connections due to thermal cycling, ohmic heating, electrical transients, vibration, chemical 

contamination, corrosion, or oxidation to ensure that electrical cable connections not subject to 

the EQ requirements of 10 CFR 50.49 and within the scope of license renewal are capable of 

performing their intended function.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.E6. 

For the “acceptance criteria” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below.

The “acceptance criteria” program element in GALL Report AMP XI.E6, “Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements,” 

recommends that cable connections should not indicate abnormal temperature for the 

application when thermography is used. However, during its audit, the staff found that the 

applicant’s plant aging management program evaluation report for the Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program 

states that the acceptance criteria for thermography testing will be based on the temperature 

rise above the reference temperature. The reference temperature will be ambient temperature 

or the baseline temperature data from the same type of connections being tested. 

The applicant referenced procedure EDP-ZZ-07001 Section 4.3.13. Section 4.3.13 of this 

procedure states that the acceptance criteria for the review of thermography result on the 

one-time inspection of cable connections will be based on the temperature rise above a 

reference temperature. The reference temperature will be ambient temperature or the baseline 

temperature data from the connections under test. The procedure does not specify the 

acceptance criteria for thermography inspections. The applicant stated that when the test 

acceptance criteria are not met, it will perform an evaluation that may include changes to the 

one-time inspection, increased inspection frequency, and replacement or repair of the affected 

connections. It is not clear to the staff that these statements are consistent because procedure 

EDP-ZZ-07001 Section 4.3.13 does not specify acceptance criterion for thermography 

inspections. By letter dated July 9, 2012, the staff issued RAI B2.1.37-1 requesting that the 
AGING MANAGEMENT REVIEW RESULTS

3-96

applicant describe the specific acceptance criteria for thermography or reference a plant-specific 

procedure that specifies the acceptance criteria for thermography inspection. 

In its response dated August 9, 2012, the applicant stated that the first sentence in procedure 

EDP-ZZ-07001 markup, paragraph 4.1.11, has been revised to read: “A one-time inspection of 

a sample of cable connections shall be conducted using thermography per EDP-ZZ-01113.” 

The applicant also stated that “EDP-ZZ-01113 specifies thermography inspection action levels 

for temperatures above a reference temperature. Element 6 AMP basis document B2.1.37 has 

been revised to identify the action levels section of EDP-ZZ-01113 for determining actions to be 

taken based on observed temperature rises recorded during the thermography inspection.”

The staff finds the applicant’s response acceptable because the applicant has revised 

procedure EDP-ZZ-01113 and basis document B2.1.37 to include thermography inspection 

action levels and actions to be taken for temperature rise measured above reference 

temperature during thermography inspections. The staff’s concern described in RAI B2.1.37-1 

is resolved.

Based on its audit and review of the applicant’s response to RAI B2.1.37-1, the staff finds that 

program elements one through six for which the applicant claimed consistency with 

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

AMP XI.E6.

Operating Experience. LRA Section B2.1.37 summarizes operating experience related to the 

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program. LRA Section B2.1.37 summarizes the operating experience related to 

this AMP as follows:

Callaway routinely performs infrared thermography on electrical components and 

connections. A review of plant operating experience identified scans where 

electrical cable connections showed thermal anomalies. The connections 

associated with these thermal anomalies were cleaned and re-tightened. No loss 

of equipment intended function has occurred because of these thermal 

anomalies. 

Operating experience with the Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements [P]rogram has 

identified loose connections prior to loss of function. Occurrences that would be 

identified under the Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements [P]rogram will be evaluated to ensure 

there is no significant impact to safe operation of the plant and corrective actions 

will be taken to prevent recurrence. Guidance for re-evaluation, repair, or 

replacement is provided for locations where aging is found. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.
AGING MANAGEMENT REVIEW RESULTS

3-97

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E6 was evaluated.

FSAR Supplement. LRA Section A1.37 provides the FSAR supplement for the Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. 

The staff reviewed this FSAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted that 

the applicant committed (Commitment No. 28) to implement the new Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program 

six months before entering the period of extended operation for managing aging of applicable 

components. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Electrical Cable Connections 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff 

concludes that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Monitoring of Neutron-Absorbing Materials Other than Boraflex 

Summary of Technical Information in the Application. LRA Section B2.1.38 describes the new 

Monitoring of Neutron-Absorbing Materials Other than Boraflex Program as consistent with 

GALL Report AMP XI.M40, “Monitoring of Neutron-Absorbing Materials Other than Boraflex.” 

The LRA states that the Monitoring of Neutron-Absorbing Materials Other than Boraflex 

Program manages reduction of neutron-absorbing capacity, change in dimensions, and loss of 

material to ensure that aging of the Boral® neutron-absorbing material used in the spent fuel 

storage racks does not invalidate the criticality analysis of the spent fuel pool. The LRA states 

that the program is a monitoring program that performs inspections and in-situ testing of the 

Boral® panels in the spent fuel pool. The program testing includes areal density measurements 

of the boron-10 in the Boral® panels, and visual inspections of the Boral panel sheaths to look 

for geometry changes caused by bulging or swelling. The LRA also states that the results are 

evaluated against the acceptance criteria and previous inspections to determine whether 

corrective actions are required. The LRA further states that if corrective actions are required, 

appropriate actions are taken to ensure the required 5 percent subcriticality margin is 

maintained. In addition the LRA states that the Boral® panels in the spent fuel pool will be 

inspected on a 10-year frequency.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M40.

Based on its audit of the applicant’s Monitoring of Neutron-Absorbing Materials Other than 

Boraflex Program, the staff finds that program elements one through six for which the applicant 
AGING MANAGEMENT REVIEW RESULTS

3-98

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M40.

Operating Experience. LRA Section B2.1.38 summarizes operating experience related to the 

Monitoring of Neutron-Absorbing Materials Other than Boraflex Program. The LRA states that a 

search of Callaway historical information found no reduction of neutron-absorbing capacity, 

change in dimensions, and loss of material for Boral®. The LRA also states that occurrences 

that would be identified under the program will be evaluated to ensure that there is no significant 

impact to safe operation of the plant and corrective actions will be taken to prevent recurrence. 

The LRA further states that industry and plant-specific operating experience will be evaluated in 

the development and implementation of the program.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M40 was evaluated. 

FSAR Supplement. LRA Section A1.38 provides the FSAR supplement for the Monitoring of 

Neutron-Absorbing Materials Other than Boraflex Program. The staff reviewed this FSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed 

(Commitment No. 29) to implement the new Monitoring of Neutron-Absorbing Materials Other 

than Boraflex Program six months before entering the period of extended operation for 

managing aging of applicable components.

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Monitoring of 

Neutron-Absorbing Materials Other than Boraflex Program, the staff concludes that those 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent. The staff concludes that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR 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 Metal Enclosed Bus 

Summary of Technical Information in the Application. LRA Section B2.1.39 describes the new 

Metal Enclosed Bus Program as consistent with GALL Report AMP XI.E4, “Metal Enclosed 

Bus.” The LRA states that the Metal Enclosed Bus Program manages age-related degradation 

of in-scope non-segregated phase metal enclosed buses. The LRA also states that bus 
AGING MANAGEMENT REVIEW RESULTS

3-99

enclosure assemblies (internal and external), bus bar insulation, bus bar insulating supports, 

and bus bar bolted connections are included. The LRA further states that the metal enclosed 

buses within the scope of this program are the metal enclosed buses that provide power to the 

service water pumps. In addition the LRA states that the service water pumps provide service 

water to fire protection hose stations in the ESW pump house through ESW piping. 

Staff Evaluation: During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared elements one through six of the applicant’s program to the 

corresponding elements of GALL Report AMP XI.E4. 

Based on its audit, the staff finds that program elements one through six for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.E4.

Operating Experience. LRA Section B2.1.39 summarizes operating experience related to the 

Metal Enclosed Bus Program. The LRA states that the Callaway CAP was searched to 

determine if metal enclosed bus failures have occurred. The LRA also states that Callaway’s 

operating experience with the Metal Enclosed Bus Program has not identified any corrective 

actions related to the buses within the scope of license renewal. The LRA further states that 

“[o]ccurrences that would be identified under the Metal Enclosed Bus [P]rogram will be 

evaluated to ensure there is no significant impact to safe operation of the plant and corrective 

actions will be taken to prevent recurrence. Guidance for reevaluation, repair, or replacement is 

provided for locations where aging is found.” In addition the LRA states that industry and 

plant-specific operating experience will be evaluated in the development and implementation of 

the program.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E4 was evaluated. 

FSAR Supplement. LRA Section A1.39 provides the FSAR supplement for the Metal Enclosed 

Bus Program. The staff reviewed this FSAR supplement description of the program and noted 

that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff also 

noted that the applicant committed (Commitment No. 30) to implement the new Metal Enclosed 

Bus Program six months before entering the period of extended operation for managing aging of 

applicable components. 

The staff finds that the information in the FSAR supplement, as amended by letters dated 

April 25, 2012, and February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Metal Enclosed Bus 

Program, the staff concludes that those program elements for which the applicant claimed 
AGING MANAGEMENT REVIEW RESULTS

3-100

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 FSAR 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 Environmental Qualification (EQ) of Electric Components 

Summary of Technical Information in the Application. LRA Section B3.2 describes the existing

EQ of Electric Components Program as consistent with GALL Report AMP X.E1, 

“Environmental Qualification (EQ) of Electric Components.” The applicant stated the Callaway 

EQ of Electric Components Program manages component thermal, radiation, and cyclical aging 

through the use of aging evaluations based on 10 CFR 50.49(f) qualification methods.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP X.E1. 

The staff reviewed the applicant’s rockbestos cable EQ qualification. These cables use 

chemically cross-linked polyethylene cable, under the trade name “Firewall III,” for use in 

nuclear applications. Institute of Electrical and Electronic Engineers (IEEE) Standard 383-1974, 

“Standard for Qualifying Class IE Equipment for Nuclear Power Generating Stations,” identifies 

cable sizes that are considered representative of four different cable categories. The staff found 

that each of Callaway’s test specimens is within the range of sizes considered by IEEE 

Standard 383-1974 and are representative of the respective cable types for a demonstration of 

qualification. The staff concluded that the test specimens are considered representative of the 

insulation types for the rockbestos “Firewall III” cables installed at Callaway.

In the thermal aging evaluation section PQE#E-057-00067P01, the applicant stated that cables 

are installed in various areas at Callaway and are subjected to a worst-case normal ambient 

temperature of 49 o

C (120 oF) (represented by the containment operating floor/steam generator 

loop compartment), plus 10 o

C (18 oF) for heat rise because of energization of the cable. The 

applicant also stated that cable specimens were thermally aged for 941 hours at 150 o

C 

(302 o

F), plus an additional 12 hours at 148 oC (298 oF). The applicant further stated that the 

additional 12 hours of aging time at 148 o

C (298 oF) will be used to demonstrate margin and will 

not be used in the determination of qualified life. The applicant identified the chemically 

cross-linked polyethylene material as having an activation energy of 1.3412 eV. Using the 

thermal aging time and temperature listed above with an activation energy of 1.3412 eV and a 

total conductor temperature of 59 o

C (138 oF), these cables are qualified for greater than 

60 years at Callaway. In the applicant’s analysis, significant margin exists since the cables 

remain qualified for 60 years as long as the insulation temperature is less than 87.9159 o

C 

(190.23 o

F). 

By letter dated September 20, 2012, the applicant provided LRA Amendment 10 which included 

an exception to the “scope of program” program element by adding environmentally qualified 

mechanical components to the scope of the EQ of Electric Components Program. The staff 

reviewed the portions of the “scope of program” program element associated with an exception 

to determine if the program will be adequate to manage the aging effects for which it is credited. 

The staff’s evaluation of this exception follows.
AGING MANAGEMENT REVIEW RESULTS

3-101

Exception 1. LRA Section B3.2, as amended by letter dated September 20, 2012, states an 

exception to the “scope of program” program element. In this exception, the applicant stated 

that the EQ of Electric Components Program takes exception to the scope of program, which is 

limited in the GALL Report to electrical equipment to include the aging management of the 

qualified life of safety-related mechanical components located in harsh environments. The staff 

reviewed this exception against the corresponding program element in GALL Report AMP 

X.E1 and finds it acceptable because a plant-specific TLAA for mechanical components 

qualified to Criterion 4 of Appendix A to 10 CFR Part 50 was established by the applicant in 

accordance with SRP-LR Sections 4.4.1 and 4.7. The inclusion of environmentally qualified 

mechanical components in LRA AMP B3.2 is acceptable in that LRA Table 3.6.2-1 identifies the 

same materials, environment, and aging effects requiring aging management for both electrical 

equipment environmentally qualified under 10 CFR 50.49 and the mechanical components 

qualified under Criterion 4 of Appendix A to 10 CFR Part 50.

Based on its audit of the applicant’s EQ of Electric Components Program, and review of the 

applicant’s response to RAI 4.4-1 provided in SER Section 4.4.2, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP X.E1. The staff also 

reviewed the exception associated with the “scope of program” program element, and its 

justification, and it finds that the AMP, with the exception, is adequate to manage the applicable 

aging effects.

Operating Experience. LRA Section B3.2 summarizes operating experience related to the EQ 

of Electric Components Program. 

In CAR No. 200904936, the applicant observed main steam isolation valve area temperature 

exceeded 49 °C (120 °F) (design) at least six times in a 2-year period. The applicant noted that 

the EQ impact was not evaluated and qualified life was not recalculated. The applicant stated 

that “[q]ualification reevaluation for components installed in the main steam isolation valve is 

required to ensure the degradation because of elevated temperature is accounted for, and the 

component is replaced, before expiring life.” The applicant also stated that the EQ engineer 

determined that the brief temperature spikes did not impact qualified life.

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicable aging effects, and industry and plant-specific operating experience, 

were reviewed by the applicant. As discussed in the audit report, the staff conducted an 

independent search of the plant operating experience information to determine if the applicant 

had adequately evaluated and incorporated operating experience related to this program. 

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, resulting in the issuance of an RAI, as discussed below.

Although the staff identified two self-assessment reports, the staff did not identify any EQ of 

Electric Components Program health reports in its review of EQ operating experience. Multiple 

EQ health reports, issued periodically, can be used to identify adverse trends in EQ of Electric 

Components Program performance. In addition, CAR No. 201104724 identified plant program 

health report and program notebook as newly added requirements for the EQ of Electric 

Components Program. By letter dated August 23, 2012, the staff issued RAI B3.2-1 requesting 

the applicant to (a) provide the schedule for performing self assessment reports and EQ health 

reports consistent with LRA Section B3.2, and (b) provide additional operating experience 

(i.e., followup actions identified by the self-assessments (2004 and 2010), including corrective 

actions) that demonstrates the effectiveness of the EQ of Electric Components Program. 
AGING MANAGEMENT REVIEW RESULTS

3-102

In its response, dated September 20, 2012, the applicant stated that the next self-assessment of 

the EQ of Electric Components Program is scheduled for 2014. The applicant also stated that, 

in accordance with plant procedures, self-assessments and benchmarks for the EQ of Electric 

Components Program are performed on an as-needed frequency, as agreed upon by the 

supervisor and program owner. The applicant also stated that, in accordance with plant 

procedures, health reports are prepared for the EQ of Electric Components Program quarterly, 

with the third quarter report due October 2012. 

In addition, the applicant provided a summary of self-assessments performed in 2004 and 2010, 

noting that bench strength was considered inadequate and that the EQ of Electric Components 

Program did not have provisions for a health report. To address the bench strength 

inadequacies noted in these self-assessments, the applicant stated that Callaway currently has 

six engineers qualified for the EQ of Electric Components Program, four of whom perform these 

responsibilities regularly. In addition, the applicant stated that corrective actions also were 

implemented that now provide for procedural requirements for the development of an EQ of 

Electric Components Program health report on a quarterly basis. The applicant also noted that 

the 2010 self-assessment identified only minor documentation issues already being resolved. 

The applicant further stated that the 2010 self-assessment did not identify any adverse 

conditions that resulted in premature aging. Additional program enhancements noted by the 

applicant included training for personnel interfacing with the EQ of Electric Components 

Program and first line supervisor training. 

The staff finds the applicant’s response acceptable because the applicant has established 

schedules for EQ of Electric Components Program health reports, self-assessments, and 

benchmarking. The applicant also provided additional operating experience, including 

corrective actions implemented to improve program effectiveness. The staff’s concern 

described in RAI B3.2-1 is resolved.

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

RAI B.3.2-1, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective action. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP X.E1 was evaluated.

FSAR Supplement. LRA Section A2.2 provides the FSAR supplement for the EQ of Electric 

Components Program. The staff reviewed this FSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

September 20, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s EQ of Electric Components 

Program, the staff concludes 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 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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

3-103

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or Enhancements 

In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with 

the GALL Report, with exceptions or enhancements:

• boric acid corrosion

• bolting integrity

• open-cycle cooling water system

• closed treated water systems

• inspection of overhead heavy load and light load (related to refueling) handling systems

• fire protection

• fire water system

• aboveground metallic tanks

• fuel oil chemistry

• reactor vessel surveillance

• selective leaching

• inspection of internal surfaces in miscellaneous piping and ducting components

• lubricating oil analysis

• buried and underground piping and tanks

• ASME Section XI, Subsection IWE

• ASME Section XI, Subsection IWF

• structures monitoring

• protective coating monitoring and maintenance program

• insulation material for electrical cables and connections not subject to 10 cfr 50.49 

environmental qualification requirements

• insulation material for electrical cables and connections not subject to 10 cfr 50.49 

environmental qualification requirements used in instrumentation circuits

• inaccessible power cables not subject to 10 cfr 50.49 environmental qualification 

requirements

• fatigue monitoring

• concrete containment tendon prestress

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 if they were acceptable and adequate. The results of the staff’s audit and reviews 

are documented in the following sections.
AGING MANAGEMENT REVIEW RESULTS

3-104

3.0.3.2.1 Boric Acid Corrosion 

Summary of Technical Information in the Application. LRA Section B2.1.4 describes the 

existing Boric Acid Corrosion Program as consistent, with enhancements, with GALL Report 

AMP XI.M10, “Boric Acid Corrosion.” The LRA states that the Boric Acid Corrosion Program 

addresses mechanical, electrical, and structural components exposed to borated water or 

reactor coolant leakage to manage loss of material and increased resistance of connection. 

The LRA also states that the Boric Acid Corrosion Program proposes to manage these aging 

effects through implementation of recommendations of NRC Generic Letter (GL) 88-05, “Boric 

Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants,” and 

WCAP-15988-NP, “Generic Guidance for an Effective Boric Acid Inspection Program for 

Pressurized Water Reactors.” The LRA further states that the Boric Acid Corrosion Program 

includes inspections, identification of leak paths, visual inspection of adjacent SCs, cleaning, 

evaluations, and tracking and trending of existing and repaired leaks. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M10. 

The staff also reviewed the portions of the “scope of program,” “detection of aging effects,” and 

“corrective actions” program elements associated with enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these enhancements follows.

Enhancement 1. LRA Section B2.1.4 states an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to include steel, copper alloy greater than 15 percent zinc, and aluminum as materials that are 

susceptible to boric acid corrosion. The “scope of program” program element of GALL Report 

AMP XI.M10 states that the program covers any structures or components on which boric acid 

corrosion may occur (e.g., steel, copper alloy greater than 15 percent zinc, and aluminum). By 

letter dated October 24, 2012, the applicant submitted LRA Amendment 13, removing 

enhancement 1 from the Boric Acid Corrosion Program. The applicant stated that it completed 

the enhancement to include steel, copper alloy greater than 15 percent zinc, and aluminum as 

materials that are susceptible to boric acid corrosion. The staff reviewed this enhancement 

against the corresponding program element in GALL Report AMP XI.M10 and finds it 

acceptable because it makes the program consistent with the GALL Report recommendations 

by providing details in the inspection procedures to ensure that components constructed of 

materials susceptible to boric acid corrosion are appropriately addressed during inspections and 

engineering evaluations of borated water leakage. 

Enhancement 2. LRA Section B2.1.4 states an enhancement to the “detection of aging effects” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

so that system engineers will inspect for signs of boric acid residue when performing system 

walkdowns. The “detection of aging effects” program element of GALL Report AMP XI.M10 

states that the program includes interfaces with other site programs and activities, such that 

borated water leakage that is encountered by means other than the monitoring and trending 

activities of this program is evaluated and corrected. By letter dated October 24, 2012, the 

applicant submitted LRA Amendment 13, removing enhancement 2 from the Boric Acid 

Corrosion Program. The applicant stated that it completed the enhancement to revise 

procedures so that system engineers will inspect for signs of boric acid residue when performing 

system walkdowns. The staff reviewed this enhancement against the corresponding program 
AGING MANAGEMENT REVIEW RESULTS

3-105

element in GALL Report AMP XI.M10 and finds it acceptable because it makes the program 

consistent with the GALL Report recommendations by providing for the discovery of borated 

water leakage and the associated followup evaluations through activities other than those 

established to specifically detect such leakage. 

Enhancement 3. LRA Section B2.1.4 states an enhancement to the “corrective actions” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to specify that the corrective actions taken by the program will include a consideration to modify 

the present design or operating procedures to mitigate or prevent recurrence of aging effects 

caused by borated water leakage. The applicant also stated that consideration will be given to 

modifications that (a) reduce the possibility of primary coolant leaks at locations where they may 

cause corrosion damage and (b) entail the use of corrosion resistant materials or the application 

of protective coatings or claddings. The “corrective actions” program element of GALL Report 

AMP XI.M10 states that corrective actions to prevent recurrences of degradation caused by 

borated water leakage should be included in the program. The GALL Report also states that 

these corrective actions include modifications to the present design or operating procedures that 

(a) reduce the probability of primary coolant leaks at locations where they may cause corrosion 

damage and (b) entail the use of corrosion resistant materials or the application of protective 

coating or claddings. By letter dated October 24, 2012, the applicant submitted LRA 

Amendment 13, removing enhancement 3 from the Boric Acid Corrosion Program. The 

applicant stated that it completed the enhancement to revise procedures to specify the 

corrective actions activities described above. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M10 and finds it acceptable because it 

makes the program consistent with the GALL Report recommendations by including the 

consideration of modifications to prevent recurrences of boric acid corrosion. 

Based on its audit of the applicant’s Boric Acid Corrosion Program, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M10. In addition, 

the staff reviewed the enhancements associated with the “scope of program,” “detection of 

aging effects,” and “corrective actions” program elements and finds that, when implemented,

they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.4 summarizes operating experience related to the 

Boric Acid Corrosion Program. The LRA states that stress-corrosion cracking was found in 

structural supports in the vicinity of a boric acid leak in the pressurizer spray line and was 

attributed, in part, to chlorides that likely originated during original construction. As a corrective 

action, the pressurizer cubical and the seal table were added to the quarterly walkdown of 

containment. The LRA also states that by the end of spring 2011, Callaway had an average 

age of open work orders on borated water leaks of approximately 10.5 months, down from 

approximately 25 months in 2008. The LRA further states that the program was revised 

between fall 2010 and spring 2011 to include (1) the addition of requirements to ensure boric 

acid evaluations were performed in a timely manner (with due dates for evaluation of 

susceptible materials); (2) increased training of plant personnel to identify leaks; and 

(3) guidance on the use of trending indicators, such as RCS leakage rate, containment cooling 

fouling, and containment air monitors. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 
AGING MANAGEMENT REVIEW RESULTS

3-106

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation. The staff noted that the current effectiveness of the program is 

demonstrated by the significant downward trend in the average age of open work orders on 

borated water leaks, which coincided with the program revisions in 2010 and 2011 that 

strengthened training to identify leaks and the performance of timely evaluations of those leaks.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M10 was evaluated.

FSAR Supplement. LRA Section A1.4 provides the FSAR supplement for the Boric Acid 

Corrosion Program. The staff reviewed this FSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant completed Commitment No. 3 to implement the enhancements to 

the program before the period of extended operation. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

October 24, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Boric Acid Corrosion 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed LRA Amendment 13, 

which revised the LRA to document that Commitment No. 3 was completed. 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 

FSAR 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 Bolting Integrity 

Summary of Technical Information in the Application. LRA Section B2.1.8 describes the 

existing Bolting Integrity Program as consistent, with enhancements, with GALL Report 

AMP XI.M18, “Bolting Integrity.” The LRA states that the existing Bolting Integrity Program 

manages cracking, loss of material, and loss of preload for pressure retaining bolting. The 

program includes preload control, selection of bolting material, use of lubricants or sealants, and 

performance of periodic inspections for indication of aging effects. The LRA also states that the 

general practices established in this program are consistent with NUREG-1339, “Resolution of 

Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,”

EPRI-NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants” (with the 

exceptions noted in NUREG-1339 for safety-related bolting) and EPRI TR-104213, “Bolted Joint 

Maintenance and Applications Guide,” which are recommended by the GALL Report. 
AGING MANAGEMENT REVIEW RESULTS

3-107

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M18. 

For the “parameters monitored or inspected” and “detection of aging effects” program elements, 

the staff determined the need for additional information, which resulted in the issuance of RAIs, 

as discussed below.

The “parameters monitored or inspected” program element of the GALL Report AMP XI.M18 

recommends that the program monitor the effects of aging on the intended function of bolting 

and that components should be inspected for leakage, loss of material, cracking, and loss of 

preload. However, the staff noted that between 1985 and 1987, the applicant installed seal cap 

enclosures on four swing check valves to mitigate gasket leakage from the bolted 

body-to-bonnet flange joint. The use of seal cap enclosures as mitigation for leakage may 

prevent the bolting within the enclosure from being managed for loss of preload, cracking, and 

loss of material aging effects since the enclosure prevents direct inspection of the bolted joint. 

The known seal cap enclosures have since been removed; however, it is not clear to the staff 

whether additional seal cap enclosures have been installed or if seal cap enclosures are still 

used at the site to mitigate leakage. Furthermore, the staff requested clarification on how the 

use of seal cap enclosures is controlled such that aging effects can be managed in the period of 

extended operation. By letter dated July 5, 2012, the staff issued RAI B2.1.8-1 requesting that 

the applicant clarify whether seal cap enclosures are still in use at the plant and how aging 

effects will be managed if they are. 

In its response dated August 6, 2012, the applicant stated that it had previously installed seal 

cap enclosures on two check valves in the normal charging line and two check valves in the 

alternate charging line at Callaway. The applicant stated that the seal cap enclosures were 

removed in 2002 and 2004, and no additional seal cap enclosures are currently installed at 

Callaway. The staff finds the applicant’s response acceptable because the applicant has 

confirmed that there are no additional seal cap enclosures at the site, and, therefore, aging 

management of bolting within seal cap enclosures will not be needed. Furthermore, the staff 

noted that NRC IN 2012-15, “Use of Seal Cap Enclosures to Mitigate Leakage from Joints that 

Use A-286 Bolts,” dated August 9, 2012, includes a detailed account of the four check valves 

described above and stated that all four valves were replaced or repaired to their original 

condition such that no aging effects resulting from the seal cap enclosures exists. The staff’s 

concern described in RAI B2.1.8-1 is resolved.

The “detection of aging effects” program element of the GALL Report AMP XI.M18 recommends 

periodic inspections of closure bolting for signs of leakage to ensure the detection of age-related 

degradation. However, GALL Report AMP XI.M18 does not include specific guidance for 

submerged bolting for which inspections for leakage are not practical. In a letter dated 

August 29, 2013, the applicant revised the LRA to include several new AMR items for pump 

closure bolting that is submerged in water or fuel oil, for which loss of material and loss of 

preload were identified as aging effects requiring management. Depending on the system in 

which the bolting resided, the applicant proposed to manage loss of material with the 

Open-Cycle Cooling Water System Program, Fuel Oil Chemistry Program, or the External 

Surfaces Monitoring of Mechanical Components Program. The applicant also proposed to 

manage loss of preload for all submerged bolting with the Bolting Integrity Program.

The staff noted that the applicant’s programs for managing aging of submerged bolting lacked 

information regarding how degradation will be detected, given the fact that the submerged 
AGING MANAGEMENT REVIEW RESULTS

3-108

environment limits accessibility and the ability to detect bolted joint leakage. By letter dated 

December 2, 2013, the staff issued RAI 3.3.2-2, requesting that the applicant state the 

parameters that will be inspected, whether inspections will or will not occur in the submerged 

environment, and the frequency of inspections. 

In its response dated January 16, 2014, as revised by letter dated February 14, 2014 (which 

removed the submerged fire pumps from the scope of license renewal), the applicant revised 

the AMR items associated with submerged pump closure bolting to state that loss of material 

will be managed with the Bolting Integrity Program, rather than the programs initially identified. 

The applicant described the program’s aging management activities for loss of material as 

follows:

1. Essential service water (ESW) system:

• The bolting will be visually inspected for degradation during dewatering of the essential 

service water intake bays, which is performed every four refueling outages (6 years).

• The ESW pumps are tested quarterly and are repaired or refurbished when prompted by 

trending of pump parameters, such as pressure, flow, and vibration.

• There have been no documented failures of the submerged ESW pump closure bolts in 

the last 10 years.

2. Service water system:

• Each service water pump is replaced nominally every 6 years with a refurbished pump,

and as a result, the pumps and associated bolting are not subject to aging management 

review.

3. Emergency diesel engine fuel oil storage and transfer system:

• The fuel oil storage tanks (FOSTs) transfer pump closure bolting will be visually 

inspected for degradation when they are made accessible during the disassembly and 

inspection of the FOST transfer pumps, which is performed on a 10-year frequency.

• The FOST transfer pumps are periodically tested and removed from service and 

repaired or refurbished when prompted by trending of pump parameters, such as 

pressure and flow.

• There have been no documented failures of the submerged FOST transfer pump closure 

bolts in the last 10 years.

4. Oily waste system and floor and equipment drains system

• The bolting associated with the submerged pumps will be visually inspected for 

degradation when they are made accessible during pump maintenance activities, but at 

least once every four refueling outages (6 years).

• The waste water sumps are monitored during operator rounds to confirm that they are 

being drained, and the pumps are repaired or refurbished if the sumps are not being 

drained.

• There have been no documented failures of the submerged waste water pump closure 

bolts in the last 10 years.

For all of the bolting subject to aging management review, the described visual inspections will 

be performed on a representative sample of bolting, defined as 20 percent of the population with 
AGING MANAGEMENT REVIEW RESULTS

3-109

a maximum of 25 and focusing on components most susceptible to aging. In addition, loss of 

preload for all of the bolting will be managed by (a) proper selection of bolting material, (b) the 

use of appropriate lubricants and sealants, (c) selection of bolting material with appropriate yield 

strength, and (d) proper torqueing of bolts, checking for uniform gasket compression, and 

application of appropriate preload. 

The staff did not find the applicant’s response acceptable because of the following concerns:

• The proposed inspections in the ESW, oily waste, and floor and equipment drains 

systems did not address the bolt threads, which likely are exposed to the most 

aggressive conditions due to their crevice-like nature.

• The response did not include the frequency at which the operator rounds occur to 

confirm that waste water sumps are being drained.

• It was unclear whether the procedures or logs for pump performance monitoring capture 

the basis for these aging management activities.

• It was not clear whether it was appropriate to remove the service water system pumps 

and associated bolting from the scope of license renewal, given the fact that these 

components could be reused. 

By letter dated March 25, 2014, the staff issued RAI 3.3.2-2a requesting that the applicant 

address these concerns. 

In its response dated April 23, 2014, as revised by letters dated May 6, 2014, and June 5, 2014, 

the applicant stated that, when the submerged raw water and waste water pump casings are 

disassembled during maintenance, the bolting threads will be inspected. The applicant also 

stated that the Operations Technician General Inspection Guide requires that inspections are 

conducted once every 12 hours to confirm that waste water sumps are operating as required. In 

addition, the applicant supported the removal of the service water pump bolting from the scope 

of license renewal by stating that, as part of the pump refurbishment, the bolting is replaced. 

The applicant also stated that the service water pump casing will be considered as long-lived 

and the effects of aging will be managed with the External Surfaces Monitoring Program. 

The staff finds the applicant’s responses to RAIs 3.3.2-2 and 3.3.2-2a and its proposal to 

manage the aging of submerged bolting acceptable because the submerged bolting in each of 

the systems will be addressed by multiple activities that, in combination, are capable of 

identifying degradation prior to loss of intended functions. These activities include 

(a) preventive measures (e.g., proper bolt torqueing and use of lubricants) to minimize the 

potential of loss of preload, (b) performance monitoring of the associated submerged pumps, 

and (c) periodic visual inspections of the bolt heads and opportunistic visual inspections of the 

bolt threads. The staff’s concerns described in RAIs 3.3.2-2 and 3.3.2-2a are resolved. The 

staff’s evaluations of the AMR items associated with these RAIs are documented separately in 

the appropriate SER sections.

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “corrective actions” program elements 

associated with enhancements to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B2.1.8 states an enhancement to the “scope of program,” 

“preventive actions,” “detection of aging effects,” and “corrective action” program elements. 
AGING MANAGEMENT REVIEW RESULTS

3-110

In this enhancement, the applicant stated that its procedures will be enhanced to reference 

NUREG-1339 and EPRI NP-5769 to meet the GALL Report recommendations. 

By letter dated April 25, 2012, the applicant submitted LRA Amendment 1 removing 

enhancement 1 from the Bolting Integrity Program, stating that it has been completed. The staff 

confirmed the completion during the audit and the review of these program elements is 

documented in the staff evaluation section above.

Enhancement 2. LRA Section B2.1.8 states an enhancement to the “scope of program,” 

“parameters monitored or inspected,” and “detection of aging effects” program elements. In this 

enhancement, the applicant stated that its procedures will be enhanced to include bolting in the 

list of items to be inspected during walkdowns. GALL Report AMP XI.M18 recommends that 

periodic system walkdowns be conducted to ensure detection of leakage at bolted joints before 

the leakage becomes excessive. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M18 and finds it acceptable because it 

makes the program consistent with the GALL Report recommendations.

By letter dated November 8, 2012, the applicant submitted LRA Amendment 15 removing 

enhancement 2 from the Bolting Integrity Program, stating that the procedures had been 

enhanced to include bolting in the list of items to be inspected during walkdowns.

Enhancement 3. LRA Section B2.1.8, as amended by letters dated January 16, 2014, and 

June 5, 2014, states an enhancement to the “scope of program” and “parameters monitored or 

inspected” program elements. In this enhancement, the applicant stated that procedures will be 

revised to include the periodic and opportunistic inspection activities for submerged bolting 

documented above in the discussion of RAIs 3.3.2-2 and 3.3.2-2a. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M18 and 

finds it acceptable because the combination of periodic inspections of bolt heads, opportunistic 

inspections of bolt threads, and the pump performance monitoring described in the 

documentation of the RAIs is capable of identifying bolting degradation prior to loss of intended 

functions.

Based on its audit of the applicant’s Bolting Integrity Program and review of the applicant’s 

response to RAIs B2.1.8-1, 3.3.2-2, and 3.3.2-2a, the staff finds that program elements one 

through six for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.M18. 

Operating Experience. LRA Section B2.1.8 summarizes operating experience related to the 

Bolting Integrity Program. The LRA states that in a review of plant operating experience, issues 

were identified involving corrosion, missing or loose bolts, inadequate thread engagement, and 

improper bolt applications. The LRA further states that no generic bolting failure issues or 

trends have been identified, and there is no documented case of cracking of pressure 

containing bolting due to SCC.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.
AGING MANAGEMENT REVIEW RESULTS

3-111

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. Operating experience 

related to the applicant’s program demonstrates that it can adequately manage the effects of 

aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking corrective actions. 

FSAR Supplement. LRA Section A1.8, as amended by letters dated April 25, 2012, 

November 8, 2012, January 16, 2014, May 6, 2014, and June 5, 2014, provides the FSAR 

supplement for the Bolting Integrity Program. The staff reviewed this FSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant completed a portion of 

Commitment No. 5 to implement the first two enhancements to the program and committed to 

the implementation of the third enhancement no later than 6 months prior to the period of 

extended operation.

The staff finds that the information in the FSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Bolting Integrity Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation through Commitment No. 5 prior to the period of extended operation will 

make the AMP adequate to manage the applicable aging effects. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Open-Cycle Cooling Water System 

Summary of Technical Information in the Application. LRA Section B2.1.10 describes the 

existing Open-Cycle Cooling Water System Program as consistent, with enhancements, with 

GALL Report AMP XI.M20, “Open-Cycle Cooling Water System.” The LRA states that this 

program manages components exposed to raw water in the ESW system for loss of material, 

wall thinning, reduction of heat transfer, cracking, blistering, change in color, hardening, and 

loss of strength. The LRA also states that the activities for this program are consistent with 

Ameren Missouri’s commitments for GL 89-13, “Service Water System Problems Affecting 

Safety-Related Components,” and that these activities include component testing, visual 

inspections, nondestrucutive examinations, and biocide and chemical treatment, all of which 

ensure that aging effects are managed. 

Based on reviews conducted by the staff, the staff identified an issue concerning loss of coating 

integrity of internal coatings of piping, piping components, heat exchangers, and tanks. The 

staff’s position is documented in SER Section 3.0.3.4. By letters dated October 7, 2013, and 

March 25, 2014, the staff issued RAI 3.0.3-2 and RAI 3.0.3-2a, respectively, to address loss of 

coating integrity. By letters dated December 20, 2013, and April 23, 2014, the applicant 

responded to these RAIs by revising the Open-Cycle Cooling Water System program. The 

staff’s evaluation of the applicant’s response to RAI 3.0.3-2 and RAI 3.0.3-2a is documented in 

SER Section 3.0.3.4. The staff’s evaluation of changes to LRA Sections B2.1.10 and A1.10, 

and Commitment No. 6 to address loss of coating integrity, follows.
AGING MANAGEMENT REVIEW RESULTS

3-112

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M20. For the “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs as discussed below. LRA Section B2.1.10 states that the activities for this 

program are consistent with the applicant’s commitments to the requirements of GL 89-13. This 

is consistent with the “detection of aging effects” program element provided in GALL Report 

AMP XI.M20 regarding nondestructive examination methods. The applicant’s response to 

GL 89-13 dated January 29, 1990, states that selected sections of ESW system piping are 

inspected each RFO for corrosion, erosion, and biofouling. The applicant’s response also 

states that “each pipe is radiographed to determine any localized pitting. This is followed by 

ultrasonic testing using accurately placed grid locations to determine the extent of any damage.” 

However, in its review of the applicant’s implementing procedure, EDP-ZZ-01121, “Raw Water 

Systems Predictive Performance Program,” the staff noted that the procedure neither discusses 

radiography as one of the nondestructive examination techniques used to inspect ESW piping 

nor includes a requirement that any pipe be radiographed each RFO to determine any localized 

pitting. In order to address this concern, by letter dated July 18, 2012, the staff issued 

RAI B2.1.10-1, requesting the applicant to demonstrate that the Open-Cycle Cooling Water 

System Program is consistent with its commitments to GL 89-13 regarding nondestructive 

examination techniques performed during each RFO. 

In its response dated August 21, 2012, the applicant stated that it does not radiograph ESW 

piping as specified in its commitments for GL 89-13, but still meets the intent of its commitment 

by performing “scan inspections” using low-frequency electromagnetic technique (LFET) 

measurements. The applicant also stated that it performs ultrasonic thickness measurements to 

determine the extent of any degraded areas identified with LFET. The applicant further stated 

that it had entered its failure to update the original commitment to radiograph ESW piping into its 

CAP. In its review of the response, the staff noted that this electromagnetic test technique is 

described in NUREG/CR-6876, “Risk-Informed Assessment of Degraded Buried Piping Systems 

in Nuclear Power Plants,” as being able to detect discontinuities and variations in materials. 

The staff finds the applicant’s response acceptable because, although LFET by itself cannot be 

considered equivalent to radiography from a non-destructive examination perspective, it is 

capable of detecting loss of material, which can then be more accurately characterized using 

ultrasonic testing. The staff also finds that the use of LFET provides reasonable assurance that 

degraded ESW piping will be identified before there is a loss of intended function. Based on the 

above, the staff finds that the applicant is consistent with the intent of its commitments to 

GL 89-13 and that entering this issue into its CAP will address any concerns with the change to 

the original commitment. The staff’s concern described in RAI B2.1.10-1 is resolved. 

The “detection of aging effects” program element in SRP-LR Section A.1.2.3.4 states that, when 

sampling is used in condition monitoring programs, applicants should provide the basis for the 

inspection population and the sample size. The applicant’s response to GL 89-13 states that 

selected sections of ESW piping are inspected each RFO for corrosion, erosion, and biofouling. 

During its review of the applicant’s implementing procedure, EDP-ZZ-01121, the staff could not 

confirm the number of trended locations nor the criteria used to identify these locations. In 

addition, the implementing procedure contains a list of “non-trended inspected locations” that 

was not fully explained. In order to address this concern, by letter dated July 18, 2012, the staff 

issued RAI B2.1.10-2, requesting the applicant to provide details regarding the number and 

selection criteria for locations inspected and information regarding the selection criteria and 

purpose for inspecting non-trended locations. 
AGING MANAGEMENT REVIEW RESULTS

3-113

In its response dated August 21, 2012, the applicant stated that the criteria used to select 

locations include: areas of stagnant or intermittent flow; pipe material, age, and configuration;

previous inspection results; recent system challenges; chemistry trend data; industry operating 

experience; and system engineering recommendations. The applicant also stated that the 

number of locations varies from outage to outage based on the previously mentioned sample 

criteria. Regarding the “non-trended inspected locations,” the applicant stated that these are 

areas where it had previously performed permanent repairs and that it considers these locations 

for future monitoring.

In its review of the response, the staff finds the selection criteria for locations to be inspected 

each RFO to be acceptable because it includes parameters considered to be most significant 

with respect to the susceptibility to aging, including quantitative and qualitative considerations. 

However, the applicant did not provide the number of locations that it is trending. Based on 

information in response to RAI B2.1.10-6, also discussed in this section, the staff noted that the 

amount of piping currently inspected with LFET has decreased significantly since 2008. 

Because of this, the staff could not assess the process by which the applicant applied the 

selection criteria to identify specific locations for inspections. In order to address this concern, 

by letter dated October 24, 2012, the staff issued RAI B2.1.10-2a, requesting the applicant to 

discuss the apparent reduction in the amount of ESW piping inspected each outage since 2008 

and to provide the current number of locations where localized damage is being monitored as 

specified in its GL 89-13 commitments. 

In its response dated November 20, 2012, the applicant stated that it undertook a three-phase 

project beginning in 2007 to inspect the approximately 3800 feet of 6-inch diameter or greater 

above-ground carbon steel piping within the ESW system. The applicant stated that the first two 

phases inspected approximately 60 percent of the subject piping using LFET; due to the 

satisfactory results, it reduced the scope of the third phase to approximately 300 feet of piping in 

the 2008 RFO. The applicant also stated that, since completing the project, it has continued to 

inspect the ESW piping each RFO - approximately 310 feet in the 2010 RFO and 170 feet in the 

2011 RFO - and plans to inspect 200 feet in the 2013 RFO. With regard to the number of 

locations where localized damage is being monitored, the applicant stated that it currently plans 

to monitor 11 locations for pitting in the 2013 RFO. The applicant also stated that this sample 

size is based on the inspection results and the extent of piping replacements being performed in 

the ESW system. 

The staff finds the applicant’s response acceptable because the extensive inspections of the 

past provide sufficient bases for the reduced scope of more recent inspections, and the current 

condition of the system and the process used by the applicant to select locations for monitoring 

provide reasonable assurance that pipe degradation will be detected before a loss of intended 

function. The staff’s concerns described in RAIs B2.1.10-2 and B2.1.10-2a are resolved. 

The “parameters monitored or inspected” program element in GALL Report AMP XI.M20 states 

that components with internal linings or coatings are periodically inspected and that the program 

ensures the detection of defective protective coatings that could adversely affect component 

performance. While LRA Section B2.1.10 states that Callaway uses internal coatings on heat 

exchanger components in various systems, it also states that the amount of coating surface is 

relatively small and that aging of the coating has not been a concern for ESW performance. 

Callaway’s implementing procedure, ETP-ZZ-3001, “GL 89-13 Heat Exchanger Inspections,” 

states that heat exchanger coatings are examined when they are accessible for inspections; 

however, Callaway’s AMP evaluation report for open-cycle cooling water system, Section 3.3.2, 
AGING MANAGEMENT REVIEW RESULTS

3-114

states that heat exchanger inspections are performed for fouling, sediment, corrosion, erosion, 

and pitting, but does not state that coating degradation is included.

In addition, the applicant’s letter dated July 16, 2007, which modified its commitments for 

GL 89-13, Item III.A, states that thermal performance testing will be the primary monitoring 

method for the component cooling water (CCW) heat exchangers, with cleaning and inspections 

as necessary. The staff noted that, while the other heat exchangers with internal coatings will 

be periodically inspected, the inspections of the CCW heat exchanger are now based on need, 

as determined by thermal performance testing, which may not afford an opportunity to detect 

coating degradation prior to failure. In order to address these concerns, by letter dated 

July 18, 2012, the staff issued RAI B2.1.10-3, requesting the applicant to confirm that heat 

exchangers with applied coatings will be periodically inspected to detect coating degradation 

and to confirm the frequency of these inspections. 

In its response dated August 21, 2012, the applicant stated that it uses internal coatings in the 

CCW heat exchangers, the control room air conditioners, and the Class 1E equipment air 

conditioner and that these components are inspected for signs of coating degradation at least 

every 5 years, as required by the heat exchanger inspection procedure. The applicant also 

stated that the ESW strainers, which are inspected every 6 years, have internal coatings and 

that the implementing procedure for the Open-Cycle Cooling Water System Program will be 

enhanced to specify inspection of these coatings. The applicant further stated that, since the 

total amount of internal coating is small and there has been no recent documented operating 

experience of internal coating failures, the frequency of inspections for the affected components 

provides reasonable assurance that the program will effectively identify coating failures and 

aging so that corrective actions can be initiated. 

The staff finds a portion of the applicant’s response acceptable because the implementing 

procedures will be enhanced to include the coatings for the ESW strainers resulting in the 

program’s inclusion of all components with coatings whose failure could adversely affect 

downstream components. However, although the applicant did not identify any recent 

plant-specific operating experience in the LRA, the staff noted that the applicant had identified 

several issues with coating degradation between 2001 and 2007. The staff also noted recent 

industry operating experience that attributed the use of internal coatings beyond their 

established service life as a cause of coating failures in raw water systems, which then 

adversely affected downstream components. Since the program basis documents do not 

address coating service life, it was unclear to the staff how coatings will be managed and 

whether inspection techniques other than visual examinations would be used as a coating 

approaches its end of service life. It was also unclear to the staff whether the program includes 

qualification requirements for personnel who perform the coating inspections. In order to 

address this concern, by letter dated October 24, 2012, the staff issued RAI B2.1.10-3a, 

requesting the applicant to provide the service life for each of the coatings subject to aging 

management review used at Callaway, to provide program requirements as the coatings 

approach their end of service life, and to provide the qualification requirements for personnel 

performing coating inspections. 

In its response dated November 20, 2012, the applicant stated that it does not rely on estimated 

service life to manage internal coatings and that intervals for monitoring the condition of the 

internal coatings begin immediately after the coatings are applied. The applicant also stated 

that it performs visual inspections as the primary method of monitoring the coating condition, 

and that corrective actions, extent of condition reviews, and evaluations for continued service 

are performed consistent with American Society for Testing and Materials (ASTM) D7167, 
AGING MANAGEMENT REVIEW RESULTS

3-115

“Standard Guide for Establishing Procedures to Monitor the Performance of Safety-Related 

Coating Service Level III Lining Systems in an Operating Nuclear Power Plant,” which 

addresses performance of physical tests, such as dry film thickness or pull-off adhesion testing, 

at the discretion of the evaluator. The applicant further stated that coating inspections will be 

performed by a qualified nuclear coatings specialist as defined by ASTM D7108 or by coatings 

surveillance personnel under the technical direction of such a specialist. 

The staff finds portions of the applicant’s response acceptable, in that coating inspections will be 

performed by personnel either qualified as a nuclear coatings specialist or under the technical 

direction of such a specialist. However, in its review of other portions of the applicant’s 

response, it was not clear to the staff that corrective actions, extent of condition reviews, and 

evaluations for continued service of coatings are being performed consistent with ASTM D7167 

because Callaway’s implementing procedures did not make this correlation and did not include 

the ASTM standard as a reference. In addition, Callaway’s implementing procedures, 

EDP-ZZ-01112 and ETP-ZZ-03001, appear to focus on the potential corrosion effects from 

coating degradation, but they do not clearly address coating degradation as a source of 

macrofouling or provide guidance on the assessment of continued service for coatings. In order 

to resolve this concern, by letter dated February 21, 2013, the staff issued RAI B2.1.10-3b, 

requesting the applicant to provide additional justification for the frequency and type of 

inspections performed on coatings in ESW components whose degradation may adversely 

affect the safety function of downstream equipment. 

In its response dated February 28, 2013, the applicant stated it will enhance the program’s 

implementing procedures to specify that coating inspections will look for signs of coating 

detachment, such as flaking, peeling, and delamination. The applicant stated that the 

procedure enhancements will also include acceptance criteria that will not permit the above 

signs of detachment, but will allow blisters if they are intact and are completely surrounded by 

sound coating bonded to the surface. The applicant also stated that implementing procedures 

will be enhanced to require coating evaluation and testing whenever coating detachments are 

not repaired or removed. These enhancements will include confirmation that coating 

manufacturer installation requirements have been met, physical testing such as dry film 

thickness or adhesion testing as identified in ASTM-D7167 will be required, and coating 

detachments that are not repaired or removed to leave sound coating bonded to the surface will 

be trended. The applicant further stated that the program components are routinely inspected 

on a staggered outage basis between redundant trains, and there would be approximately 18 

months between alternate train inspections and 36 months between specific component 

inspections. The applicant stated that the corresponding program components in the redundant 

trains have the same coatings, are exposed to the same environment, and are constructed of 

the same materials. In addition, the applicant stated that for the same components in redundant 

trains, the same material/environment conditions are being inspected every RFO.

The staff finds the applicant’s response acceptable because the proposed changes to the 

implementing procedures will ensure that coating inspections will more rigorously look for 

coating degradation, and the acceptance criteria will ensure the coatings are bonded to the 

surface by including requirements for physical testing such as those identified in ASTM-D7167. 

In addition, the staff finds the inspection frequency of the coatings to be acceptable because the 

program’s routine inspections for redundant trains will ensure comparable components in the 

same environment and constructed of the same material with the same coating will be inspected 

every RFO. The staff’s concerns described in RAIs B2.1.10-3, B2.1.10-3a, and B2.1.10-3b are 

resolved.
AGING MANAGEMENT REVIEW RESULTS

3-116

The staff notes that the applicant’s responses to RAI 3.0.3-2 and RAI 3.0.3-2a, dated 

December 20, 2013, and April 23, 2014, respectively, resulted in changes to the Open-Cycle 

Cooling Water System Program in regard to managing loss of coating integrity for the coatings 

addressed in RAIs B2.1.10-3, B2.1.10-3a, and B2.1.10-3b. As a result of these changes, the 

following statements made by the applicant in the response to RAIs B2.1.10-3, B2.1.10-3a, and 

B2.1.10-3b were altered:

• Inspection intervals have been modified to: (a) if no peeling, delamination, blisters, or 

rusting are observed, and any cracking or flaking has been found to be acceptable 

based on an evaluation by the coatings specialist, inspections will occur once every 

6 years; (b) if no indications are found during the inspection of one train, the redundant 

train will not be inspected; (c) if the inspection results do not meet the conditions 

described in (a) and a coatings specialist determines that no remediation is required, 

inspections will occur every other refueling outage; and (d) repaired, replaced, or newly 

installed coatings will be inspected in each of the following two refueling outages. As 

further revised by letter dated June 5, 2014, the applicant restricted the redundant train 

inspection frequency to only apply if the components are not subject to turbulent flow 

conditions that could result in mechanical damage to the coating.

• The applicant removed ASTM D7167 as a reference to address performance of physical 

tests and instead stated that physical testing (i.e., destructive or nondestructive 

adhesion testing) will be conducted in accordance with ASTM International Standards 

endorsed in RG 1.54, “Service Level I, II, and III Protective Coatings Applied to Nuclear 

Plants.”

• The applicant removed ASTM D7108 as a reference for qualifying inspection personnel 

and instead stated that training and qualification of individuals involved in coating 

inspections are conducted in accordance with ASTM International Standards endorsed 

in RG 1.54 including guidance from the staff associated with a particular standard.

• The acceptance criteria was modified to allow indications such as cracking, flaking, and 

rusting if they are evaluated by a coatings specialist qualified in accordance with an 

ASTM International Standard endorsed in RG 1.54 including staff guidance associated 

with use of a particular standard.

• The requirement to confirm that coating manufacturer installation requirements have 

been met has been removed from the program.

The staff finds the applicant’s changes to the Open-Cycle Cooling Water System Program 

associated with loss of coating integrity acceptable because they are consistent with staff 

recommendations for managing loss of coating integrity as documented in SER Section 3.0.3.4.

The “detection of aging effects” program element in GALL Report AMP XI.M20 states that 

inspection methods (e.g., visual or nondestructive examination) are in accordance with the 

applicant’s docketed response to GL 89-13. The applicant’s response to GL 89-13, dated 

January 29, 1990, Enclosure 2, Item III.B, states, in part, that air flow rates of all air-to-water 

heat exchangers are taken and trended and that visual inspections of the air side of the heat 

exchangers will be performed. The applicant modified its GL 89-13 commitment for heat 

exchanger testing in its letter dated July 16, 2007, and addressed Item III.A by changing the 

methodology to clean and inspect the water side of the tubes for all of the room coolers in lieu of 

efficiency testing. However, that letter did not address Item III.B regarding air flow rate 
AGING MANAGEMENT REVIEW RESULTS

3-117

monitoring and trending for room coolers. By contrast, for the containment air coolers, which 

are air-to-water heat exchangers, the 2007 letter states that the primary monitoring method will 

be cleaning and inspection of the inner tube walls and outer coil fins per EDP-ZZ-01112. In 

addition, although heat transfer is the intended function listed for heat exchangers exposed to 

ventilation atmosphere in various LRA Tables (e.g., 3.3.2-11, 3.3.2-13, 3.3.2-14, 3.3.2-15, and 

3.3.2-19), reduction of heat transfer is not listed as an AERM for these GL 89-13 components. 

It was not clear to the staff that the program is being implemented consistent with the applicant 

commitments regarding air-side heat exchanger inspections or that LRA tables containing these 

heat exchangers include AERM consistent with the activities described in the applicant 

commitments. In order to address these concerns, by letter dated July 18, 2012, the staff 

issued RAI B2.1.10-4, requesting the applicant to confirm that the Open-Cycle Cooling Water 

System Program is consistent with its commitments to GL 89-13 with respect to air-side heat 

exchanger inspections and, if needed, to update the appropriate tables in the LRA to reflect the 

aging effects being managed by this program through these commitments. 

In its response dated August 21, 2012, the applicant stated that it regularly cleans and inspects 

the air-side of the GL 89-13 safety-related heat exchangers and that it no longer requires 

air-flow testing for the safety-related air-to-water heat exchangers, as documented in its 

commitment change for GL 89-13, dated July 16, 2007. The staff notes that the applicant’s 

July 16, 2007, letter with commitment change for GL 89-19 states that the frequency of cleaning 

and inspection is based on past inspection results but will not exceed 5 years. The applicant 

also stated that, to demonstrate consistency with its GL 89-13 commitments, it will enhance the 

heat exchanger inspection procedure to visually inspect and, if necessary, clean the air sides of 

the GL 89-13 room coolers. In addition, the applicant revised LRA Tables 3.3.2-11, 3.3.2-13, 

3.3.2-14, 3.3.2-15, and 3.3.2-19 to identify management of reduction of heat transfer for heat 

exchanger components that have a heat transfer intended function in a ventilation atmosphere.

The staff finds the response acceptable because the applicant confirmed that it conducts 

air-side inspections of applicable room coolers, consistent with its modified commitments to 

GL 89-13. The applicant also committed to enhance the implementing procedures to provide for 

this inspection activity and revised the applicable LRA tables to reflect the appropriate aging 

management activities being performed by this program. Based on the above discussion, the 

staff’s concern described in RAI B2.1.10-4 is resolved.

The “acceptance criteria” program element in the GALL Report AMP XI.M20 states that 

inspected components should exhibit adequate design margin regarding design dimensions, 

such as minimum required wall thickness. SRP-LR Section A.1.2.3.6, “Acceptance Criteria,” 

states that acceptance criteria should ensure that the component-intended function(s) are 

maintained consistent with all CLB design conditions during the period of extended operation. 

Callaway’s AMP evaluation report for this program, Section 3.6.2, states that minimum wall 

thickness acceptance criteria are listed in procedure EDP-ZZ-1121, Attachments 3 and 4. In its 

review of operating experience reports, the staff noted in CAR 200703680 that a flange for an 

ESW valve had corrosion damage. The CAR states that more than 50 percent of the gasket 

seating area was damaged by corrosion, but it does not provide any information regarding the 

depth of the corrosion. The CAR’s corrective actions section states, “[t]he extent of the 

corrosion damage identified does not adversely impact the structural integrity of the flange. The 

standard Class 3 manufacturing tolerance of 12.5 percent thickness provides assurance that 

this condition is not a structural or pressure boundary issue.”

The staff noted that the acceptance criteria listed in procedure EDP-ZZ-1121, Attachments 3 

and 4, only apply to pipe minimum wall thickness and do not address flange thicknesses. The 
AGING MANAGEMENT REVIEW RESULTS

3-118

staff also noted that the 12.5 percent manufacturing tolerance stated in the CAR only applies to 

pipe wall thickness; the tolerance for flange thickness is typically specified in ANSI B16.5, “Pipe 

Flanges and Flanged Fittings,” with a 0.0 “minus” value. ANSI B16.5 does not appear to give a 

“plus or minus” 12.5 percent tolerance for flange thickness, and without knowing the depth of 

the corrosion and the thickness of the flange, the structural integrity of the flange during the 

period of extended operation has not been demonstrated. By letter dated July 18, 2012, the 

staff issued RAI B2.1.10-5, requesting the applicant to address structural integrity evaluations 

where flange thicknesses have been adversely affected, and to provide the acceptance criteria 

that will be used to ensure that the component-intended function(s) will be maintained 

consistent with all CLB design conditions, or provide the basis for applying the “standard 

Class 3 manufacturing tolerance of 12.5 percent” to flange thicknesses.

In its response dated August 21, 2012, the applicant stated that the pipe spool piece in question 

has been replaced with stainless steel; therefore, the current configuration maintains the 

structural integrity of the system. The applicant also stated that, although the 12.5 percent used 

in the response to CAR 200703680 does not apply to flange thickness, the degradation on the 

flange face was fairly shallow such that structural integrity was not adversely impacted to the 

point of flange failure. The response discussed the quality control acceptance criteria for the 

percentage of defective gasket seating area, which states, “[n]o transverse discontinuities 

longer than 50 [percent] of gasket seat area width (25 [percent] for serrated finish surface)," and 

stated that any defect exceeding these criteria would go to the engineering department for 

evaluation.

In its review of the response, the staff noted that the applicant’s criteria for addressing flange 

degradation pertained to the surface area, which would affect leakage, but the criteria did not 

provide any guidance regarding the loss of flange thickness, which would affect structural 

integrity. In addition, the staff noted that CAR 200703680 addressed a condition requiring an 

engineering evaluation, and the engineering evaluation apparently justified the structural 

integrity of the flange based on incorrect tolerances. It was unclear to the staff what acceptance 

criteria will be used where flange thicknesses have been adversely affected and what 

assurances that the 12.5 percent pipe wall thickness manufacturing tolerance will only be 

applied to appropriate components in engineering evaluations of structural integrity. Therefore, 

by letter dated October 24, 2012, the staff issued RAI B2.1.10-5a, requesting the applicant to 

provide the acceptance criteria for flange thickness degradation that will be used to ensure the 

component’s intended function(s) will be maintained consistent with all CLB design conditions 

and to provide assurance that the 12.5 percent pipe wall thickness manufacturing tolerance will 

only be applied to appropriate components in engineering evaluations of structural integrity. 

In its response dated November 20, 2012, the applicant stated that it is not its practice to 

evaluate the acceptance of degraded flanges based on manufacturer’s tolerances and noted 

that the evaluation cited in CAR 200703680 compared the observed flange corrosion to the 

12.5 percent pipe tolerance as a reasonable qualitative conclusion that structural integrity was 

not challenged. The applicant explained that the CAR was generated because the corrosion 

observed on the surface of the flange exceeded the quality control acceptance criterion of 

50 percent surface degradation measured transversely. The applicant stated that corrective 

action was taken to apply a coating, which is appropriate for surface degradation, but 

subsequently, the affected piping was replaced with stainless steel. The applicant also stated 

that it had searched Callaway operating experience and did not identify any instances where 

flange degradation challenged structural integrity. 
AGING MANAGEMENT REVIEW RESULTS

3-119

The staff finds the applicant’s response acceptable. GALL Report XI.M20 recommends that the 

acceptance criteria be in accordance with the applicant’s docketed response to NRC GL 89-13. 

The applicant’s GL 89-13 program includes use of the Callaway Operational Quality Control 

Manual, which contains acceptance criteria for flange degradation. Since no other flange 

degradation structural issues were found, the applicant has provided reasonable assurance that 

it would identify structural degradation of flanges prior to loss of intended function. The staff’s 

concerns described in RAI B2.1.10-5 and B2.1.10-5a are resolved. 

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with 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 B2.1.10 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that procedures will be enhanced to include polymeric 

material inspection requirements and acceptance criteria to be consistent with examinations 

described in the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. The staff noted that GALL Report AMP XI.M20 recommends that 

examinations of polymeric materials be consistent with those described in GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components.” GALL Report AMP XI.M38 recommends that visual and tactile inspections be 

conducted whenever the component surface is accessible. The staff also noted that the 

polymer examinations in the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program are consistent with GALL Report AMP XI.M38, as 

documented in SER Section 3.0.3.2.12. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M20 and finds it acceptable because, 

when it is implemented, the inspections of polymeric components within the program will be 

consistent with those described in GALL AMP XI.M38, as specified in the “detection of aging 

effects” program element in GALL AMP XI.M20 and will be able to detect aging effects before 

there is a loss of intended function.

Enhancement 2. In response to RAI B2.1.10-3, the applicant committed to enhance the 

“preventive actions,” “parameters monitored or inspected,” “detection of aging effects,” and 

“acceptance criteria” program elements by revising procedures to inspect the coatings in the 

ESW strainers for degradation once every 6 years. As amended by letter dated 

December 20, 2013, this enhancement was deleted, and by letter dated April 23, 2014, a new 

enhancement (Enhancement No. 5) was proposed to address loss of coating integrity. 

Enhancement 3. In response to RAI B2.1.10-4, the applicant committed to enhance the 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements by revising procedures to inspect and clean, if necessary, the air-side of the 

safety-related air-to-water heat exchangers cooled by ESW. The staff notes that the current 

frequency for cleaning and inspection of safety-related heat exchangers, as provided in the 

applicant’s commitment change for GL 89-13 dated July 16, 2007, is based on past inspection 

results, but will not exceed 5 years. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M20 and finds it acceptable because, 

when it is implemented, the revised procedures will manage reduction of heat transfer due to 

fouling of the air side for heat exchangers consistent with the applicant’s commitments to 

GL 89-13.
AGING MANAGEMENT REVIEW RESULTS

3-120

Enhancement 4. In response to RAI B2.1.10-3b, the applicant committed to enhance the 

“preventive actions,” “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements by revising inspection 

procedures of internal coatings to specify acceptance criteria for, and to identify indications of, 

coating detachment that could affect downstream components. As amended by letter dated

December 20, 2013, this enhancement was deleted, and by letter dated April 23, 2014, a new 

enhancement (Enhancement No. 5) was proposed to address loss of coating integrity. 

Enhancement 5. As amended by letters dated December 20, 2013, April 23, 2014, and 

June 5, 2014, LRA Section B2.1.10 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant provided a list of procedure enhancements associated with 

coatings inspections (e.g., base line inspections, extent of inspections), training and qualification 

of individuals involved in coating inspections, acceptance criteria, and corrective actions. These 

enhancements and the corresponding staff evaluation are documented in the response to 

RAI 3.0.3-2a Request Nos. (2), (5), and (6) in SER Section 3.0.3.4.

Enhancement 6. As amended by letter dated December 20, 2013, LRA Section B2.1.10 adds

an enhancement to the “detection of aging effects” program element. Prior to the period of 

extended operation, the applicant will select an inspection technique from available techniques 

to identify internal pipe wall degradation due to MIC for performance of a one-time inspection of 

a buried carbon steel piping segment that is representative of other accessible carbon steel 

ESW piping segments. This enhancement is acceptable because, as part of the activities to 

address recurring internal corrosion, it will provide an assessment of the buried carbon steel 

piping to ensure that the condition of accessible piping is representative of buried piping.

Based on its audit and review of the applicant’s responses to RAIs B2.1.10-1, B2.1.10-2, 

B2.1.10-2a, B2.1.10-3, B2.1.10-3a, B2.1.10-3b, B2.1.10-4, B2.1.10-5 and B2.1.10-5a, the staff 

finds that the program elements for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.M20. 

Based on its review of the applicant’s responses to RAIs 3.0.3-2 and 3.0.3-2a, the staff also 

finds that the applicant’s program changes to address loss of coating integrity are consistent 

with staff recommendations for managing loss of coating integrity documented in SER Section 

3.0.3.4. In addition, the staff reviewed the enhancements associated with the “preventive 

actions,” “parameters monitored or inspected,” “detection of aging effects,” and “acceptance 

criteria” program elements and finds that, when implemented, they will make the AMP adequate 

to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.10 summarizes operating experience related to the 

Open-Cycle Cooling Water System Program. The applicant stated that the design of the 

containment cooler coils did not allow them to be mechanically cleaned and that the coil 

performance degraded over time due to debris from the service water system. The applicant 

replaced the coils for the four containment coolers in 2001 and 2002 with a design that included 

removable cover plates, which permit access to mechanically clean individual tubes. The 

applicant also discussed the replacements in 2009 and 2010 of several safety-related room 

coolers and the heat exchangers for the emergency diesel generator (EDG) jacket water, lube 

oil, and intercoolers with coils and tubes made from AL6XN stainless steel. These 

replacements were due to performance and aging issues, including loss of material. In 2008 

and 2009, the applicant also replaced the buried portions of the ESW supply from the ESW 

pump house and the return to the ultimate heat sink cooling tower with high-density 

polyethylene (HDPE) piping due to the material condition of the ESW system. The applicant 
AGING MANAGEMENT REVIEW RESULTS

3-121

stated that these examples show that the existing Open-Cycle Cooling Water System Program 

activities prevent or detect aging effects and that the continued implementation of the program 

will effectively identify aging prior to loss of intended function.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI, as 

discussed below.

During its review of plant-specific operating experience, the staff noted the discussion in 

CAR 200608086 regarding wall thinning of carbon steel components, which adversely affected 

the ability of the ESW system to perform its intended function. In addition, the staff noted that a 

number of carbon steel components are still in service and that the applicant did not discuss 

plans for future replacement with corrosion-resistant materials. Based on the past extent of 

degradation in the ESW, the staff lacked sufficient information to conclude that the Open-Cycle 

Cooling Water System Program will adequately manage the effects of aging so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation. By letter dated July 18, 2012, the staff issued RAI B2.1.10-6, requesting the 

applicant to provide (a) corrective actions taken and enhancements made to prevent recurrence 

of the pervasive degradation in the system, (b) a summary of the augmented inspections that 

are currently being performed to identify loss of material before through-wall leaks occur, and 

(c) a summary of past analyses conducted that evaluated the structural integrity of degraded 

areas, including data to demonstrate that the degradation is limited to independent, localized 

corrosion sites.

In its response dated August 21, 2012, the applicant discussed the 2005 event in which it 

declared the ESW B train inoperable due to under-deposit corrosion in a section of the pipe 

between the pump strainer and pump discharge valve. The applicant stated that its extent of 

condition review, which included volumetric examinations of corresponding segments in the 

A train and additional locations of horizontal pipe exposed to intermittent flow, did not identify 

any additional degradation. Based on these inspections, the applicant concluded that the 

initiating cause was unique to the location where the corrosion occurred and that no further 

corrective actions or program enhancements were needed beyond the replacement of the 

degraded pipe section. 

The applicant also stated it has replaced a substantial amount of ESW piping including (a) all 

small bore carbon steel ESW piping (approximately 3400 feet) with stainless steel pipe starting 

in the mid-1990s; (b) 79 feet of 30-inch piping, several sections of 8-inch and 6-inch piping, the 

pump discharge spool and reducer, and the pump discharge cross-connect spool piece in 2007;

and (c) the buried portions of the ESW supply and return lines with HDPE from 2008 to 2009. 

The applicant stated it did not have any plans for additional replacements. In addition, the 

applicant stated it used LFET to inspect approximately 2000 feet of ESW piping in spring 2008, 

300 feet in each of the refueling outages in fall 2008, spring 2010, and fall 2011, and it planned 

to inspect 200 feet in spring 2013. The applicant also described the five engineering 

evaluations it performed in 2007, the two in 2008 and one in 2009 for the structural integrity of 

the ESW system due to leakage or minimum wall thickness deficiencies. 
AGING MANAGEMENT REVIEW RESULTS

3-122

The staff finds the above portions of the applicant’s response acceptable because the applicant 

has replaced a significant amount of carbon steel ESW piping with material that is much more 

resistant to degradation from raw water. In addition, the applicant has performed a significant 

number of inspections using the LFET. The staff notes that the number of degraded locations 

needing evaluation has decreased since 2007 and that no additional evaluations have 

apparently been required since 2009. Based on the above discussion, the staff finds that the 

applicant has taken corrective actions to address the consequences of past program 

weaknesses. The staff’s concerns described in RAI B2.1.10-6 are resolved except as noted 

below.

As part of it review of past operating experience, the staff noted the discussion in 

CAR 200703627 that correlates the identification of ESW system leaks with periodic testing for 

the engineered safety feature actuation system (ESFAS). This testing includes actuations in 

response to loss of offsite power. The CAR states that ESW components above a certain 

elevation will naturally drain when the pump is secured in the ESFAS procedure and that 

corrective actions taken to date have not been effective in preventing ESW system hydraulic 

transients during this testing. As part of RAI B2.1.10-6, the staff questioned whether the 

applicant included these hydraulic transient loads in its structural integrity evaluations of 

degraded ESW piping. In its response dated August 21, 2012, the applicant stated that 

calculations of minimum wall thickness do not require consideration of transient pressure 

caused by a water hammer event and that the Callaway pipe design standard establishes how 

design pressures are defined and allows pressure excursions in excess of design for short 

periods of time.

In its review of this portion of the RAI response, the staff noted that the ASME Code requires the 

system design pressure to include allowances for pressure surges and that, although 

Callaway’s pipe design standard allows pressure excursions in excess of design, the ASME 

Code limits the stresses resulting from pressure excursions depending on the service level. In 

order to address this issue, by letter dated October 24, 2012, the staff issued RAI B2.1.10-6a, 

requesting the applicant to address why the exclusion of pressure surges caused by transient 

loads and loss of offsite power in structural evaluations meets the CLB. 

In its response dated November 20, 2012, the applicant stated that in the 1990s, when it was 

recognized that procedural guidance would not prevent water hammer from occurring during a 

loss of offsite power event, pipe stress evaluations were performed to include water hammer as 

an upset design condition, and the structural interactions of the event were accounted for by 

factoring pipe stress results in the code equations to determine the minimum wall thickness. In 

addition, the applicant stated that it installed multiple modifications to address the susceptibility 

of the ESW system to water hammer, most recently including a 30-inch check valve to prevent 

draining and re-sequencing two isolation valves as discretionary enhancements to bolster the 

system’s defense in depth against potential water hammer occurrences. The applicant also 

stated that, since these changes were implemented, there have been no recurrences of water 

hammer in conjunction with ESFAS testing. The staff finds the applicant’s response acceptable 

because the minimum pipe wall thickness had previously considered the structural interactions 

due to water hammer, which meets the CLB for structural evaluations. The staff also noted that 

the discretionary enhancements to the ESW system have prevented recurrence of the water 

hammer. Based on the above, the staff’s concerns described in RAIs B2.1.10-6 and B2.1.10-6a

are resolved.

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

RAI B2.1.10-6 and B2.1.10-6a, the staff finds that the applicant has appropriately evaluated 
AGING MANAGEMENT REVIEW RESULTS

3-123

plant-specific and industry operating experience and that implementation of the program has 

resulted in the applicant taking corrective action. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which GALL Report 

AMP XI.M20 was evaluated. 

FSAR Supplement. LRA Section A1.10 provides the FSAR supplement for the Open-Cycle 

Cooling Water System Program. The staff reviewed this FSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 6) to enhance 

the Open-Cycle Cooling Water System Program procedures six months before the period of 

extended operation to include (a) polymeric material inspection requirements, parameters 

monitored and acceptance criteria; (b) inspection of the internal coatings in the ESW strainers;

(c) inspection and cleaning of the air side of ESW-cooled heat exchangers, and (d) trending, 

acceptance criteria, and testing for indications of coating detachment to confirm coating is 

bonded to surface. 

The staff noted that the applicant modified LRA Section A.1.10 in response to RAI 3.0.3-2 and 

RAI 3.0.3-2a by letters dated December 20, 2013, and April 23, 2014, to address loss of coating 

integrity. The staff also noted that the applicant committed (in Commitment No. 6) to revise the 

Open-Cycle Cooling Water System Program procedures to address loss of coating integrity as 

described above in Enhancement No. 5.

The staff finds that the information in the FSAR supplement, as amended by letters dated 

February 28, 2013, December 20, 2013, and April 23, 2014, is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Open-Cycle Cooling Water 

System Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M20. Also, the staff reviewed the enhancements and 

confirmed that their implementation through Commitment No. 6 six months before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 

staff also reviewed the FSAR supplement for this AMP and concludes that it provides an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.4 Closed Treated Water Systems 

Summary of Technical Information in the Application. LRA Section B2.1.11 describes the 

existing Closed Treated Water Systems Program as consistent, with an enhancement, with 

GALL Report AMP XI.M21A, “Closed Treated Water Systems.” The LRA states that the Closed 

Treated Water Systems Program addresses components in closed-cycle cooling water systems 

to manage the effects of loss of material, cracking, and reduction of heat transfer. The LRA also 

states that the AMP proposes to manage these aging effects through periodic visual inspections 

and control of water chemistry consistent with the guidelines of EPRI 1007820, “Closed Cooling 

Water Chemistry Guideline.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M21A. 

For the program description, the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below.
AGING MANAGEMENT REVIEW RESULTS

3-124

During its audit, the staff found inconsistencies in the LRA AMP description, program basis 

document, and implementing procedures regarding which water chemistry control approach is 

used in the boron thermal regeneration (BTR) system chilled water system. The staff noted that 

the improper identification of the water chemistry may lead to an inadequate sampling of 

inspection populations based on water treatment programs.

By letter dated July 5, 2012, the staff issued RAI B2.1.11-1 requesting that the applicant state 

the water chemistry environment of the BTR system chilled water system and revise the LRA, 

program basis document as well as the implementing procedures accordingly.

In its response dated August 6, 2012, the applicant stated that the water chemistry treatment 

program for the BTR system chilled water system is nitrite/molybdate with tolyltriazole. The 

applicant revised LRA Section B2.1.11 and stated that it revised the program basis document 

and inspection procedure to indicate this environment. The applicant also revised AMR items in 

LRA Table 3.3.2-10 to show that components in the BTR system chilled water system are 

exposed internally to closed-cycle cooling water and are managed with the Closed Treated 

Water Systems Program, rather than being exposed to demineralized water and managed with 

the Water Chemistry and One-Time Inspection programs, as originally stated in the LRA. 

The staff finds the applicant’s response acceptable because the correct identification of the 

water chemistry treatment program in the BTR system chilled water system in the LRA, program 

basis document, and inspection procedure ensures that proper inspection sampling of 

components exposed to each water treatment program can be performed. The staff’s review of 

the revised AMR items associated with the BTR system chilled water system is documented in 

SER Section 3.3.2.1. The staff’s concern described in RAI B2.1.11-1 is resolved.

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 an enhancement to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this enhancement follows.

Enhancement. LRA Section B2.1.11 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements. In this enhancement, the applicant stated that procedures will be enhanced 

to include visual inspections of the surfaces of components with closed treated water 

environments. The applicant also stated that representative samples of each combination of 

material and water treatment program will be inspected opportunistically, or at least every 

10 years, for cracking, loss of material, and fouling. However, during its audit of the Closed 

Treated Water Systems Program, the staff noted that the program basis document and 

implementing procedures differ with this inspection sampling methodology. The staff also noted 

that neither the LRA nor the program basis document state that inspection locations will be 

selected based on likelihood of corrosion or cracking, as recommended by GALL Report 

AMP XI.M21A. By letter dated July 5, 2012, the staff issued RAI B2.1.11-2 requesting that the 

applicant state what inspection sampling methodology will be used and whether inspection 

locations will be selected based on likelihood of corrosion or cracking or to provide technical 

justification for not doing so. 

In its response dated August 6, 2012, the applicant stated that the correct sampling 

methodology is defined in the program basis document and consists of a sample size of 

20 percent of components, up to a maximum of 25 components, for each chemical environment, 

with at least two samples of each material to be included in the sample for each environment. 

The applicant also stated that the inspections will be conducted during each 10-year period 
AGING MANAGEMENT REVIEW RESULTS

3-125

beginning 10 years before entry into the period of extended operation. The applicant further 

stated that the draft implementing procedure will be corrected to agree with the program basis 

document. In addition, the applicant revised the LRA and Commitment No. 7 to state that 

inspection locations will be selected based on likelihood of corrosion and cracking. 

The staff finds the applicant’s response acceptable because the sampling methodology 

described in the RAI response provides sufficient opportunity to discover the presence or extent 

of aging for each type of material in every applicable environment before loss of 

component-intended functions. The staff noted that the application of this sampling 

methodology at least every 10 years, beginning 10 years before the period of extended 

operation, allows the progression of degradation to be adequately monitored and trended. The 

staff’s concern described in RAI B2.1.11-2 is resolved. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.M21A and finds it 

acceptable because when it is implemented it will include appropriate visual inspections to verify 

the effectiveness of water chemistry controls, as described above.

Based on its audit of the applicant’s Closed Treated Water Systems Program and review of the 

applicant’s responses to RAIs B2.1.11-1 and B2.1.11-2, the staff finds that program elements 

one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M21A. In 

addition, the staff reviewed the enhancement associated with the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements and finds that when implemented it will make the AMP adequate to manage 

the applicable aging effects.

Operating Experience. LRA Section B2.1.11 summarizes operating experience related to the 

Closed Treated Water Systems Program. The LRA states that a review of the past 10 years of 

operating experience did not identify any instances where aging effects arising from 

closed-cycle cooling water led to loss of intended function of any of the heat exchangers served 

by the systems within the scope of this program. The LRA also states that cracking due to SCC 

was identified in the outlet nozzle area of the letdown heat exchanger during a 2002 inspection 

that was prompted by similar cracking at Wolf Creek. The affected components were replaced 

and followup inspections did not find any additional cracking. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience, and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M21A was evaluated. 

FSAR Supplement. LRA Section A1.11 provides the FSAR supplement for the Closed Treated 

Water Systems Program. The staff reviewed this FSAR supplement description of the program 
AGING MANAGEMENT REVIEW RESULTS

3-126

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed (Commitment No. 7) to enhance the program six 

months before the period of extended operation to include visual inspections for loss of material, 

cracking, and fouling at least once every 10 years as described in the enhancement description 

above. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Closed Treated Water 

Systems Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. Also, the staff reviewed the 

enhancement and confirmed that its implementation through Commitment No. 7 six months 

before the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. The staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR 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 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

Summary of Technical Information in the Application. LRA Section B2.1.12 describes the 

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program as consistent, with enhancements, with GALL Report AMP XI.M23, 

“Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.” 

The LRA states that the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program manages loss of material and loss of preload for bolting 

for all crane, trolley, and hoist structural components; and fuel handling equipment and 

applicable rails within the scope of license renewal. The LRA also states that visual inspections 

will manage loss of material due to corrosion of structural members and bolting, loss of material 

due to wear of rails, and loss of preload for bolted connections. The LRA further states that 

crane inspections are performed in accordance with the ASME B30 standards, which are 

recommended by the GALL Report. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M23. The staff also reviewed 

the portions of the “parameters monitored or inspected,” “detection of aging effects,” 

“acceptance criteria” and “corrective actions” program elements associated with enhancements 

to determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B2.1.12 states an enhancement to the “parameters monitored or 

inspected,” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that its procedures will be enhanced to inspect crane structural members for 

loss of material due to corrosion and rail wear and loss of preload due to loose or missing bolts 

and nuts. GALL Report AMP XI.M23 recommends that visual inspections be conducted to 

ensure that there is no loss of material occurring and that bolted connections are monitored for 

loose bolts, missing or loose nuts, and other conditions indicative of loss of preload. The staff 
AGING MANAGEMENT REVIEW RESULTS

3-127

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M23 and finds it acceptable because when it is implemented it will ensure inspections of 

crane structural members for loss of material because of corrosion and rail wear and loss of 

preload caused by loose or missing bolts and nuts are performed consistent with the 

recommendations in the GALL Report.

Enhancement 2. LRA Section B2.1.12 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the program will be 

enhanced to include performance of periodic inspections as defined in the appropriate 

ASME B30 series standard for all cranes, hoists, and equipment handling systems within the 

scope of license renewal and that for handling systems that are infrequently in service, such as 

those only used during RFOs, periodic inspections may be deferred until just before use. 

GALL Report AMP XI.M23 recommends that visual inspections be conducted at a frequency in 

accordance with the appropriate ASME B30 series standard and that infrequently used systems 

be inspected just before use. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M23 and finds it acceptable because when it is 

implemented it will ensure that the periodic inspections will be performed consistent with the 

recommendations in the GALL Report.

Enhancement 3. LRA Section B2.1.12 states an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that the program will be enhanced 

to require evaluation of loss of material due to wear or corrosion and loss of bolting preload per 

the appropriate ASME B30 series standard. GALL Report AMP XI.M23 recommends that any 

visual indication of loss of material due to corrosion or wear and loss of bolting preload be 

evaluated in accordance with the appropriate ASME B30 series standard. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M23 

and finds it acceptable because when it is implemented it will ensure that indications of the 

aging effects will be evaluated in accordance with the applicable ASME B30 series standard, 

consistent with the recommendations in the GALL Report.

Enhancement 4. LRA Section B2.1.12 states an enhancement to the “corrective actions” 

program element. In this enhancement, the applicant stated that the program will be enhanced 

to require repairs to cranes, hoists, and equipment handling systems per the appropriate 

ASME B30 series standard. GALL Report AMP XI.M23 recommends that repairs for all cranes, 

hoists, and equipment handling systems within the scope of license renewal be performed as 

specified in ASME B30.2 or other appropriate ASME B30 series standard. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M23 

and finds it acceptable because when it is implemented it will ensure that repairs to cranes, 

hoists, and equipment handling systems are performed consistent with the recommendations in 

the GALL Report. 

Based on its audit of the applicant’s Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems Program, the staff finds that program elements one 

through six for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.M23. In addition, the staff 

reviewed the enhancements associated with the “parameters monitored or inspected,” 

“detection of aging effects,” “acceptance criteria,” and “corrective actions” program elements 

and finds that when implemented they will make the AMP adequate to manage the applicable 

aging effects.
AGING MANAGEMENT REVIEW RESULTS

3-128

Operating Experience. LRA Section B2.1.12 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program. The LRA states that in a review of Callaway corrective action documents over a 

10-year period none were found that identified corrosion or rail wear as a problem. The LRA 

also states that there were no occurrences of unacceptable corrosion, rail wear, or loose or 

missing fasteners for components within the scope of the Inspection of Overhead Load and 

Light Load (Related to Fuel Handling) Handling Systems Program. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M23 was evaluated. 

FSAR Supplement. LRA Section A1.12 provides the FSAR supplement for the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The 

staff reviewed this FSAR supplement description of the program and noted that it is consistent 

with the recommended description in SRP-LR Table 3.0-1. The staff also noted that the 

applicant committed (Commitment No. 8) to implement the enhancements to the program six 

months before the period of extended operation for managing aging of applicable components 

during the period of extended operation. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation through Commitment No. 8 six months before the period of extended 

operation will make the AMP adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

FSAR 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 Fire Protection 

Summary of Technical Information in the Application. LRA Section B2.1.13 describes the 

existing Fire Protection Program as consistent, with enhancements, with GALL Report 

AMP XI.M26, “Fire Protection.” The LRA states that the Fire Protection Program is a condition 
AGING MANAGEMENT REVIEW RESULTS

3-129

and performance monitoring program that comprises tests and inspections that follow applicable 

National Fire Protection Association (NFPA) recommendations. The LRA also states that the 

program manages loss of material for fire rated doors, fire dampers, and the halon system; 

concrete cracking, spalling, and loss of material for fire barrier walls, ceilings, and floors; and 

increased hardness, shrinkage, and loss of strength for fire barrier penetration seals. The LRA 

further states that the program includes visual inspections of fire barrier penetrations seals, 

walls, ceilings, floors, coatings, wraps, doors, dampers, and halon systems; and functional tests 

of fire doors and halon systems.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M26. For the “scope of 

program” and “detection of aging effects” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

GALL Report AMP XI.M26 is a fire barrier inspection program that includes aging management 

of fire barrier penetration seals, walls, ceilings, floors, doors, and other fire barrier materials 

within the “scope of program” program element. The LRA denotes AMR items with an intended 

function of fire barrier using an “FB.” The staff noted that there are AMR items in LRA 

Table 3.5.2-1 for the hatch emergency airlock and hatch personnel airlock exposed to plant 

indoor air, which have an intended function of fire barrier, but are not being managed for aging 

using the Fire Protection Program. It was not clear to the staff how components with a fire 

barrier-intended function are being adequately managed for aging using alternative programs. 

By letter dated July 5, 2012, the staff issued RAI B2.1.13-1 requesting that the applicant explain 

how the items with a fire barrier function that are not being managed for aging using the Fire 

Protection Program are being adequately managed for aging using alternative programs. 

In its response dated August 6, 2012, the applicant stated that the hatch emergency airlock and

hatch personnel airlock are both fire barriers that will be managed for aging using the Fire 

Protection Program. The applicant revised LRA Table 3.5.2-1 to include AMR items to manage 

of loss of material for the hatch emergency airlock and hatch personnel airlock using the Fire 

Protection Program consistent with LRA Table 3.3-1, AMR item 3.3.1.059. The staff finds the 

applicant’s response acceptable because the applicant is managing all the components with a 

fire barrier-intended function using the Fire Protection Program, consistent with the 

GALL Report recommendations. The staff’s concern described in RAI B2.1.13-1 is resolved.

The “detection of aging effects” program element of GALL Report AMP XI.M26 states that visual 

inspections of fire barrier penetration seals, walls, ceilings, floors, doors, and other fire barrier 

materials are performed by fire protection-qualified personnel. LRA Section B2.1.13 states that 

the Fire Protection Program, following enhancement, will be consistent with GALL Report 

AMP XI.M26. During the audit, the staff noted that procedures QSP-ZZ-65045, Revision 13, 

“Fire Barrier Seal Visual Inspection,” and QSP-ZZ-65046, Revision 13, “Fire Barrier Inspection,” 

state that the personnel performing the inspections are quality control inspectors. The staff also 

noted that procedure OSP-KC-00015, Revision 8, “Fire Door Inspections,” does not state what 

qualifications are required for personnel who perform the inspections.

Callaway’s FSAR-SP, Section 9.5.1.6, and FSAR-SA, Appendix 9.5A, Section A.1 both state 

that FSAR-SA Section 9.5 discusses training for maintaining the competence of the station fire 

fighting and operating crew, including personnel responsible for maintaining and inspecting the 

fire protection equipment. However, the information regarding training of personnel who 

maintain and inspect fire protection equipment does not appear to be included in the FSAR-SP 
AGING MANAGEMENT REVIEW RESULTS

3-130

or FSAR-SA. RG 1.189, “Fire Protection for Nuclear Power Plants,” states that personnel 

responsible for maintaining and testing fire protection systems should be qualified by training 

and experience for such work. However, neither the FSAR nor the LRA discuss the training and 

qualifications required for personnel responsible for performing Fire Protection Program 

inspections. By letter dated July 5, 2012, the staff issued RAI B2.1.13-2 requesting that the 

applicant explain the minimum training and qualifications required for personnel who perform 

Fire Protection Program inspections. The staff also requested the applicant to explain how only 

personnel with the required training and experience are assigned to perform Fire Protection 

Program inspections since a fire protection qualification is not used.

In its response dated August 6, 2012, the applicant stated that the personnel performing the Fire 

Protection Program inspections are qualified consistent with ASME N45.2.6-1978, 

“Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants.” 

The applicant also stated that the quality control personnel are trained and qualified to perform 

their activities in accordance with procedure QCP-ZZ-01000, “QC Inspector Qualification.” The 

applicant further stated that the operations personnel who perform fire door inspections are 

qualified by a specific watch station qualification program. However, the applicant did not 

discuss any specific fire protection-related training or qualifications required for personnel 

performing Fire Protection Program inspections. The staff noted that ASME N45.2.6-1978

requires that personnel performing inspections be qualified within their respective areas of 

responsibility. The staff also noted that the personnel performing Fire Protection Program 

inspections are quality control or operations personnel. It remained unclear to the staff how only 

personnel with the required training and experience in fire protection are assigned to perform 

Fire Protection Program inspections since a fire protection qualification is not used. Therefore, 

by letter dated October 1, 2012, the staff issued RAI B2.1.13-2a requesting that the applicant 

explain the specific fire protection-related training and experience that the quality control and 

operations personnel who perform Fire Protection Program inspections receive, and how only 

the personnel with fire protection-related training and experience are used to perform Fire 

Protection Program inspections. 

In its response dated October 31, 2012, the applicant stated that the quality control inspectors 

who perform Fire Protection Program inspections are certified Level II and Level III inspectors 

and that the inspections of fire barriers, penetration seals, or fireproofing are performed using 

Callaway surveillance procedures that contain specific acceptance criteria and have undergone 

review by the fire protection engineer and/or fire protection system engineer. In addition, the 

applicant stated that the operations personnel who perform fire protection program inspections 

are equipment operators who are also qualified to perform the job of "Equipment Operator 

Inside (Watchstation Qualified)." The applicant stated that “[a]n individual with this qualification 

has completed an [i]nside [e]quipment [o]perator qualification card which requires demonstrated 

proficiency in the areas of responsibility for an [i]nside [o]perator, including familiarity with the 

fire protection system through a [f]ire [p]rotection [s]ystem [w]alkdown [c]heckout.” The staff 

finds the applicant’s response acceptable because fire protection program inspection 

procedures have been reviewed by fire protection engineers, and the Level II and Level III 

quality control inspectors are capable of performing inspections in accordance with those 

procedures and evaluating the validity and acceptability of the inspection results. In addition, 

the qualification of operations personnel who perform fire protection program inspections 

provides sufficient training to allow those personnel to validate the operability of fire barriers. 

The staff’s concern described in RAI B2.1.13-2a is resolved.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” and “acceptance criteria” program elements 
AGING MANAGEMENT REVIEW RESULTS

3-131

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 B2.1.13 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements. In this enhancement, the LRA states that procedures will be enhanced to 

include visual inspections of the external surfaces of halon fire suppression system components 

for excessive loss of material caused by corrosion. GALL Report AMP XI.M26 recommends 

that visual inspections of halon systems be performed to detect any signs of corrosion. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M26 and finds it acceptable because when it is implemented it will ensure halon system 

visual inspections are performed consistent with the recommendations in the GALL Report.

Enhancement 2. LRA Section B2.1.13 originally stated an enhancement to the “monitoring and 

trending” program element to enhance procedures to include trending of the performance of the 

halon system during testing. By letter dated April 25, 2012, the applicant revised the LRA (LRA 

Amendment 1) to delete this enhancement because the procedure changes have been 

completed.

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M26 and finds it acceptable because it ensures that halon system testing 

is trended consistent with the recommendations in the GALL Report.

Based on its audit and review of the applicant’s responses to RAIs B2.1.13-1, B2.1.13-2 and 

B2.1.13-2a, the staff finds that program elements one though six for which the applicant claimed 

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

GALL Report AMP XI.M26. In addition, the staff reviewed the enhancements associated with 

the “parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” 

and “acceptance criteria” program elements and finds that when implemented they will make the 

AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.13 summarizes operating experience related to the 

Fire Protection Program. The LRA states an operating experience example in which a 

degraded fire barrier penetration seal was discovered by inspection before any leakage 

occurred. The seal was subsequently repaired. The LRA states another operating experience 

example in which a small section of structural steel fireproofing was found degraded during an 

inspection and repaired. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience, and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 
AGING MANAGEMENT REVIEW RESULTS

3-132

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M26 was evaluated.

FSAR Supplement. LRA Section A1.13 provides the FSAR supplement for the Fire Protection 

Program. The staff reviewed this FSAR supplement description of the program and noted that it 

is consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted 

that, as amended by letters dated April 25, 2012, and December 20, 2013, the applicant stated 

that the enhancements described in Commitment No. 9 have been completed. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fire Protection Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation through Commitment No. 9 will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

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

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Water System 

Summary of Technical Information in the Application. As amended by letter dated 

December 20, 2013, LRA Section B2.1.14 describes the existing Fire Water System Program as 

consistent, with exceptions and enhancements, with GALL Report AMP XI.M27, “Fire Water 

System.” The LRA states that the program manages loss of material and flow blockage for 

water-based fire protection systems, including piping, fittings, valves, fire pump casings, 

sprinklers, nozzles, hydrants, hose stations, standpipes, and water storage tanks. The LRA 

also states that the program includes flow testing, visual inspections, and sprinkler inspections 

performed consistent with NFPA codes and standards. The program also includes pipe wall 

thickness examinations and internal inspections of fire water piping. In addition to NFPA codes 

and standards, portions of the water-based fire protection system that are normally dry but 

periodically subject to flow that cannot be drained or allow water to collect are subjected to 

augmented testing or inspections. Also, portions of the system are normally maintained at 

operating pressure and monitored such that loss of system pressure is immediately detected 

and corrective actions are initiated. Samples are collected for MIC quarterly and when fire 

water piping and components are opened for maintenance or are accessible. Biofouling is 

prevented by periodically adding treatment chemicals such as an anti-scalant, a biopenetrant, 

and a biostat to the fire water system and when monitoring indicates they should be added. The 

staff notes that, as amended by letter dated April 23, 2014, the Fire Water System program 

manages loss of coating integrity on the internal surfaces of the fire water storage tanks.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M27. For the program 

description and “detection of aging effects” program element, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.
AGING MANAGEMENT REVIEW RESULTS

3-133

The program description and “detection of aging effects” program element of GALL Report 

AMP XI.M27 recommend that sprinklers that have been in place for 50 years be replaced or a 

representative sample of sprinklers be field service tested at a recognized testing laboratory in 

accordance with NFPA 25, “Inspection Testing and Maintenance of Water-Based Fire Protection 

Systems.” The LRA states that sprinklers will be replaced before 50 years in service or a 

representative sample of sprinklers will be tested, with testing repeated every 10 years. The 

Fire Water System Program does not discuss what type of testing will be performed or that 

testing will be performed in accordance with NFPA 25; therefore, it was unclear to the staff 

whether these statements are consistent with the GALL Report. By letter dated July 5, 2012, 

the staff issued RAI B2.1.14-1 requesting that the applicant clarify whether sprinkler field service 

testing will be performed at a recognized testing laboratory in accordance with NFPA 25. If

sprinkler field service testing will not be performed at a recognized testing laboratory in 

accordance with NFPA 25, the staff asked the applicant to explain the testing that will be 

performed, including test methods and acceptance criteria, and how this testing satisfies the 

guidance in NFPA 25.

In its response dated August 6, 2012, the applicant revised the LRA to clarify that it will replace 

sprinkler heads before reaching 50 years in service or test a representative sample of sprinklers 

at a recognized testing laboratory in accordance with NFPA 25, with additional representative 

samples of sprinklers tested at 10-year intervals thereafter. The staff finds the applicant’s 

response acceptable because sprinkler head testing or replacement will be performed in 

accordance with NFPA 25, which is consistent with the recommendations in GALL Report 

AMP XI.M27. The staff’s concern described in RAI B2.1.14-1 is resolved.

The program description and the “detection of aging effects” program element of GALL Report 

AMP XI.M27 recommend that sprinklers be tested in accordance with applicable NFPA codes 

and standards. NFPA 25 states that any sprinklers that show signs of physical damage, 

corrosion, or loading shall be replaced. In the first operating experience example of the 

“operating experience” program element, the LRA states that in 2005, 10 sprinkler heads were 

found with corrosion or damage. The LRA also states that two sprinkler heads were replaced 

and that the rest were cleaned. Review of CAR 200502420 during the audit identified that there 

were four sprinklers with damage, three with corrosion, and three with lint, but only two were 

documented as being replaced. It is unclear to the staff why only two of the sprinklers with 

identified damage, corrosion, or loading were replaced. This does not appear to be consistent 

with the guidance in NFPA 25 and, therefore, does not appear to be consistent with the 

recommendations in the GALL Report. By letter dated July 5, 2012, the staff issued 

RAI B2.1.14-2 requesting that the applicant explain why some of the corroded or damaged 

sprinklers were not replaced and why this is consistent with the guidance in NFPA 25 and 

GALL Report AMP XI.M27.

In its response dated August 6, 2012, as supplemented by letter dated August 21, 2012, the 

applicant stated that six of the sprinklers were cleaned to remove lint or tarnish, two were 

immediately replaced, and two had bent diffusers that were originally repaired but later 

replaced. The applicant also stated that the subject nozzles were evaluated to be fully 

functional as part of the remedial actions taken in the CAP. 

The staff finds the applicant’s response acceptable because cleaning and replacement of the 

sprinklers as well as the evaluation to confirm the full functionality of the sprinkler heads are 

adequate corrective actions. The staff’s concern described in RAI B2.1.14-2 is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-134

Subsequent to the applicant’s submittal of its LRA, the staff issued LR-ISG-2012-02, “Aging 

Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation,” which revised several AMPs including the guidance for 

AMP XI.M27, “Fire Water System.” By letter dated October 7, 2013, the staff issued RAI 3.0.3-3 

requesting that the applicant either describe how its Fire Water System program already 

addresses the issues identified in this revised guidance or provide adequate justification why its 

program does not need to address them. 

In its response dated December 20, 2013, the applicant stated that:

(a) The Fire Water System program will include the tests and inspections described in 

AMP XI.M27 Table 4a except for the following:

• The fire pumps do not have suction screens and therefore NFPA 25 

Section 8.3.3.7 is not applicable.

• Main drain tests are not conducted (NFPA Section 13.2.5). Alternative testing 

and inspections were cited as the basis for not conducting main drain tests, 

including annual fire protection loop flow tests; fire protection water system 

flushes; hydrant flushes; and wet pipe, deluge, and preaction system visual 

inspections. 

The staff noted that the basis for the exception lacked sufficient detail for it to 

conclude that the listed alternative tests and inspections are capable of detecting 

potential flow blockage in system risers. By letter dated March 25, 2014, the staff 

issued RAI 3.0.3-3a Request (1) requesting that the applicant describe the 

alternative tests and inspections with sufficient detail to demonstrate that they are

capable of detecting potential flow blockage in system risers.

In its response dated April 23, 2014, the applicant stated that, to address flow 

blockage, flow testing (verifying that the water supply provides the design 

pressure at the required flow) is performed at the hydraulically most limiting 

location in each major structure every 5 years, including two locations in the 

reactor building, three locations in the auxiliary building, one location in the 

radwaste building, two locations in the control building, and five locations in the 

turbine building. Every 3 years, each hose station valve is partially opened to 

verify no flow blockage. The hydraulically most limiting hose stations are 

normally located at the most remote point from the main header piping. Using 

these locations would include the risers and some distribution piping in the test 

flow path, whereas, use of the drain valves does not include the risers or the 

distribution piping to hose stations and spray systems in the flow path and would 

not reveal any obstructions to flow in that piping. In addition, annual main drain 

tests per NFPA Section 13.2.5 will be performed on a representative sample of 

20 percent of the main drains within the scope of license renewal. There are 21 

main drain valves within the scope of license renewal, so that 5 main drain tests 

will be performed annually. During annual testing one of the tests is performed in 

a radiologically controlled area.

The staff noted that LR-ISG-2012-02 states that the purpose of the test and 

inspections associated with AMP XI.M27 Table 4a is to provide “inspections and 

tests that are related to age-managing applicable aging effects that are 

associated with loss of material and flow blockage for passive long-lived in-scope 
AGING MANAGEMENT REVIEW RESULTS

3-135

components in the fire water system.” The staff also noted that the purpose of 

flow tests and main drain tests is to detect potential flow blockage. The staff 

further noted that NFPA 25 (2014 Edition) Sections 13.2.5 and 13.2.5.1 allow a 

reduced number of main drain tests to be conducted. It states: “[a] main drain 

test shall be conducted annually for each water supply lead-in to a building 

water-based fire protection system to determine whether there has been a 

change in the condition of the water supply. Where the lead-in to a building 

supplies a header or manifold serving multiple systems, a single main drain test 

shall be permitted.” The staff noted that testing 20 percent of the in-scope 

components is consistent with the extent of sampling in several GALL Report 

AMPs including XI.M32, XI.M33, and XI.M38.

The staff finds the applicant’s response acceptable because: (a) the alternative 

flow tests and hose station testing, both in number and scope of locations, 

provide insights concerning potential accumulation of corrosion products that are 

comparable to those gained from main drain testing; (b) in regard to the number 

of tests, the applicant has proposed to periodically perform 13 flow tests every 5 

years and every hose station valve is tested every 3 years; (c) in regard to the 

scope of testing, the testing will encompass piping located in five different 

buildings and every fire hose station is tested to ensure there is an open flow 

path; therefore, all buildings with in-scope components that are protected by the 

fire water system are tested in some manner; and (d) on an annual basis, 20 

percent of the in-scope main drains will be tested in accordance with NFPA 25. 

As a result the testing will provide adequate trendable results to determine if flow 

blockage is occurring in the piping. The staff’s concern described in 

RAI 3.0.3-3a Request (1) is resolved.

• The water spray fixed systems do not have main line strainers and therefore 

NFPA 25 Sections 10.2.1.7 and 10.2.7.1 are not applicable.

• The station does not have a foam water sprinkler system and therefore NFPA 25 

Sections 11.2.7.1, 11.3.2.6, and storage tank inspections are not applicable.

• The response to RAI 3.0.3-3 Request (a) states, “[t]he internal surface of piping 

and branch lines is inspected for foreign material every five years by flushing wet 

pipe system piping.” The response to Request (b) states, “[i]nternal visual 

inspections are performed during plant maintenance activities and the five year 

flush of wet pipe system piping.” 

The staff noted that the response to RAI 3.0.3-3 Request (a) related to NFPA 25 

Section 14.2 internal inspections appears to rely solely on flushes and not 

internal visual inspections. The staff has concluded that inspections conducted 

in accordance with NFPA 25 Section 14.2 should include internal visual 

inspections. While flushing procedures can detect loose corrosion products, 

internal conditions such as tubercules (NFPA Section 14.2.1.2) may not be 

detected with a flush. The response to Request (b) states that internal visual 

inspections will be conducted during maintenance activities and the 5-year flush 

of wet pipe systems; however, the minimum amount or percentage of piping that 

will be visually inspected was not stated. By letter dated March 25, 2014, the 

staff issued RAI 3.0.3-3a Request (3) requesting that the applicant state the 
AGING MANAGEMENT REVIEW RESULTS

3-136

minimum amount of wet pipe system piping, excluding private fire service main 

piping, that will be internally visually inspected on a 5-year basis.

In its response dated April 23, 2014, the applicant stated that it will perform 

inspections as recommended by NFPA 25 Section 14.2 (i.e., half of the systems 

in each building at 5-year intervals) on the eight in-scope wet-pipe systems. If 

sufficient foreign material is detected all the systems in the building will be 

inspected in that interval. The applicant also stated that the in-scope dry-pipe 

preaction systems are normally dry and pressurized with instrument air. These 

systems will be internally visually inspected following actuation, prior to return to 

service. The applicant further stated that, if sufficient foreign material is found to 

obstruct the piping or sprinklers, an obstruction investigation will be conducted in 

accordance with NFPA 25 Annex D. If the visual inspection detects surface 

irregularities that could be indicative of wall loss below nominal pipe wall 

thickness, followup volumetric examinations will be performed. 

The staff noted that GALL Report item AP-4 states that there are no aging effects 

requiring management and no recommended AMPs for steel piping exposed to 

dry air (equivalent of instrument air). The staff finds the applicant’s response 

acceptable because: (a) the inspections of the wet-pipe systems are consistent 

with LR-ISG-2012-02 AMP XI.M27 and NFPA 25; (b) although NFPA 25 

Section 14.2.1.5 recommends periodic internal inspections of dry-pipe and 

preaction systems, corrosion would not be anticipated based on the conditions of 

the air in the system; and (c) augmented inspections will be conducted on 

normally dry piping that is periodically subject to flow and where drainage may 

not occur as expected as described below in the response to RAI 3.0.2-3 

Request (d). The staff’s concern described in RAI 3.0.3-3a Request (3) is 

resolved.

The staff finds the applicant’s response to RAI 3.0.3-3 Request (a) acceptable because 

the fire water system inspections and tests are either consistent with LR-ISG-2012-02 

AMP XI.M27, which recommends sufficient inspections and tests (when accompanied by 

other testing and inspections recommended in AMP XI.M27), or the applicant has 

provided a sufficient basis for exceptions. The staff’s concern described in RAI 3.0.3-3 

Request (a) is resolved.

(b) “[w]hen internal visual inspections are used to detect loss of material, the inspection 

technique will be capable of detecting surface irregularities that could indicate wall loss 

to below nominal pipe wall thickness due to corrosion and corrosion product deposition. 

Where such irregularities are detected, follow-up volumetric wall thickness examinations 

will be performed.”

The staff finds the applicant’s response to RAI 3.0.3-3 Request (b) acceptable because it 

is consistent with LR-ISG-2012-02 AMP XI.M27. The staff’s concern described in RAI 

3.0.3-3 Request (b) is resolved. 

(c) “[w]all thickness examinations are not used in lieu of conducting flow tests or internal 

visual examinations.”

The staff finds the applicant’s response to RAI 3.0.3-3 Request (c) acceptable because it 

is consistent with LR-ISG-2012-02 AMP XI.M27. The staff’s concern described in RAI 

3.0.3-3 Request (c) is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-137

(d) The portions of the fire water system that are periodically subject to flow, but designed to 

be normally dry, will be identified and inspected prior to the period of extended 

operation. For those piping segments where drainage may not occur as expected 

(susceptible piping): (a) either a flow test or flush sufficient to detect potential flow 

blockage, or a visual inspection of 100 percent of the internal surface of the piping 

segments that cannot be drained or allow water to collect will be conducted; (b) 

inspections will be performed in each 5-year interval beginning 5 years prior to the 

period of extended operation; (c) a 100 percent baseline inspection will be performed 

prior to the period of extended operation with 20 percent of the inspections performed in 

each five year interval of the period of extended operation. The acceptance criterion is 

no debris that could obstruct pipe or sprinklers and minimum design wall thickness is 

maintained. In addition, in each 5-year interval of the period of extended operation, 20 

percent of the length of piping segments that cannot be drained or that allow water to 

collect will be subject to volumetric wall thickness examinations. The 20 percent of 

piping that is periodically inspected in each 5-year interval will be in different locations 

than previously inspected piping. If the results of a 100 percent internal visual inspection 

are acceptable, and the segment is not subsequently wetted, no further augmented tests 

or inspections will be performed.

The staff finds the applicant’s response to RAI 3.0.3-3 Request (d) acceptable in part. 

Conducting a flow test, flush or internal visual examination of 100 percent of the 

susceptible piping prior to the period of extended operation, and volumetrically 

determining wall thickness of 20 percent of the susceptible piping every 5 years is 

consistent with the augmented inspection recommendations of LR-ISG-2012-02 AMP 

XI.M27. However, it is not clear to the staff that conducting a flow test, flush or internal 

visual examination of 20 percent of the susceptible piping during the period of extended 

operation is sufficient to provide reasonable assurance that the flow blockage will not 

occur in this piping. The staff also noted that LRA Section B.2.14 states that 100 

percent of the susceptible piping would be subject to a flow test, flush or internal visual 

examination; however, as documented above, this conflicts with the RAI response. By 

letter dated March 25, 2014, the staff issued RAI 3.0.3-3a Request (2) requesting that 

the applicant provide the basis for why there is reasonable assurance that flow blockage 

will not occur in this piping.

In its response dated April 23, 2014, the applicant revised the response to 

RAI 3.0.3-3 Request (d) to state that 100 percent of the susceptible piping will have a 

flow test, flush or internal visual examinations in each 5-year interval, beginning 5 years 

prior to the period of extended operation.

The staff finds the applicant’s revised response acceptable because the responses to 

RAI 3.0.3-3 Request (d) and RAI 3.0.3-3a Request (2) are now consistent with the 

augmented inspections recommended in LR-ISG-2012-02 AMP XI.M27. The staff’s 

concern described in RAI 3.0.3-3 Request (d) and RAI 3.0.3-3a Request (2) is resolved. 

(e) LRA Sections A1.14, B1.15, B2.1.14, and B2.1.15 were revised to include the fire water 

storage tanks within the scope of the Fire Water System program in lieu of the 

Aboveground Metallic Tanks program.

The staff finds the response to RAI 3.0.3-3 Request (e) acceptable because it is 

consistent with LR-ISG-2012-02 AMP XI.M27, which recommends that aging effects 
AGING MANAGEMENT REVIEW RESULTS

3-138

associated with fire water storage tanks be managed by the Fire Water System program. 

The staff’s concern described in RAI 3.0.3-3 Request (e) is resolved.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements associated with exceptions and enhancements to determine if the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

these exceptions and enhancements follows.

Exception 1. LRA Section B2.1.14 states an exception to the “detection of aging effects” 

program element. In this exception, the applicant stated that it will perform power block hose 

station gasket inspections at least once every 18 months, which is in accordance with the 

applicant’s existing NRC-approved Fire Protection Program. GALL Report AMP XI.M27 

recommends that gasket inspections be performed annually. During the audit, the staff 

reviewed plant operating experience and did not identify any examples of gasket failures. 

The staff also reviewed recent gasket inspection results and noted that a minimal number of 

gaskets required replacement when inspected. The staff reviewed this exception against the 

corresponding program element in GALL Report AMP XI.M27 and finds it acceptable because 

the existing gasket inspection frequency is based on the NRC-approved Fire Protection 

Program and is adequate to identify degradation before loss of intended function. Also, given 

that gaskets are replaced periodically, an increased frequency of inspection would not be 

required as the plant enters the period of extended operation because the overall average age 

of the gaskets should not change. Therefore, current inspection results would be expected to 

be similar.

Exception 2. LRA Section B2.1.14 states an exception to the “detection of aging effects” 

program element. In this exception, the applicant stated that it will perform hydrostatic hose 

testing for hose stations that are more than 5 years old on a 3-year frequency. The staff noted 

that the “detection of aging effects” program element of GALL Report AMP XI.M27 recommends 

that fire hoses be hydrostatically tested annually in accordance with NFPA codes and 

standards. During the audit, the staff noted that hydrostatic testing had not been performed 

since 2007. The staff also noted that CAR 201110777 documents the failure of a fire hose 

when it was charged during fire brigade training in 2011. The staff noted that hydrostatic testing 

is not being performed in accordance with the frequency outlined in the existing Fire Protection 

Program or the frequency recommended in GALL Report AMP XI.M27. The staff also noted 

that its review of plant-specific operating experience revealed a hose failure, which occurred 

during testing at the existing frequency. It is not clear to the staff, therefore, why the existing 

frequency is acceptable to ensure detection of fire hose degradation before loss of the intended 

function. By letter dated July 5, 2012, the staff issued RAI B2.1.14-3 requesting that the 

applicant provide justification for why the existing fire hose hydrostatic testing frequency is 

adequate to identify degradation of fire hose before loss of intended function.

In its response dated August 6, 2012, the applicant stated that it has two categories of fire 

hoses—fire brigade hose and interior fire hose—for the fire hose stations. The applicant also 

stated that fire brigade hose will be tested annually, as recommended in GALL Report 

AMP XI.M27. The applicant revised the LRA to include an enhancement, discussed later in this 

section, to perform annual hydrostatic hose testing for the fire brigade hose. The applicant 

further stated that interior fire hose for fire hose stations is tested 5 years from installation and 

every 3 years thereafter, in accordance with its previously approved Fire Protection Program, as 

described in FSAR-SP Table 9.5.1-2.
AGING MANAGEMENT REVIEW RESULTS

3-139

The staff noted that NFPA 1962, “Standard for the Inspection, Care, and Use of Fire Hose, 

Couplings, and Nozzles, and the Service Testing of Fire Hose,” outlines different hydrostatic 

hose testing frequencies for an occupant use hose and a fire brigade hose. NFPA 1962 states 

that an occupant use hose shall be service-tested 5 years after manufacture and every 3 years 

thereafter, and fire brigade hoses shall be service-tested annually. The staff finds the 

applicant’s response acceptable because fire brigade hoses will be hydrostatically tested 

annually as recommended in the GALL Report, and fire hoses for fire hose stations will be 

tested consistent with the applicant’s CLB and NFPA 1962. The staff’s concern described in 

RAI B2.1.14-3 is resolved. The staff reviewed this exception against the corresponding program 

element in GALL Report AMP XI.M27 and finds it acceptable because fire hose testing will be 

performed in accordance with NFPA codes and standards, which is consistent with the 

GALL Report recommendations.

Exception 3. LRA Section B2.1.14 originally stated an exception to the “detection of aging 

effects” program element. In this exception, the applicant stated that it will perform fire hydrant 

flow tests every 3 years. The “detection of aging effects” program element of GALL Report 

AMP XI.M27 recommends that fire hydrants be flow tested annually in accordance 

with NFPA 25. The staff reviewed the results of the last three sets of fire hydrant flow tests. 

The staff noted that testing performed in 2011 indicated that approximately 25 percent of the 

hydrants tested failed to drain in the required time frame. The testing performed in 2007 

indicated that approximately 20 percent of the hydrants tested failed to drain properly, and 

testing performed in 2005 indicated that approximately 50 percent of the hydrants tested failed 

to drain as required. It is not clear to the staff how the existing frequency of 3 years is 

acceptable to identify degradation before loss of intended function, given that the recent 

performances of the hydrant flush have resulted in 20 to 50 percent of the hydrants failing. 

By letter dated July 5, 2012, the staff issued RAI B2.1.14-4 requesting that the applicant provide 

justification for why the existing hydrant flow testing frequency is adequate to identify 

degradation of the fire hydrants before loss of intended function.

In its response dated August 6, 2012, the applicant stated that the Fire Water System Program 

will be enhanced to include annual flow testing of fire hydrants consistent with NFPA 25. The 

applicant revised the LRA to delete this exception and include a new enhancement. The staff’s 

evaluation of the enhancement is discussed later in this section. The staff finds the applicant’s 

response acceptable because the exception has been deleted and an enhancement has been 

added to test fire hydrants consistent with the recommendations in GALL Report AMP XI.M27. 

The staff’s concern described in RAI B2.1.14-4 is resolved. 

Exception 4. As amended by letter dated December 20, 2013, LRA Section B2.1.14 contains 

an exception to the “detection of aging effects” program element. In this exception, the 

applicant stated that main drain tests are not conducted; however, as amended by letter dated 

April 23, 2014, the applicant deleted this exception based on the response to RAI 3.0.3-3a 

Request (1), above.

Enhancement 1. LRA Section B2.1.14, as amended by letter dated August 6, 2012, states an 

enhancement to the “preventive actions” program element. The applicant stated that the 

internal surfaces of the fire water storage tanks (FWSTs) will be recoated before the period of 

extended operation. As part of the Aboveground Metallic Tanks Program, the applicant 

identified corrosion, blistering, and delamination of the coating inside the FWSTs. The staff’s 

concern regarding aging management of the internal surfaces of FWSTs and evaluation of this 

enhancement is documented in SER Section 3.0.3.2.8 for the Aboveground Metallic Tanks 

Program.
AGING MANAGEMENT REVIEW RESULTS

3-140

Enhancement 2. As amended by letters dated October 31, 2012, and May 6, 2014, LRA 

Section B2.1.14 states an enhancement to the “parameters monitored or inspected,” “detection 

of aging effects,” and “acceptance criteria” program elements. The applicant stated that the 

program will be enhanced to include pipe wall thickness examinations every 3 years. Each 

3-year sample will include at least three locations for a total of 100 feet of above-ground fire 

water piping, and the locations will be selected based on system susceptibility to corrosion or 

fouling and evidence of performance degradation during system flow testing or flushes. In 

addition, internal inspections will be performed on accessible exposed portions of fire water 

piping during plant maintenance activities. When visual inspections are used to detect loss of 

material, the inspection technique will be capable of detecting surface irregularities that could 

indicate wall loss below nominal pipe wall thickness due to corrosion and corrosion product 

deposition and if this occurs, followup volumetric wall thickness examinations will be performed. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report XI.M27, considering the plant-specific operating experience and the applicant’s response 

to RAI B2.1.14-5a discussed below in the “operating experience” program element. The staff 

finds this enhancement acceptable because, when it is implemented, the associated inspections 

will be capable of detecting pipe wall degradation before an impact on the system’s ability to 

perform its intended function(s).

Enhancement 3. LRA Section B2.1.14, as amended by letter dated August 6, 2012, states an 

enhancement to the “detection of aging effects” program element. The applicant stated that the 

program will be enhanced to include annual hydrostatic hose testing of fire brigade hose. The 

“detection of aging effects” program element of GALL Report AMP XI.M27 recommends that fire 

hoses be hydrostatically tested annually in accordance with NFPA codes and standards. 

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M27 and finds it acceptable because, when it is implemented, it will 

ensure fire brigade hose is hydrostatically tested consistent with the GALL Report 

recommendations.

Enhancement 4. LRA Section B2.1.14 states an enhancement to the “detection of aging 

effects” program element. The applicant stated that the program will be enhanced to replace 

sprinkler heads before 50 years in service or representative samples will be submitted for 

field-service testing by a recognized testing laboratory in accordance with NFPA 25. The 

program will field-service test additional representative samples every 10 years thereafter. 

GALL Report AMP XI.M27 recommends that sprinkler heads be tested before reaching the 

50-year service life and at 10-year intervals thereafter. The staff reviewed this enhancement 

against the corresponding program element and the program description in GALL Report 

AMP XI.M27 and finds it acceptable because, when it is implemented, it will ensure sprinkler 

head testing is performed consistent with the recommendations in the GALL Report.

Enhancement 5. LRA Section B2.1.14, as amended by letter dated August 6, 2012, states an 

enhancement to the “detection of aging effects” and “acceptance criteria” program elements. 

The applicant stated that the program will be enhanced to include annual flow testing of fire 

hydrants in accordance with NFPA 25. The “detection of aging effects” program element of 

GALL Report AMP XI.M27 recommends that fire hydrants be flow tested annually in accordance 

with NFPA 25. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M27 and finds it acceptable because, when it is implemented, 

it will ensure fire hydrants are flow tested consistent with the recommendations in the 

GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-141

Enhancement 6. LRA Section B2.1.14 states an enhancement to the “monitoring and trending” 

program element. The applicant stated that the program will be enhanced to review and 

evaluate trends in flow parameters recorded during the NFPA 25 flow tests. GALL Report 

AMP XI.M27 recommends that results of system performance testing be monitored and trended. 

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.M27 and finds it acceptable because, when it is implemented, it will 

ensure flow testing results are monitored and trended.

Enhancement 7. As amended by letter dated December 20, 2013, LRA Section B2.1.14 states 

an enhancement to the “parameters monitored or inspected” and “detection of aging effects” 

program elements. The applicant stated that the program will be enhanced to inspect the 

internal surface of piping and branch lines for foreign material every 5 years by flushing wet-pipe 

system piping. However, as amended by letter dated April 23, 2014, based on the response to 

RAI 3.0.3-3a Request (3), above, this enhancement was deleted.

Enhancement 8. As amended by letter dated December 20, 2013, LRA Section B2.1.14 states 

an enhancement to the “parameters monitored or inspected” and “detection of aging effects” 

program elements. The applicant stated that the program will be enhanced to include 

augmented tests and inspections of wetted but normally dry piping segments that cannot be 

drained or that allow water to collect as described in the responses to RAI 3.0.3-3 Request (d) 

and RAI 3.0.3-3a Request (2) above. The staff reviewed this enhancement against the 

corresponding program elements in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because, when it is implemented, the program will include augmented testing of wetted but 

normally dry piping segments that cannot be drained or that allow water to collect consistent 

with LR-ISG-2012-02 AMP XI.M27. 

Enhancement 9. As amended by letter dated December 20, 2013, LRA Section B2.1.14 states 

an enhancement to the “detection of aging effects” program element. The applicant stated that 

the program will be enhanced to include checking for evidence of voids beneath the floor of the 

fire water storage tanks. The staff reviewed this enhancement against the corresponding 

program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when it is 

implemented, the program will include appropriate inspections of the tank bottom as 

recommended by LR-ISG-2012-02 AMP XI.M27 and NFPA 25 Section 9.2.6.5.

Enhancement 10. As amended by letter dated December 20, 2013, LRA Section B2.1.14 states 

an enhancement to the “detection of aging effects” program element. The applicant stated that 

the program will be enhanced to change the frequency of trip testing each deluge valve from 

every three years to every refueling outage. The staff reviewed this enhancement against the 

corresponding program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because, when it is implemented, the testing frequency of the deluge valves will be as 

recommended by LR-ISG-2012-02 AMP XI.M27 and NFPA 25 Sections 13.4.3.2.2 and 

13.4.3.2.2.3, which allow testing to be conducted on a refueling outage interval due to the 

nature of the protected property. 

Enhancement 11. As amended by letter dated December 20, 2013, LRA Section B2.1.14 states 

an enhancement to the “detection of aging effects” program element. The applicant stated that 

the program will be enhanced to change the frequency of spray/sprinkler nozzle discharge 

pattern tests from every three years to every refueling outage. The staff reviewed this 

enhancement against the corresponding program element in LR-ISG-2012-02 AMP XI.M27 and 

finds it acceptable because, when it is implemented, the test frequency of spray/sprinkler nozzle 
AGING MANAGEMENT REVIEW RESULTS

3-142

discharge patterns will be as required by NFPA 25 Section 10.3.4.3, as modified by 

LR-ISG-2012-02 AMP XI.M27 to permit testing on a refueling outage interval.

Enhancement 12. As amended by letter dated December 20, 2013, LRA Section B2.1.14 states 

an enhancement to the “detection of aging effects” program element. The applicant stated that 

the program will be enhanced to include the tests and inspections listed in NFPA 25 Section 

9.2.7, items (1) through (6), whenever pitting, corrosion, or coating failure is found during the 

inspection of the fire water storage tanks. The staff reviewed this enhancement against the 

corresponding program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because, when it is implemented, when pitting, corrosion, or coating failure is found during the 

inspection of the fire water storage tanks, the additional tank and coating inspections

recommended by LR-ISG-2012-02 AMP XI.M27 and NFPA 25 Section 9.2.7 will be conducted.

Enhancement 13. As amended by letter dated December 20, 2013, LRA Section B2.1.14 states 

an enhancement to the “acceptance criteria” program element. The applicant stated that the 

program will be enhanced to require the removal of foreign material if its presence is found 

during pipe inspections to obstruct pipe or sprinklers and that the source of the material is 

determined and corrected. The staff reviewed this enhancement against the corresponding 

program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because when it is 

implemented, the requirements are consistent with the “acceptance criteria” program element of 

LR-ISG-2012-02 AMP XI.M27.

Enhancement 14. As amended by letter dated April 23, 2014, LRA Section B2.1.14 states an 

enhancement to the “detection of aging effects” program element. The applicant stated that the 

program will be enhanced to perform annual main drain tests consistent with NFPA 25 

Section 13.2.5 on a representative sample of 20 percent of the main drains within the scope of 

license renewal, including one in the radiologically controlled area, in order to check for potential 

flow blockage in system risers. The staff’s evaluation of this enhancement is documented with 

the response to RAI 3.0.3-3a Request (1), above.

Enhancement 15. As amended by letter dated April 23, 2014, LRA Section B2.1.14 states an 

enhancement to the “detection of aging effects” program element. The applicant stated that the 

program will be enhanced to include inspections of wet-pipe and dry-pipe systems as described 

in the response to RAI 3.0.3-3a Request (3), above. The staff’s evaluation of this enhancement 

is documented with the response to RAI 3.0.3-3a Request (3). 

Based on its audit and review of the applicant’s responses to RAIs B2.1.14-1, B2.1.14-2, 

B2.1.14-3, B2.1.14-4, 3.0.3-3, and 3.0.3-3a, the staff finds that the program elements for which 

the applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of LR-ISG-2012-02 AMP XI.M27. The staff also reviewed the exceptions 

associated with the “detection of aging effects” program element, and their justifications, and 

finds that the AMP, with the exceptions, is adequate to manage the applicable aging effects. In 

addition, the staff reviewed the enhancements associated with the “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements and finds that, when they are implemented, they will 

make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.14 summarizes operating experience related to the 

Fire Water System Program. One operating experience example in the LRA states that there 

was a leak in the fire water system in 2005 that was identified by excessive jockey pump run 

times. CAR 200510105 clarifies that the leak was in buried piping on an isolable branch. 

Another operating experience example in the LRA states that a low cleanliness factor was 
AGING MANAGEMENT REVIEW RESULTS

3-143

identified during system flow testing and, as a result, chemical cleaning was performed on the 

fire water system in 2006 to improve the cleanliness factor. However, after chemical cleaning, 

five leaks developed, which were subsequently repaired. 

The staff reviewed operating experience information in the application and during the audit to 

determine if the applicant reviewed the applicable aging effects and industry and plant-specific 

operating experience. As discussed in the audit report, the staff conducted an independent 

search of the plant operating experience information to determine if the applicant had 

adequately evaluated and incorporated operating experience related to this program. During its 

review, the staff identified operating experience for which it determined the need for additional 

clarification and resulted in the issuance of an RAI, as discussed below.

During the audit, the staff noted that MIC contributed to the low cleanliness factor and leakage 

operating experience examples discussed in the LRA and that additional leaks occurred after 

the chemical cleaning. The staff also noted that system flow testing performed in 2011 

identified a low cleanliness factor again and that compensatory measures were required to 

maintain system-intended function. The LRA states that flow testing is performed every 3 years 

and that pipe wall thickness examinations will be performed before the period of extended 

operation and every 10 years. Given that the fire water system degraded from a clean system 

in 2006 to a degraded system in 2011, in which compensatory measures were required to 

maintain system-intended function, it is not clear to the staff how the existing testing and 

inspection activities are adequate to ensure aging is identified before loss of intended function 

throughout the period of extended operation. By letter dated July 5, 2012, the staff issued 

RAI B2.1.14-5 requesting that the applicant do the following:

(a) List, for the past 10 years, each instance of internal or external degradation of the fire 

protection piping that resulted in either through-wall or significant penetration of the pipe 

wall, including any out-of-scope piping instances where the environment is similar to that 

of in-scope piping.

(b) Describe the results of general internal and external observations of the condition of the 

piping and coatings that have been conducted for the past 10 years.

(c) Project the condition of the internal and external surfaces of the fire protection system 

in-scope piping through the end of the period of extended operation.

(d) State the basis for why the configuration of the in-scope fire protection system will have 

sufficient structural integrity to meet all design loads throughout the period of extended 

operation. Include consideration of multiple flaws located in a configuration such that 

they cannot be considered as independent flaws.

(e) State how the inspections of the fire water system will be augmented to ensure that the 

assumptions used in the response to (d) above will be met throughout the period of 

extended operation.

In its response dated August 6, 2012, to RAI B2.1.14-5, Part (a), the applicant provided a 

summary of the internal and external degradation identified in fire protection piping from 

2001–2012. The staff noted that the applicant identified two instances of leakage from the 

buried high-density polyethylene (HDPE) fire protection piping installed in 2007 that were 

attributed to poor fusion during installation. Although this fire protection piping is not within the 

scope of license renewal, similar replacements were performed in the in-scope ESW system. 
AGING MANAGEMENT REVIEW RESULTS

3-144

The staff finds the applicant’s response related to providing the past 10 years of plant-specific 

operating experience acceptable because the applicant’s summary of occurrences of 

degradation provided the staff with an understanding of all the instances of internal or external 

degradation of the fire protection piping for the past 10 years, as well as the applicant’s level of 

understanding of the cause of each event. However, the staff lacked sufficient information to 

conclude that poor fusion failures will not occur on the in-scope ESW piping, given that the fire 

water system failures did not reveal themselves for at least 3 months and upwards of 46 months 

after installation. By letter dated October 3, 2012, the staff issued RAI B2.1.14-5a, Part (a) 

requesting that the applicant state the basis for why the inspections being conducted in 

accordance with the Buried and Underground Piping and Tanks Program will be sufficient to 

detect poor fusion of in-scope ESW piping or state the basis for why this failure mechanism is 

not applicable to the piping.

In its response to RAI B2.1.14-5a, Part (a), dated October 31, 2012, the applicant stated that the 

ESW piping was designed and installed consistent with ASME Code Class 3 quality controls, 

whereas the fire water piping was installed as commercial grade piping; the fusion joints, which 

leaked, were not within the scope of license renewal; and the fusion process for the fire water 

system joints was not subject to the same quality controls as the ESW piping. The applicant 

also stated the following:

• The ESW HDPE material was traceable to the resin supplier and pipe manufacturer.

• The resin manufacturer performed burst testing in accordance with ASTM D 1599, 

“Standard Test Method for Resistance to Short-Time Hydraulic Pressure of Plastic Pipe, 

Tubing, and Fittings.”

• Performance testing was conducted on fused joint test coupons.

• The fusion procedure, fusion machine and fusion machine operators were qualified.

• NDE was performed on the fused joints by qualified NDE inspectors.

• The joints were visually inspected, an ultrasonic time-of-flight diffraction examination 

was performed, and a hydrostatic test was conducted. 

The applicant further stated that the ESW HDPE piping was installed in 2008 and early 2009,

and none have leaked.

The staff finds the applicant’s response acceptable because sufficient controls were established 

to provide reasonable assurance that the materials and installation processes were effective in 

regard to installing fused HDPE joints. In addition, the ultrasonic time-of-flight diffraction 

examination technique is an industry-recognized means of detecting cracking in joints 

(e.g., EN 583-6, “Non-destructive testing – Ultrasonic examination – Part 6: Time-of-flight 

diffraction technique as a method for detection and sizing of discontinuities,” ASM Handbook, 

Volume 19, “Fatigue and Fracture,” 1996, Time of Flight Measuring Techniques, page 217). 

This method is also endorsed in NUREG/CR-7136 PNNL-20300, “Assessment of NDE Methods 

on Inspection of HDPE Butt Fusion Piping Joints for Lack of Fusion” Section 3.3, “Ultrasonic 

Time-of-Flight Diffraction.” The staff’s concerns described in RAIs B2.1.14-5, Part (a), and 

B2.1.14-5a, Part (a), are resolved.

In its response, dated August 6, 2012, to RAI B2.1.14-5, Part (b), the applicant stated that there 

have been no failures in the fire protection system piping related to internal aging effects since 

2001. The applicant also stated that, before the chemical cleaning, the system was susceptible 

to fouling because of corrosion products and tuberculation generated within the system itself, 
AGING MANAGEMENT REVIEW RESULTS

3-145

which caused the failed fire main flow test in 2004. Subsequent to the chemical cleaning 

conducted in 2006 to remove the corrosion products from the pipe wall, several leaks were 

revealed in out-of-scope piping. After chemical cleaning, the fire main flow test failed again in 

2009 and 2011, but the applicant identified inaccuracies in the calculation and conservatisms 

that could be eliminated to achieve acceptable results, confirming the operability of the system. 

The applicant further stated (in the response to Part (d) of this RAI), that, in 2011, visual 

inspection of the internal and external surfaces of excavated fire hydrant piping was performed. 

The inspections identified no physical damage or breaks in the coating and found no signs of 

microbial infestation. In June 2012, internal visual inspections of seven different locations in the 

turbine building were performed, and no adverse conditions were noted. The applicant stated 

that biological corrosion of the internals of the piping is mitigated by the use of a biopenetrant 

and biostat.

The staff finds the applicant’s response to RAI B2.1.14-5 Part (b) acceptable because sufficient

general information was provided on the internal and external observations of the condition of 

the piping and coatings that have been conducted for the past 10 years for the staff to 

understand the fire water system conditions and evaluate the applicant’s proposed aging 

management program. The staff’s concern described in RAI B2.1.14-5 Request (b) is resolved. 

However, the staff noted the following in relation to flow testing results: 

• Failure of the flow test in 2004 was attributed to accumulated corrosion products. 

The corrective action was to conduct chemical cleaning in 2006, and the subsequent 

flow test met acceptance criteria.

• Failure of the flow test in 2009 was attributed to a combination of factors related to the 

test procedure and the flow calculation, such as gauge elevation, rounding error, and 

rerouting of fire piping. Upon revision of the calculation and flow test procedure, the flow 

test met acceptance criteria.

• Failure of the flow test in 2011 was attributed to unnecessary conservatisms in the flow 

calculation, such as how much additional flow was assumed to hose stations and yard 

hydrants coincident with sprinkler demand, as compared to the licensing basis value. 

Additionally, the calculation used to determine pipe wall cleanliness was rewritten, 

including taking credit for actual fire pump performance. Upon revision of the 

calculations, the flow test met acceptance criteria.

Although the applicant has identified contributing factors to the flow test failures and has been 

able to revise the procedure to verify operability of the system, the test results indicate that the 

condition of the fire main is degrading, and the applicant has not identified a cause. For 

example, the 2006 test was passed without the improvements in the test’s procedures and 

calculations identified during the analyses of the 2009 and 2011 test results. Likewise, the 2009 

test was passed without the improvements in the calculations identified during the analysis of 

the 2011 test results. It was not clear to the staff what caused the extensive buildup of 

corrosion products and tuberculation that contributed to the failed fire main flow tests, and 

whether the existing flow testing frequency is adequate to identify degradation before loss of 

intended function given the repeat failures at the existing frequency. 

The staff noted that the applicant identified four instances in which buried piping experienced 

leakage but the cause could not be determined because the piping was abandoned in place or 

isolated. As a result of two of these cases, the entire length of piping between the plant and the 

training center was abandoned in place, and new HDPE piping was installed. The applicant 

stated that these leaks occurred just after chemical cleaning of the system, yet the applicant did 
AGING MANAGEMENT REVIEW RESULTS

3-146

not attribute any leakage to internal aging effects other than fouling caused by corrosion 

products in its summary table in response to the staff’s request. In addition, for at least one of 

the cases in which external corrosion was listed as the cause of the failure, the staff reviewed 

pictures of the failed piping during the audit, which indicated that loss of material because of 

internal corrosion also was present in the piping and could have contributed to the failure. It 

was unclear to the staff if the applicant has adequately evaluated whether loss of material 

caused by corrosion is contributing to leakage from the system.

By letter dated October 3, 2012, the staff issued RAI B2.1.14-5a, Part (b), requesting that the 

applicant state the cause of the extensive buildup of non-microbial corrosion products and 

tuberculation that contributed to the failed fire main flow tests and leakage that developed after 

chemical cleaning, the basis for acceptability of the existing fire main flow testing frequency for 

identifying degradation before loss of intended function, and the basis for why loss of material 

caused by corrosion is not contributing to leakage from the system.

In its response dated October 31, 2012, the applicant stated that the 2004 flow test failure was 

caused by buildup of deposits because the steel piping was exposed to raw water for over 

20 years and that chemical cleaning in 2006 was conducted to remove accumulated corrosion 

products. The applicant also stated that the inspection program described in the response to 

Part (d), below, will manage internal corrosion such that the system will be able to perform its 

intended function.

The staff finds the applicant’s response acceptable, in part, because the wall thickness testing 

described below will be adequate to detect through-wall or partial-wall degradation of the piping 

before an impact on the ability of the system to perform its intended function. The staff’s 

evaluation is below. However, the flow testing in 2004, 2006, 2009, and 2011 demonstrates a 

decreasing trend in fire water system flow performance. The staff lacked sufficient information 

to conclude that conducting flow testing every 3 years will provide reasonable assurance that 

the fire water system will perform its intended function during the period of extended operation. 

The staff’s concerns, described in RAI B2.1.14-5a, Part (b), are not resolved. By letter dated 

January 14, 2013, the staff issued RAI B2.1.14-5b, Part (a), requesting that, in light of the 

decreasing trend in system performance, the applicant state the basis for why flow testing of the 

system every 3 years will be sufficient to ensure the system can perform its intended function 

during the period of extended operation. 

In its response dated January 24, 2013, the applicant stated that, based on the performance 

trending of data from the 2006, 2009, and 2011 flow tests, the test will be conducted initially 

every two years in lieu of the three-year interval stated in the FSAR. This test frequency has 

been adopted to facilitate establishing a trend based on the current flow test procedures. The 

test results are trended to ensure that adequate margin, including anticipated degradation and 

corrective action, exists through the next flow test. The next flow test is scheduled for 2013. 

Given the procedurally-allowed 25 percent grace period for testing intervals, at least four and up 

to eight tests will be conducted prior to the period of extended operation. If a test yields results 

that do not meet the acceptance criteria established in the test, it will be documented in the 

Corrective Action Program. Depending on the results, the corrective actions for tests not 

meeting acceptance criteria could include pipe cleaning, refurbishment, or replacement.

The staff finds the applicant’s response acceptable because (a) reducing the test interval from 

three years to two years is adequate to establish a trend of system performance using current 

flow test procedures, (b) unacceptable test results will be entered into the Corrective Action 
AGING MANAGEMENT REVIEW RESULTS

3-147

Program, and (c) there are corrective actions available that could restore margin if the trend is 

not acceptable (e.g., pipe cleaning, refurbishment, or replacement).

The staff’s concerns described in RAI B2.1.14-5a, Part (b) and RAI B2.1.14-5b, Part (a), are

resolved.

In its response dated August 6, 2012, to RAI B2.1.14-5, Part (c), the applicant stated that 

microbial corrosion inspections, coatings, and pipe wall thickness measurements will be used, 

as follows, to project the condition of the fire protection system piping through the period of 

extended operation:

• Opportunistic visual inspections are performed and MIC samples are obtained. If active 

MIC colonies are discovered, corrective actions are taken to mitigate the effects of MIC.

• Coatings and cathodic protection are used to protect the external surfaces of the fire 

protection system piping.

• The Fire Protection Program will be enhanced to conduct NDE testing to determine 

general wall thickness. A sampling plan will be used with locations selected based on 

susceptible locations identified from opportunistic inspections and chemistry sampling.

The staff finds the applicant’s response acceptable, in part, because preventive actions for the 

external surfaces (i.e., coatings and cathodic protection) are used; biological corrosion of the 

piping internals is mitigated by the use of a biopenetrant and biostat (as stated in the reply to 

Part (b) of RAI B2.1.14-5); and opportunistic inspections and analyses are performed to confirm 

that MIC is not occurring. However, it was unclear to the staff why the MIC sampling plan and 

NDE testing plan are not credited for aging management of the fire water system for license 

renewal. By letter dated October 3, 2012, the staff issued RAI B2.1.14-5a, Part (c), requesting 

that the applicant include these activities in the Fire Water System Program for license renewal. 

In its response dated October 31, 2012, to RAI B2.1.14-5a, Part (c), the applicant stated the 

following:

• MIC samples are collected quarterly and when fire water piping and components are 

opened for maintenance or are accessible.

• The MIC Index is trended to evaluate treatment effectiveness in specific locations.

• Biofouling is prevented by adding treatment chemicals such as an anti-scalant, a 

biopenetrant, and a biostat to the fire water system annually and when monitoring 

indicates they should be added.

• Wall thickness measurements will be performed on fire water piping every 3 years.

The applicant also stated that each 3-year sample will include at least three locations, for a total 

of at least 30.5 meters (100 feet) of above-ground fire water piping and will be selected based 

on system susceptibility to corrosion or fouling and evidence of performance degradation during 

system flow testing or flushes. Wall thickness measurements will use a LFET or an equivalent 

as a screening tool to identify “spots of interest,” which are then followed up with UT testing on 

the spots of interest. With the exception of trending of the MIC index, LRA Sections A1.14 and 

B2.1.14 were revised to reflect the above as well as Commitment No. 10. 

The staff finds the applicant’s response acceptable, in part, because, with the exception of MIC 

Index trending, the applicant included MIC sampling, biofouling treatments, and wall thickness 
AGING MANAGEMENT REVIEW RESULTS

3-148

measurements into the program. However, the staff noted that the applicant did not revise LRA 

Section B2.1.14 to include MIC Index trending to evaluate treatment effectiveness in specific 

locations. The staff’s concerns described in RAIs B2.1.14-5, Part (c) and B2.1.14-5a, Part (c) 

are resolved with the exception of MIC Index trending. By letter dated January 14, 2013, the 

staff issued RAI B2.1.14-5b, Part (b), requesting that the applicant revise LRA Section B2.1.14 

to include MIC Index trending. 

In its response dated January 24, 2013, the applicant revised LRA Sections B2.1.14 and A1.14 

to include MIC Index trending.

The staff finds the applicant’s response acceptable because the MIC Index provides input into 

chemical treatment effectiveness, and by revising the program and FSAR supplement, this 

parameter will be utilized through the period of extended operation. The staff’s concern 

described in RAI B2.1.14-5b, Part (b), is resolved.

In its response, dated August 6, 2012, to RAI B2.1.14-5, Part (d), the applicant stated that the 

internal surfaces of fire protection system piping are monitored through the Raw Water Systems 

Control Program and the Raw Water Predictive Maintenance Program. The Raw Water 

Systems Control Program performs MIC culture samples when piping becomes accessible. 

The Raw Water Preventive Maintenance Program ensures engineering performs inspections of 

the piping for structural integrity. The applicant also stated that, before 1996, the fire water was 

untreated, but that currently an anti-scalant, biopenetrant, and biostat are added to the FWSTs 

weekly and in conjunction with the yearly fire main flush. 

The applicant further stated that the external surfaces of the fire protection system piping are 

managed by the Buried and Underground Piping and Tanks Program, which will be augmented 

for license renewal. It was unclear to the staff how opportunistic visual inspections of the fire 

water system piping are adequate to ensure the structural integrity of the piping, given the 

unknown cause of past piping failures and failed flow tests. It was also unclear to the staff why 

the activities in the Raw Water Systems Control and Raw Water Maintenance Programs, 

including the water treatment activities, are not credited for aging management of the fire 

protection system for license renewal. By letter dated October 3, 2012, the staff issued 

RAI B2.1.14-5a, Part (d), requesting that the applicant state the basis for why opportunistic 

visual inspections are adequate to ensure the structural integrity of the system and to include 

the activities of the Raw Water Systems Control and the Raw Water Predictive Maintenance 

Programs into the Fire Water System Program for license renewal.

In its response dated October 31, 2012, to RAI B2.1.14-5a, Part (d), the applicant repeated a 

summary of the examinations and testing described in the response to Part (c).

The staff finds the applicant’s response acceptable because:

• Rather than crediting the Raw Water Systems Control and Raw Water Maintenance 

Programs’ activities related to MIC sampling and wall thickness inspections for aging 

management of the fire protection system for license renewal, these provisions have 

been incorporated into the fire water system AMP.

• As described in the response to Part (d), LRA Sections A1.14 and B2.1.14 were revised 

to reflect the above as well as Commitment No. 10.

• Appropriate preventive actions are used to mitigate external and internal corrosion 

(i.e., coatings, cathodic protection, and chemical additions).
AGING MANAGEMENT REVIEW RESULTS

3-149

• Inspecting for wall thickness of 100 feet of pipe (over multiple locations) every 3 years, 

commencing after 2014 (reference Commitment No. 10), will result in 400 feet of pipe 

being inspected before the period of extended operation and an additional 600 feet 

during the period of extended operation. On a comparable basis, GALL Report AMP 

XI.M41, “Buried and Underground Piping and Tanks,” Table 4a, “Inspections of Buried 

Pipe,” recommends that 600 feet of piping be inspected starting ten years prior and 

extending through the end of the period of extended operation for a buried piping system 

that has adverse plant-specific OE. Based on this comparison, inspecting 1000 feet of 

pipe provides sufficient information to project the condition of the internal and external 

surfaces of the fire protection system in-scope piping through the end of the period of 

extended operation.

• In addition to a sufficient number of inspections being conducted, the applicant will 

inform the location of inspections based on system susceptibility to corrosion or fouling 

and evidence of performance degradation during system flow testing or flushes. This is 

consistent with GALL Report AMPs that use a sampling basis (e.g., AMP XI.M41, 

“Buried and Underground Piping and Tanks,” AMP XI.M32, “One-Time Inspection”).

• The staff’s evaluation of using the LFET technique to screen for wall thickness 

degradation is documented in SER Section 3.0.3.2.8.

The staff’s concerns addressed in RAIs B2.1.14-5, Part (d), and B2.1.14-5a, Part (d), are 

resolved.

In its response dated August 6, 2012, to RAI B2.1.14-5, Part (e), the applicant stated that the 

Fire Water System Program will be enhanced to include a sampling plan for performing NDE 

testing to determine general wall thickness. Locations will be selected based on susceptible 

locations and information from inspections and chemistry sampling. The staff noted that the 

applicant’s enhancement states that the program will be enhanced to include non-intrusive pipe 

wall thickness examinations or internal visual inspections before the period of extended 

operation and at 10-year intervals thereafter. The enhancement does not discuss the basis for 

where inspections will be conducted or the basis for the 10-year frequency. From the 

information requested, there does not appear to be a corrosion rate established for the fire 

protection system piping; the staff also noted that failures have occurred much more frequently 

than 10 years apart. By letter dated October 3, 2012, the staff issued RAI B2.1.14-5a, Part (e), 

requesting that the applicant state the basis for the chosen inspection frequency, inspection 

sample size, and inspection location selection criteria and include this information in the Fire 

Water System Program. 

In its response dated October 31, 2012, to RAI B2.1.14-5a, Part (e), the applicant stated that the 

basis for the inspection frequency (i.e., 100 feet of pipe covering 3 locations every 3 years) is 

that it is the same frequency as the yard fire loop flush and the flow tests of the fire water loops, 

which is set by FSAR Table 9.5.1-2 SP, items 2.4 and 2.7. The applicant reiterated the basis for 

sample location selection criteria as stated in Part (c) above. Also, as stated in Part (c) above, 

the Fire Water System Program was amended to address the sample size, frequency, and 

location selection basis for the wall thickness inspections.

The staff finds the applicant’s response acceptable because the applicant (a) amended its 

program to inspect 100 feet of pipe covering 3 locations every 3 years as opposed to an 

unspecified number of inspections every 10 years, (b) inspection locations will be selected 

based on system susceptibility to corrosion or fouling and evidence of performance degradation 

during system flow testing or flushes, and (c) a frequency of 3 years is consistent and 
AGING MANAGEMENT REVIEW RESULTS

3-150

corresponds with the applicant’s CLB as documented in FSAR Table 9.5.1-2 SP; therefore, the 

inspections are sufficient to provide reasonable assurance that degradation of pipe wall 

thickness will be discovered and corrected before impacting the ability of the system to perform 

its intended function(s), and the appropriate changes have been made to the program, FSAR 

Supplement and Commitment No. 10. The staff’s concern described in RAI B2.1.14-5a, 

Part (e), is resolved.

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

RAIs B2.1.14-5, B2.1.14-5a, and B2.1.14-5b, the staff finds that the applicant has appropriately 

evaluated plant-specific and industry operating experience and that implementation of the 

program has resulted in the applicant taking corrective action. In addition, the staff finds that the 

conditions and operating experience at the plant are bounded by those for which GALL Report 

AMP XI.M27 was evaluated.

FSAR Supplement. LRA Section A1.14, as amended by letters dated August 6, 2012, October 

31, 2012, January 24, 2013, December 20, 2013, April 23, 2014, and May 6, 2014, provides the 

FSAR supplement for the Fire Water System Program. The staff reviewed this FSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in LR-ISG-2012-02 Table 3.0-1. The staff also noted that the applicant committed 

(Commitment No. 10) to enhance the Fire Water System Program procedures to implement 

Enhancement Nos. 1–6 and 8-15 during the period of extended operation; with some program 

elements being implemented between 5 years and 6 months prior to the period of extended 

operation (Enhancements Nos. 1 and 8). 

The staff noted that by letter dated April 23, 2014, the applicant amended Commitment No. 10 

to state that it will revise the procedure and calculation used to change test and inspection 

frequencies associated with the NFPA 805, “Performance-Based Standard for Fire Protection 

for Light Water Reactor Electric Generating Plants,” license amendment (Amendment 206) to 

include the following restrictions:

• EPRI Report 1006756, “Fire Protection Equipment Surveillance Optimization and 

Maintenance Guide,” will be used to adjust test and inspection frequencies.

• Data to be used in analyzing the potential for modifying test and inspection frequencies 

would not be obtained any earlier than 5 years prior to the [period of extended 

operation].

• A minimum sample size consistent with EPRI Report 1006756 Section 11.2 will be used 

to modify test and inspection frequencies.

• EPRI Report 1006756 would not be used to modify: fire water storage tank 

inspections/tests, underground flow tests, and inspections of normally dry but 

periodically wetted piping that will not drain due to its configuration.

The staff finds this change acceptable because: (a) use of EPRI Report 1006756 is consistent 

with the applicant’s current licensing basis (ADAMS Accession No. ML13274A596); 

(b) modification of testing frequencies will be based on data obtained no earlier than 5 years 

prior to the period of extended operation which is consistent with GALL Report AMP XI.M33, 

which ensures that the in-scope components have had an adequate aging period prior to using 

inspections as input for determining potential changes to subsequent inspection intervals; 

(c) EPRI Report 1006756 Section 11.2 includes industry-standard guidance for selecting the 

number of data points to be used in potentially adjusting test and inspection frequencies; and 

(d) the applicant stated that it will not use the methodology to adjust the frequency of fire water 
AGING MANAGEMENT REVIEW RESULTS

3-151

storage tank inspections/tests, underground flow tests, and inspections of normally dry but 

periodically wetted piping that will not drain due to its configuration, which are included in the 

program based on plant-specific or industry operating experience.

The staff finds that the information in the FSAR supplement, as amended by letters dated 

through May 6, 2014, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fire Water System Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determines that the AMP, with the exceptions, is adequate to manage the 

applicable aging effects. Also, the staff reviewed the enhancements and confirmed that their 

implementation through Commitment No. 10 six months before the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Aboveground Metallic Tanks 

Summary of Technical Information in the Application. LRA Section B2.1.15 describes the new 

Aboveground Metallic Tanks Program as consistent, with an exception, with GALL Report 

AMP XI.M29, “Aboveground Metallic Tanks.” The LRA states that the AMP manages the effects 

of cracking and loss of material for the condensate storage tank (CST), refueling water storage 

tank (RWST), and the two FWSTs, which are exposed to outdoor air and supported on concrete 

foundations. The LRA also states that the AMP proposes to manage these aging effects 

through coatings on the external surface and edge grouting at the base of the FWSTs, as well 

as jacketed insulation that prevents moisture intrusion for the CST and RWST. The LRA further 

states that periodic visual inspections of the external surfaces and thickness measurements of 

the bottom of the FWSTs will be conducted. The LRA states that the insulation covering for the 

CST and RWST will be inspected for damage, thickness measurements of the walls of tanks will 

be conducted when insulation has not been opportunistically removed, and thickness 

measurements of the bottom of the tanks will be conducted.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M29.

For the “preventive actions” and “detection of aging effects” program elements, the staff 

determined the need for additional information, which resulted in the issuance of RAIs, as 

discussed below.

The “preventive actions” program element in GALL Report AMP XI.M29 states that sealant or 

caulking may be applied at the external surface of the interface joint between a tank and its 

concrete foundation to minimize the amount of water penetrating the interface, which could lead 

to corrosion of the tank bottom. However, during its audit, the staff found that the applicant’s 

Aboveground Metallic Tanks Program states that there are no sealants or caulking applied at 

the external interface between the bottoms of the CST and RWST and their concrete 

foundations. By letter dated July 5, 2012, the staff issued RAI B2.1.15-1 requesting that the 

applicant state the basis for why the proposed inspection schedule of the CST and RWST tank 
AGING MANAGEMENT REVIEW RESULTS

3-152

bottom volumetric inspections is sufficient to provide reasonable assurance that the tanks will 

meet their intended function(s) during the period of extended operation.

In its response dated August 6, 2012, the applicant stated that the tank foundations for the CST 

and RWST are designed using a radial slope. It also stated that the high point of the foundation 

is located at the tank centerline, allowing collected liquid to flow down and away from the base 

of the tanks, and caulking or sealant at the external interface of the tank bottoms and their 

foundations would impede this design by preventing water from flowing outward, trapping water 

between the tank and foundation. According to the applicant, the free draining design of the 

foundations and the tank bottom thickness inspection frequency (i.e., once within 5 years of 

entering the period of extended operation and whenever the tanks are drained) will provide 

reasonable assurance that degradation will be detected and corrective actions taken before loss 

of intended function.

The staff finds the applicant’s response acceptable because the design of the tank foundation is 

such that water would not penetrate the interface between the tank bottom and concrete 

foundation for any appreciable amount of time because (1) water would drain out from under the 

tank, (2) installation of caulking or sealant would cause water not to drain from under the tank, 

(3) no signs of corrosion were found at the interface between the tanks and their foundations 

during the staff’s walkdowns of these tanks, and (4) the program’s inspection frequency is 

consistent with GALL Report AMP XI.M29. The staff’s concern described in RAI B2.1.15-1 is 

resolved.

The “preventive actions” program element in GALL Report AMP XI.M29 recommends that “[i]n 

accordance with industry practice, tanks may be coated with protective paint or coating to 

mitigate corrosion by protecting the external surface of the tank from environmental exposure.” 

However, during its audit, the staff found that the applicant’s Aboveground Metallic Tanks 

Program states, in part, the following:

• The stainless steel CST does not have a protective coating, the insulation materials 

have a documented evaluation demonstrating that there are not any harmful substances 

that could leach onto the tank surface, and the insulation has a protective aluminum 

jacket with overlapping seams. In contrast to these statements, LRA Table 3.4.2-6, 

Insulation, plant-specific note 3, states, in part, “[t]he dome of the stainless steel tank is 

prepped with a low halogen (<200 parts per million (ppm)) primer before the application 

of the foam urethane.”

• The stainless steel RWST does not have a protective coating, and the insulation has a 

protective aluminum jacket with overlapping seams.

During the staff’s walkdown of the structure that partially encloses the CST, water stains were 

observed on the side of the tank where insulation is not installed. By letter dated July 5, 2012, 

the staff issued RAI B2.1.15-2 requesting that the applicant provide information. The applicant’s 

response and the staff’s evaluation of the response are provided below.

• Part (a): State whether there is or could be the potential for chemical compounds in the 

cooling tower water, soil, or other sources to migrate to the CST or RWST insulation 

jacketing or tank external surfaces.

Part (f): State whether chemical treatments of cooling tower water will contain chemical 

compounds that could cause cracking, pitting, or crevice corrosion on the external 

surfaces of the tank, and propose a schedule for periodic site soil samples that will 
AGING MANAGEMENT REVIEW RESULTS

3-153

demonstrate that harmful compounds have not accumulated on the soil surface due to 

prior treatments.

In its response to Part (a) dated August 6, 2012, the applicant stated:

There has been no operating experience indicating negative 

effects of chemical compounds in the cooling tower water, soil, or 

other sources on the surfaces of the CST or RWST. The range of 

cooling water chemicals includes biocides, bleach, coagulant aids, 

cationic polymers, bromine, HEDP (hydoxyethylidine diphosphonic 

acid), pyrophosphate, sodium tolytriazole, biopenetrant, and 

sulfuric acid.

In its response to Part (f) dated August 6, 2012, the applicant stated that during the 

period of extended operation, chemical treatments of cooling tower water will not contain 

chemical compounds that could cause cracking, pitting, or crevice corrosion on the 

external surfaces of the tanks; within 5 years of entering the period of extended 

operation a one-time soil surface sample near the CST and RWST will be performed; 

and the soil surface sample will be evaluated to ensure that chlorides or other 

aggressive cooling tower water treatment chemicals are not creating an aggressive 

environment that would degrade the CST, RWST, or their insulation jacketing. The 

applicant also revised LRA Appendix A1.15 and LRA Appendix B2.1.15 to reflect the 

above.

The staff did not find the applicant’s response to Part (a) in and of itself acceptable 

because the applicant only cited plant-specific operating experience to date. Given that 

there are more than 12 years before entry into the period of extended operation, existing 

operating experience is not sufficient to predict degradation that could occur during the 

period of extended operation. In addition, the response did not cite specific inspections 

that have been performed to conclude that no negative effects are occurring. Finally, 

based on the list of cooling water chemicals, some have been known to cause loss of 

material or cracking of stainless steel. However, the staff finds the applicant’s overall 

proposal, in response to Parts (f) and (a) combined, acceptable because, during the 

period of extended operation, chemical treatments of cooling tower water will not contain 

chemical compounds that could cause cracking, pitting, or crevice corrosion on the 

external surfaces of the tanks. In addition, a one-time verification of deleterious 

compound fallout will be conducted by a soil sample to confirm the absence of an 

aggressive environment that could have been created before the period of extended 

operation. The staff’s concern described in RAI B2.1.15-2, Parts (a) and (f), are 

resolved.

• Part (b): State whether the RWST insulation contains any harmful substances that could 

leach onto the tank surface. 

In its response dated August 6, 2012, the applicant stated that the tank is insulated with 

calcium silicate insulation that was manufactured and tested to comply with RG 1.36, 

“Nonmetallic Insulation for Austenitic Stainless Steel,” Revision 0, February 1973. The 

insulation has low leachable chloride and fluoride concentrations and silicate.

The staff finds the applicant’s response acceptable because insulation that is 

manufactured and tested to the recommendations in RG 1.36 is known to have minimal 

potential to cause loss of material or cracking on stainless steel surfaces. The staff’s 

concern described in RAI B2.1.15-2 Part (b) is resolved. 
AGING MANAGEMENT REVIEW RESULTS

3-154

• Part (c): State whether and what portions of the CST are coated. 

In its response dated August 6, 2012, the applicant stated, “[t]he dome exterior of the 

CST is coated with a low halogen (<200 ppm) primer. The next layer of the CST dome 

is urethane foam insulation. The urethane foam insulation cover layer of the CST dome 

is an acrylic rubber sealant coating providing protection from UV radiation.” The 

applicant also stated that the vertical exterior wall of the CST is not coated and it is 

insulated with FOAMGLAS® (glass dust) insulation.

The staff finds the applicant’s response acceptable because it described the 

configuration of the coating on the CST. Use of FOAMGLAS® (glass dust) insulation on 

vertical uncoated surfaces is acceptable because, based on the Material Safety Data 

Sheet for this insulation, 

(http://www.industrialinsulation.com/images/foamglas_msds.pdf), it is composed of 

hydrogen sulfide, carbon monoxide, carbon dioxide, and glass dust, none of which are 

known to cause degradation of stainless steel materials. In addition, there is a low 

likelihood of water intrusion past the overlapping joints of the insulation jacketing. 

Furthermore, the vertical surfaces would shed this water, which would also make it 

unlikely that any corrosion would occur as a result of compounds leaching from the 

insulating materials. The response and staff evaluation of Part (d) of this RAI regarding 

the evaluation of the dome surface coating is discussed below. The staff’s concern 

described in RAI B2.1.15-2, Part (c), is resolved.

• Part (d): State whether the external surface coating has been credited for license 

renewal and, if not, explain why the opportunistic inspections of the tank’s external 

surface are adequate. 

In its response dated August 6, 2012, the applicant stated that the CST dome metallic 

surface primer does not have an intended function and is not credited as a preventive 

measure. It also stated that the CST acrylic rubber sealant is credited as a preventive 

measure for the CST urethane foam insulation and CST metallic surface.

The staff noted that the applicant had not addressed why the proposed opportunistic 

inspections of the tank’s external surfaces are adequate. However, the staff noted that 

the applicant addressed the external inspections in the response to Part (a) of this RAI. 

By letter dated July 5, 2012, the staff issued RAI B2.1.15-3, Part (a), associated with the 

“detection of aging effects” program element, requesting that the applicant state the 

basis for how an inspection conducted once within 5 years of entering the period of 

extended operation and whenever the tank is drained is sufficient to detect pitting, 

crevice corrosion, and cracking. In its response dated August 6, 2012, to RAI B2.1.15-3, 

Part (a), in part (see further aspects of the staff evaluation of this response below), the 

applicant stated:

Instead of inspecting the internal surface of the tank walls, only 

the external surface of the tank wall will be inspected. The 

inspection of the tank wall external surface prior to entering the 

period of extended operation will include locations where the 

insulation will be removed to demonstrate that the insulating 

materials are effective in preventing moisture intrusion to the tank 

surface. External wall surface inspection will require insulation to 

be removed on 25 locations on the tank external walls to allow 

inspection for loss of material and cracking. At least ten of the 25 

locations will be near the base of the tank wall. Each location will 

measure approximately one square foot in area.
AGING MANAGEMENT REVIEW RESULTS

3-155

The applicant also stated that the tank bottom internal surface will be examined by 

measuring thickness along 12-inch wide bands of the bottom. The staff noted that this 

response replaces the opportunistic inspection of the external surfaces of the tank with a 

one-time inspection. The staff finds the applicant’s responses to RAI B2.1.15-2, Part (d) 

and RAI B2.1.15-3, Part (a), partially acceptable because a one-time inspection of 25 

one-square-foot samples of the tank’s external surfaces before entering the period of 

extended operation is an acceptable method to confirm that leakage through the acrylic 

rubber sealant coating does not occur, and external visual inspections conducted by the 

Aboveground Metallic Tanks Program could detect cracking or blistering in the acrylic 

rubber sealant during the period of extended operation. Based on the one-time 

inspection of the tanks surface and periodic visual examinations (conducted on a RFO 

interval) of the acrylic rubber sealant coating, the staff finds that crediting the acrylic 

rubber sealant coating as a preventive measure is acceptable. However, it was not clear 

to the staff when in the time frame before the period of extended operation the one-time 

inspection will be conducted, whether the inspection locations will include the dome 

region, and how many bottom measurements will be obtained in each 12-inch band. In 

addition, the applicant did not include details on the inspections, including the number 

and size, in the program and FSAR supplement. By letter dated October 1, 2012, the 

staff issued RAI B2.1.15-2a requesting that the applicant state (a) the timing of the 

one-time inspection of the external surfaces of the tank, (b) whether and how many 

inspections will be conducted on the external metallic surfaces in the dome region, and 

(c) how many inspections will be conducted in each 12-inch band of the tank bottom. In 

addition, the staff requested that the applicant update its FSAR supplement to reflect the 

one-time inspection details for the dome and wall surfaces.

In its response dated October 31, 2012, the applicant stated that the timing of the 

one-time inspection will be within the 5-year period before entering the period of 

extended operation, and a minimum of 2 of the 25 inspection locations will be in the 

dome region. The applicant revised the tank bottom inspection to include a scanning 

technique (e.g., low-frequency electromagnetic technique) of the entire bottom of the 

tank that will be capable of detecting loss of material below nominal plate thickness. Any 

regions below nominal plate thickness will have a followup ultrasonic thickness reading. 

The applicant also stated that, if there are areas of significant loss of material, future 

ultrasonic thickness measurements and trending will be performed. The applicant 

amended the FSAR Supplement and program to reflect the response to this RAI.

The staff finds the applicant’s response acceptable because: 

• Conducting a one-time inspection within the 5-year period before the period of extended 

operation is consistent with GALL Report AMP XI.M32, “One-Time Inspection,” which 

states that these inspections should be conducted no earlier than 10 years before the 

period of extended operation. Reasonable assurance that aging of the tank’s surface is 

not occurring because of contaminants in the atmosphere is provided by the one-time 

inspections of the bare tank surfaces; the fact that the cooling tower water will not 

contain chemical compounds that could cause cracking, pitting, or crevice corrosion on 

the external surfaces of the tanks during the period of extended operation; and the 

one-time soil surface sample near the CST and RWST to confirm that chlorides or other 

aggressive cooling tower water treatment chemicals are not creating an aggressive 

environment.

• The tank’s dome area will be sampled to ensure that aging is not occurring in this region. 

The inspections, coupled with the slope of the tank’s roof resulting in any potential 
AGING MANAGEMENT REVIEW RESULTS

3-156

leakage through the insulation flowing to the ground and not remaining on the roof, 

provides reasonable assurance that aging of the tank’s roof is not occurring because of 

contaminants in the atmosphere.

• The entire tank bottom will be scanned with a technique capable of detecting changes 

from nominal plate thickness, and followup ultrasonic examinations will be conducted at 

any locations where the wall thickness is below nominal. Given that the entire tank 

bottom is scanned, and local ultrasonic readings will be taken as necessary, this 

approach is consistent with GALL Report AMP XI.M29, “Aboveground Metallic Tanks.” 

• The example technique cited, LFET, has been conducted in the refinery business and 

was effectively demonstrated by a comparison of inspection test results against the 

internal inspection of a previously in-service refinery tank. As documented in “Detecting 

Corrosion in Production Tanks,” DT Schardine, Inspection Trends, American Welding 

Society, summer 2008, the external LFET inspection results were consistent with the 

internal inspection. The nondestructive examination procedure, “Examination for the 

Detection and Sizing of Pitting, Corrosion, and Wall Loss Using Low Frequency 

Electromagnetic Techniques,” TesTex document NPS-PROCOO7, Revision 4, 

September 2007, Section 2.2, states that the method is capable of inspecting ferritic and 

non-ferritic materials up to 3⁄4 inch. Section 5.2.2.5 states that the technique can be used 

on flat bottom tanks, while Section 7.1.5 states that a frequency of 1000 hertz is used to 

inspect stainless steel materials. Therefore, there is reasonable assurance that a LFET, 

or a technique with equivalent capability, can be used as an effective screening tool.

The staff’s concerns described in RAIs B2.1.15-2, Part (d); B2.1.15-3, Part (a); and B2.1.15-2a 

are resolved.

• RAI B2.1.15-2, Part (e): Given the evidence of water stains on the side of the CST 

where insulation is not installed, state the basis for why it can be concluded that the CST 

and RWST jacketing will prevent water intrusion into the tank insulation and then onto 

the tank surface. 

In its response dated August 6, 2012, the applicant stated that the water stains on the 

CST were caused by leakage from the CST pipehouse roof. The applicant also stated 

that the roof covering the CST pipehouse was replaced in 2011 to provide a better seal 

between the CST pipehouse and tank insulation, thus sheltering and protecting the 

uninsulated portion of the CST.

The staff finds the applicant’s response acceptable because the source of leakage was 

not through the jacketing, the leaking roof joint was repaired, and during the AMP audit, 

the staff’s walkdown did not reveal any corrosion associated with the leakage. The 

staff’s concern described in RAI B2.1.15-2, Part (e), is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M29 recommends 

that external surfaces of the tank be inspected on a refueling outage interval. However, during 

its audit, the staff noted that the applicant’s Aboveground Metallic Tank Program states that 

visual inspections of the exterior surfaces of the CST and RWST are conducted when the 

surfaces are accessible. The program basis document also states that for inaccessible exterior 

tank surfaces, the applicant will sample wall thickness to ensure that the tank bottom and tank 

wall sections with insulated outer surfaces are not losing material or cracking. As noted above 

in the staff evaluation of RAI B2.1.15-3, Part (a), the applicant amended its program to include a 

one-time inspection of a sample of the CST’s and the RWST’s insulated outer surfaces in lieu of 

opportunistic inspections. The staff, however, also questioned how cracking will be detected. 
AGING MANAGEMENT REVIEW RESULTS

3-157

By letter dated July 5, 2012, the staff issued RAI B2.1.15-3, Part (b), requesting that the 

applicant state what inspection technique will be used to detect cracks. 

In its response to RAI B2.1.15-3, Part (b), dated August 6, 2012, the applicant stated that 

cracking will be detected by a surface exam technique from the external surface after the 

insulation has been removed.

The staff finds the applicant’s response acceptable because surface examination techniques 

are capable of detecting cracking in stainless steel. The staff’s concern described in 

RAI B2.1.15-3, Part (b) is resolved. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with the exception to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this exception follows.

Exception. LRA Section B2.1.15 states an exception to the “detection of aging effects” program 

element. In this exception, the applicant stated that, to determine the thickness of the tank 

bottom, UT thickness measurements of the bottom of each FWST from the internal surface will 

be performed at least once every 10 years. Thickness measurement inspections may occur 

more frequently based on the results of visual inspections. The staff noted that the 

GALL Report recommends that bottom thickness measurements be performed within 5 years of 

entering the period of extended operation and whenever the tank is drained. The staff reviewed 

this exception against the corresponding program element in GALL Report AMP XI.M29 and 

finds it acceptable because (a) the bottom thickness measurement conducted within 5 years of 

entering the period of extended operation will be evaluated in light of the acceptance criteria in 

the program; (b) based upon the degree of conformance with the acceptance criteria, additional 

thickness measurements will be implemented if necessary; and (c) the thickness measurements 

conducted every 10 years will be augmented by visual inspection results conducted every time 

the tank is drained and, therefore, these inspections will be sufficient to provide reasonable 

assurance that each tank will meet its intended function(s).

Based on its audit and review of the applicant’s responses to RAIs B2.1.15-1, B2.1.15-2, 

B2.1.15-2a, and B2.1.15-3, the staff finds that the program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M29. The staff also reviewed the exception associated with 

the “detection of aging effects” program element and its justification and finds that the AMP, with 

the exception, is adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B2.1.15, as amended by letter dated April 25, 2012, 

summarizes operating experience related to the Aboveground Metallic Tanks Program. The 

applicant stated that a 2007 internal inspection of the B FWST identified small amounts of 

corrosion and mineral deposits. A followup inspection in 2009 identified several areas of 

blistering in the coating and calcium deposits, along with minor corrosion on bare metal 

surfaces. A subsequent inspection of B FWST in 2011 revealed little-to-no degradation of the 

internal metallic surfaces of the tank; however, there was some surface roughness and pitting. 

In addition, general blistering and delamination of the coating was found. In 2008 an internal 

inspection of A FWST also identified minor blistering and limestone deposits. A followup 

inspection in 2010 identified discontinuities and delamination sites in the coating in addition to 

some pitting. The applicant also stated given that the cathodic protection system was 

determined to be effective, the tank interiors would not degrade excessively before the next 

planned inspection.
AGING MANAGEMENT REVIEW RESULTS

3-158

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff identified operating experience for which it determined the need for 

additional clarification and resulted in the issuance of an RAI, as discussed below.

The “operating experience” program element of the Aboveground Metallic Tanks Program, LRA 

Section B2.1.15, and the staff’s independent review of CARs and work orders indicate that 

multiple inspections of the internal surfaces of the FWSTs, spanning 2007 through 2011, have 

revealed blistering and delamination of coatings. Work orders documented that these defects 

were not all repaired before returning the tanks to service. The work orders also documented 

that the acceptance of the as-found defects that were not repaired was based on internal 

cathodic protection of the tank preventing corrosion of exposed metal surfaces. The staff noted 

that neither the LRA AMP nor FSAR supplement state that the cathodic protection system is 

credited as a preventive measure to account for the plant-specific operating experience. In 

addition, the staff lacks sufficient information to conclude that the delamination of the coatings 

would not block downstream components either based on current levels of delamination or 

those that could occur in the period of extended operation. By letter dated July 5, 2012, the 

staff issued RAI B2.1.15-4 requesting that the applicant: (a) state the basis for why blistering 

and delamination of coatings will not occur during the period of extended operation despite the 

current trend of plant-specific operating experience, or revise the program and LRA 

Section A1.15, FSAR Supplement to credit the FWST internal cathodic protection system as a 

preventive measure to prevent corrosion on exposed bare metal as-left surfaces of the tanks or, 

alternatively, (b) state the basis for why delamination of coatings will not prevent downstream 

in-scope components from being able to perform their intended function(s), including 

consideration of the size of delaminations that could occur during the period of extended 

operation.

In its response dated August 6, 2012, the applicant stated that the blistering and delamination 

will be corrected before the period of extended operation through the application of a new 

coating. The FWST internal cathodic protection system will prevent corrosion on the internal 

surfaces of the tank. LRA Sections A1.15 and B2.1.15 were revised to state that cathodic 

protection is used as a preventive measure to prevent corrosion on exposed bare metal as-left 

surfaces of the tanks. The applicant also stated that coating delaminations have been minor 

and that they will be removed before the period of extended operation during the recoating of 

the tanks’ internal surfaces. The applicant further stated that the tank outlets consist of a 

14-inch pipe that extends 3 feet inside the tank and ends in a 90 degree radius elbow turned 

downward, ending 6 in. above the bottom of the tank; therefore, in the event of delamination, 

this geometry would preclude any large pieces of coating from entering the outlet of the tank 

and affecting downstream equipment.

The staff finds the applicant’s response acceptable, in part, because the cathodic protection 

system will prevent corrosion on exposed metal surfaces of the tank. While the staff 

understands that the coatings will be replaced before the period of extended operation, given 

past plant-specific operating experience, subsequent delamination of coatings could occur. 

Neither the Fire Water System, nor Aboveground Metallic Tanks Programs nor the 

corresponding FSAR supplements state that the FWSTs will be cleaned and inspected on an 
AGING MANAGEMENT REVIEW RESULTS

3-159

alternating refueling outage frequency and, therefore, the staff cannot determine if followup 

inspections of the new coatings will occur to confirm the lack of delamination. The Callaway 

Site Addendum to FSAR Section 9.5.1.2.1 states, “[t]he FPS water supply is separated from all 

other site water supply systems and is based on providing 2,300 gallons per minute of water for 

2 hours to sprinkler systems with a simultaneous total flow of 1,000 gallons per minute to hose 

stations.” The staff noted that the fluid velocity corresponding to 3,300 gpm in a 14-inch pipe is 

approximately 7.8 feet per second. Even considering the 6-inch clearance to the bottom of the 

tank, delaminated particles could still be carried into the flow stream. The staff lacked sufficient 

information to find that downstream components will not be affected by delaminated coatings. 

By letter dated October 1, 2012, the staff issued RAI B2.1.15-4a requesting that the applicant 

revise the Fire Water System or Aboveground Metallic Tanks Program, and the corresponding 

FSAR supplement, to state the frequency of coating inspections conducted to confirm that 

delamination of the coatings does not occur or provide the basis for why the smallest size 

delaminated particle that could prevent an in-scope intended function from being performed will 

not be transported from the tank.

In its response dated October 31, 2012, the applicant revised LRA Sections A1.14 and B2.1.14 

to include internal coating inspections on the fire water storage tanks with a minimum frequency 

of alternating refueling outages.

The staff finds the applicant’s response acceptable because new coatings will be installed on 

the tanks before the period of extended operation and, between the two fire water storage 

tanks, a tank will be inspected, on average, every refueling outage interval, which is sufficient to 

detect coating degradation before impacting the intended functions of the fire water storage 

tanks or downstream components. The staff’s concern described in RAI B2.1.15-4a is resolved.

During its review of the applicant’s LRA, the staff identified several instances of industry 

operating experience associated with age-related degradation of tanks. Tanks with defects 

variously described as wall thinning, pinhole leaks, cracking, and through-wall flaws had been 

identified by detecting external leakage rather than through internal inspections. As a result, the 

staff issued LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and Corrosion Under Insulation,” (ADAMS Accession 

No. ML13227A361) to address this operating experience. GALL Report AMP XI.M29 was 

revised to (a) manage aging effects for both internal and external surfaces of tanks, (b) include 

cracking as an applicable aging effect for certain material and environment combinations, 

(c) provide a table of inspection techniques and frequencies, and (d) extend the scope of the 

AMP to indoor welded tanks that have a large volume (greater than 100,000 gallons), are 

designed to near-atmospheric internal pressures, sit on concrete, and are exposed internally to 

water. By letter dated October 7, 2013, the staff issued RAI 3.0.3-4, requesting that the 

applicant either describe how its program already addresses the issues identified in this revised 

guidance or provide adequate justification why its program does not need to address them. 

In its response dated December 20, 2013, the applicant stated that it does not have any indoor 

welded tanks that meet the scoping criteria in revised GALL Report AMP XI.M29. The applicant 

also stated that it will manage the aging of fire water storage tanks with the Fire Water System 

Program, rather than the Aboveground Metallic Tanks Program. For outdoor tanks, the 

applicant revised its Aboveground Metallic Tanks Program and FSAR supplement to be 

consistent with the new inspection recommendations. The staff noted that the applicant’s 

revised program includes a one-time inspection of a representative sample of tank external 

surfaces (after insulation removal) and a one-time volumetric examination of tank bottoms. The 

applicant supported the use of one-time inspections by stating that the chemical treatments of 
AGING MANAGEMENT REVIEW RESULTS

3-160

the cooling tower water do not contain aggressive compounds and that non-corrosive conditions 

will be verified every 10 years by testing of the soil and tank surface residues. 

The staff finds the applicant’s response acceptable because the applicant incorporated the new 

inspection guidance provided in LR-ISG-2012-02, such that the Aboveground Metallic Tanks 

Program is consistent with the revised GALL Report AMP XI.M29. The staff noted that the 

applicant’s use of one-time inspections for the tank external surfaces and bottoms in lieu of 

periodic inspections is allowed by LR-ISG-2012-02. Table 4a of the revised GALL Report 

AMP XI.M29 states that one-time inspections can be used in the absence of sources of chloride 

in the vicinity of the plant and if evaluations of the soil and tank surface residues are performed 

prior to the period of extended operation and every 10 years to demonstrate the absence of 

aggressive environments. Also, the staff noted that managing the aging effects of fire water 

storage tanks with the Fire Water System Program is consistent with the revised staff guidance 

in LR-ISG-2012-02. The staff’s evaluation of the Fire Water System program is documented in 

SER Section 3.0.3.2.7. The staff’s concern described in RAI 3.0.3-4 is resolved.

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

RAI B2.1.15-4, RAI B2.1.15-4a, and RAI 3.0.3-4, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. The staff also finds 

that the operating experience related to the applicant’s program demonstrates that it can 

adequately manage the effects of aging on SSCs within the scope of the program and that 

implementation of the program has resulted in the applicant taking corrective actions.

FSAR Supplement. LRA Section A1.15, as amended by letters dated April 25, 2012, 

August 6, 2012, October 31, 2012, February 28, 2013, and December 20, 2013, provides the 

FSAR supplement for the Aboveground Metallic Tanks Program. The staff reviewed this FSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed 

(Commitment No. 11) to implement the new Aboveground Metallic Tanks Program within the 

5-year period before the period of extended operation for managing aging of applicable 

components. 

The staff finds that the information in the FSAR supplement, as amended by letters dated 

April 25, 2012, August 6, 2012, October 31, 2012, February 28, 2013, and December 20, 2013, 

is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Aboveground Metallic Tanks 

Program, the staff determines that the program elements for which the applicant claimed 

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

GALL Report AMP XI.M29. In addition, the staff reviewed the exception and its justification and 

determines that the AMP, with the exception, is adequate to manage the applicable aging 

effects. The staff also reviewed the FSAR 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 Fuel Oil Chemistry

Summary of Technical Information in the Application. LRA Section B2.1.16 describes the 

existing Fuel Oil Chemistry Program as consistent, with enhancements, with GALL Report 

AMP XI.M30, “Fuel Oil Chemistry.” The LRA states that the Fuel Oil Chemistry Program 

manages loss of material on the internal surface of components in the emergency diesel engine 

fuel oil storage and transfer system, fire protection system, standby diesel generator engine 
AGING MANAGEMENT REVIEW RESULTS

3-161

system, and emergency operations facility and technical support center diesels security building 

system. The LRA also states that the program includes the following:

• surveillance and monitoring procedures for maintaining fuel oil quality by controlling 

contaminants in accordance with plant technical specifications and ASTM Standards 

D1796-83 and D2276-78

• periodic draining of the emergency fuel oil system storage tanks and day tanks

• cleaning and visual inspection of internal surfaces of the emergency fuel oil system 

storage tanks and day tanks during periodic draining

• ultrasonic measurements of the emergency fuel oil system storage tank and fuel oil day 

tank bottom thickness if there are indications of reduced cross-sectional thickness found 

during the visual inspection

• periodic volumetric examination of the tank bottom, from the external surface, of the 

diesel fire pump fuel oil day tank and security diesel generator fuel oil day tank where 

tank design prevents cleaning and inspection from the inside

• inspection of new fuel oil before introduction to storage tanks

The staff noted that the LRA references ASTM Standards D1796-83 and D2276-78, whereas 

GALL Report AMP XI.M30 references ASTM Standards D1796-97 and D2276-00. The staff has 

reviewed all four revisions of the ASTM Standards and finds that there are no technical 

differences between the revisions that warrant the need for additional information from the 

applicant.

Based on recent staff reviews of several LRAs and of industry OE, the staff has determined that 

additional recommendations beyond those in the GALL Report should be considered in regards 

to managing loss of coating integrity for internal coatings of piping, piping components, heat 

exchangers, and tanks. By letters dated October 7, 2013, and March 25, 2014, the staff issued 

RAI 3.0.3-2 and RAI 3.0.3-2a, respectively, to address loss of coating integrity. In its response 

dated April 23, 2014, the applicant revised the Fuel Oil Chemistry program to address loss of 

coating integrity for the emergency fuel oil storage tanks and day tanks. The staff’s evaluation 

of the applicant’s response to RAI 3.0.3-2 and RAI 3.0.3-2a is documented in SER Section 

3.0.3.4. The staff’s evaluation of changes to LRA Sections B2.1.16 and A1.16, and 

Commitment No. 12 to address loss of coating integrity follows.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M30. For the “scope of 

program,” and “detection of aging effects” program elements, the staff determined the need for 

additional information, which resulted in the issuance of an RAI, as discussed below. 

The “scope of program,” and “detection of aging effects” program elements in GALL Report 

AMP XI.M30 recommend that periodic cleaning of diesel fuel oil tanks should be performed to 

remove sediments. However, during its audit, the staff found that the applicant’s Fuel Oil 

Chemistry Program does not state that periodic cleaning of the diesel generator fire pump fuel 

oil day tank and the security diesel generator fuel oil day tank will be performed. By letter dated 

July 5, 2012, the staff issued RAI B2.1.16-1 requesting that the applicant state how the 

volumetric examination, which will be conducted every 10 years, will be sufficient to ensure that 

the intended function of the tanks will be maintained in lieu of not performing periodic tank 

cleanings that will mitigate any corrosion that may occur. Alternatively, the staff requested the 
AGING MANAGEMENT REVIEW RESULTS

3-162

applicant to describe the actions that it will perform to prevent or mitigate corrosion of the diesel 

generator fire pump fuel oil day tank and the security diesel generator fuel oil day tank and the 

basis for how these actions will be effective.

In its response dated August 6, 2012, the applicant stated that because of the limited access to 

the diesel generator fire pump fuel oil day tank and the security diesel generator fuel oil day 

tank, draining and cleaning the tanks is not physically possible. The applicant stated that water 

will be periodically removed from the bottom of these tanks, minimizing the exposure of internal 

tank surfaces to the water, which will reduce the likelihood of corrosion and eliminate the 

environment for microbiological organisms. The applicant also stated that the tanks will be 

periodically sampled to determine water and sediment, particulate, and microbial activity 

concentrations to ensure that corrosion is not taking place. The applicant further stated that 

should periodic tests indicate the presence of biological activity, a biocide will be added to the 

tanks. The applicant stated that fuel oil receipt sampling will be performed for water and 

sediment before introduction of the new fuel oil into the tanks. The applicant also stated that 

volumetric examinations will identify any loss of material associated with corrosion and, if such a 

loss of material is discovered, it will be addressed by the CAP. 

The staff finds the applicant’s response acceptable because:

• Conducting tank wall thickness measurements every 10 years is sufficient to detect 

potential corrosion and this is consistent with the “detection of aging effects” program 

element of GALL Report AMP XI.M30 which states that these measurements are 

conducted when visual examination is not possible or if visual examinations detect 

evidence of degradation.

• The first wall thickness inspection will be conducted within the 10-year period prior to the 

period of extended operation and this test will be capable of detecting any internal 

corrosion prior to entering the period of extended operation.

• Any loss of material will be evaluated by the applicant’s CAP.

• Fuel oil quality is maintained by monitoring and controlling fuel oil contamination in 

accordance with the Callaway TSs and, therefore, the inventory source for these tanks 

should be free of water, sediment, and biological activity.

• The applicant will periodically drain any accumulated water in the diesel generator fire 

pump fuel oil day tank and the security diesel generator fuel oil day tank, along with 

sampling new fuel oil before it is placed in the tanks.

• The applicant will perform periodic sampling of the tanks to ensure that corrosion of the 

internal surfaces of the tanks is not taking place.

• The addition of biocide to a tank that shows signs of biological activity will further provide 

reasonable assurance that internal corrosion of the tanks will not take place.

The staff finds that these actions will provide reasonable assurance that corrosion and 

microbiological corrosion is not taking place. Therefore, the staff’s concern described in 

RAI B2.1.16-1 is resolved.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “corrective actions” 

program elements associated with enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows.
AGING MANAGEMENT REVIEW RESULTS

3-163

Enhancement 1. LRA Section B2.1.16 states an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to include periodic draining of the water from the bottom of the emergency fuel oil system day 

tanks, diesel fire pump fuel oil day tanks, and security diesel generator fuel oil day tank. The 

applicant also stated that procedures will be enhanced to add biocide to the diesel fire pump 

fuel oil day tank and security diesel generator fuel oil day tank if periodic testing indicates 

biological activity or evidence of corrosion. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M30 and finds it acceptable because 

when it is implemented it will make the existing Fuel Oil Chemistry Program consistent with the 

GALL Report AMP which recommends that biocides or corrosion inhibitors may be added (1) as 

a preventive measure or (2) if periodic testing indicates biological activity or evidence of 

corrosion and periodic draining of water collected at the bottom of a tank.

Enhancement 2. LRA Section B2.1.16 states an enhancement to the “preventive actions,” and 

“detection of aging effects” program elements. In this enhancement, the applicant stated that 

procedures will be enhanced to include draining, cleaning, and inspection of the emergency fuel 

oil system day tanks within the 10-year period before the period of extended operation and at 

least once every 10 years after entering the period of extended operation. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.M30 

and finds it acceptable because when it is implemented it will make the existing Fuel Oil 

Chemistry Program consistent with the GALL Report AMP which recommends that these 

activities (i.e., draining, cleaning, and inspection) be conducted.

Enhancement 3. LRA Section B2.1.16 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that procedures will be 

enhanced to include a determination of water and sediment in the periodic sampling of the 

emergency fuel oil system day tanks and security diesel generator fuel oil day tank. 

Additionally, the applicant stated that procedures will be enhanced to include a determination of 

particulate concentrations in the periodic sampling of the emergency fuel oil system day tanks, 

diesel fire pump fuel oil day tanks, and security diesel generator fuel oil day tank. The applicant 

also stated that procedures will be enhanced to include a determination of microbial activity 

concentrations in the periodic sampling of the emergency fuel oil system storage tanks, 

emergency fuel oil system day tanks, diesel fire pump fuel oil day tanks, and security diesel 

generator fuel oil day tank. Finally, the applicant stated that procedures will be enhanced to 

include new fuel oil receipt sampling for water and sediment before introduction into the security 

diesel generator fuel oil day tank and diesel fire pump fuel oil day tank. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M30 and 

finds it acceptable because when it is implemented it will make the existing Fuel Oil Chemistry 

Program consistent with the GALL Report AMP which recommends that the AMP monitor fuel 

oil quality through receipt testing and periodic sampling of stored fuel oil.

Enhancement 4. LRA Section B2.1.16 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that procedures will be 

enhanced to perform a volumetric examination of the emergency fuel oil system storage tanks 

and day tanks after evidence of tank degradation is observed during the visual inspection within 

the 10-year period before the period of extended operation and at least once every 10 years 

after entering the period of extended operation. Additionally, the applicant stated that 

procedures will be enhanced to perform a volumetric examination on the external surface of the 

diesel fire pump fuel oil day tanks and security diesel generator fuel oil day tank within the 

10-year period before the period of extended operation and at least once every 10 years after 

entering the period of extended operation. The staff reviewed this enhancement against the 
AGING MANAGEMENT REVIEW RESULTS

3-164

corresponding program element in GALL Report AMP XI.M30 and finds it acceptable because 

when it is implemented it will make the existing Fuel Oil Chemistry Program consistent with the 

GALL Report AMP which recommends the same inspections and frequency for inspections.

Enhancement 5. LRA Section B2.1.16 states an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to include at least quarterly trending for water, biological activity, and particulate concentrations 

on the emergency fuel oil system day tanks, diesel fire pump fuel oil day tanks, and security 

diesel generator fuel oil day tank. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M30 and finds it acceptable because 

when it is implemented it will make the existing Fuel Oil Chemistry Program consistent with the 

GALL Report AMP which recommends monitoring and trending of the same parameters.

Enhancement 6. LRA Section B2.1.16 states an enhancement to the “corrective actions” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to include immediate removal of accumulated water when discovered in the emergency fuel oil 

system day tank, diesel fire pump fuel oil day tank, and security diesel generator fuel oil day 

tank. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M30 and finds it acceptable because when it is implemented it will make 

the existing Fuel Oil Chemistry Program consistent with the GALL Report AMP which 

recommends immediate removal of any accumulated water found in a fuel oil storage tank.

Enhancement 7. As amended by letter dated April 23, 2014, LRA Section B2.1.16 contains an 

enhancement to the “preventive actions,” “parameters monitored or inspected,” “detection of 

aging effect,” “monitoring and trending,” and “acceptance criteria” program elements. In this 

enhancement, the applicant provided a list of procedure enhancements associated with 

coatings inspections (e.g., base line inspections, extent of inspections), training and qualification 

of individuals involved in coating inspections, acceptance criteria, and corrective actions. These 

enhancements and the corresponding staff evaluation are documented in the response to 

RAI 3.0.3-2a Request Nos. (2), (5), and (6) in SER Section 3.0.3.4.

Based on its audit of the applicant’s Fuel Oil Chemistry Program and review of the applicant’s 

response to RAI B2.1.16-1, the staff finds that program elements one through six for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M30. In addition, based on its review of the 

applicant’s responses to RAIs 3.0.3-2 and 3.0.3-2a, the staff finds that the applicant’s program 

changes to address loss of coating integrity are consistent with recommended measures 

acceptable to the staff for addressing loss of coating integrity for internal coatings as described 

in SER Section 3.0.3.4. In addition, the staff reviewed the enhancement(s) associated with the 

“preventive actions,” “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “corrective actions” program elements and finds that when 

implemented, they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.16 summarizes operating experience related to the 

Fuel Oil Chemistry Program. The LRA states that in 2009, the applicant performed a diesel fuel 

oil program self-assessment and made the following changes as a result of the assessment 

findings: 

(a) [t]he Certificate of Compliance for incoming diesel fuel oil truck loads was 

updated to include assurances that no biodiesel is present[;] [and] (b) the diesel 

fuel oil testing program procedure was changed to include [preventative 
AGING MANAGEMENT REVIEW RESULTS

3-165

maintenance] PMs for sampling of both underground storage tanks after each 

outage, including specific gravity, density, lubricity, and microbial activity. 

The LRA also states that in 2010, in response to industry operating experience concerning 

contamination of diesel fuel oil with biodiesel, the applicant took the following actions to ensure 

that biodiesel is not used: 

(a) a procedure that tests for biodiesel was created; (b) both diesel fuel oil 

storage tanks were sampled for biodiesel and were confirmed to have less than 

minimum detectable; (c) testing for biodiesel was added to the required analyses 

for truck receipt sampling; [and] (d) PMs were created to sample the fuel oil 

storage tanks after the 24-hour diesel runs at the end of each outage. 

The LRA further states the following:

During [RFO] 17 (spring 2010), as part of the 10-year cleaning and inspection of 

the emergency fuel oil system storage tank TJE01A, the condition of the internal 

coating was inspected and determined to be in acceptable condition. No debris, 

sludge, or bare metal areas were identified during the inspection. The coal tar 

epoxy coating was in good condition; however, coating blisters were identified in 

various places. An engineering evaluation determined the identified blistering 

was acceptable since all instances were less than nickel size. No issue with the 

coatings has been documented in any of the previous inspections. The 

procedure requiring the condition of each tank coating to be documented was 

enhanced to require inclusion of pictures of the internal coating condition and 

additional details regarding tank internal coating cleanliness, coating color, 

coating uniformity, and general tank condition.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI as 

discussed below.

Given that the engineering evaluation described in the operating experience for tank TJE01A in 

spring 2010 did not state the potential corrosion rate if the blisters were to open up, it was not 

clear to the staff that the tank would be capable of performing its intended function(s) should 

further degradation of the coating occur between inspections. By letter dated July 5, 2012, the 

staff issued RAI B2.1.16-2 requesting that the applicant provide an evaluation of the corrosion 

rate and minimum design wall thickness of the fuel oil system storage tank should one of the 

blisters open up, exposing the fuel oil in the tank to the bare metal material of the tank. 

Additionally, the staff requested the applicant to provide an evaluation of the adequacy of the 

10-year inspection interval based on the evaluation of the corrosion rate.

In its response dated August 6, 2012, the applicant stated the following:

Using the [National Association of Corrosion Engineers] NACE Standard 

RP0502-2002 default corrosion rate of 16 [mils per year] mpy over the 10–year 

interval, as a bounding scenario, only 0.16 inches of wall thickness would be lost. 
AGING MANAGEMENT REVIEW RESULTS

3-166

Using a minimum plate thickness of 0.875 inches, this would result in a final 

thickness of 0.715 inches, which is significantly greater than the minimum 

requirements of 0.1159 inches for the shell and 0.2771 inches for the head. 

There has been no plant operating experience regarding water found in the 

emergency diesel fuel oil storage tank. This record of good chemistry control, 

plus the preventive measure of adding a biocide to the fuel oil, ensures that even 

if there was a failure of the internal coating, the environment needed for corrosion 

to occur would not exist. If the monthly fuel oil sampling results start to indicate a 

trend of water or corrosion products found in the oil, the applicant stated that 

additional corrective actions would be evaluated.

The staff noted that the basis for the National Association of Corrosion Engineers 

(NACE) RP0502-2002 corrosion rate of 16 mils per year (mpy) is an upper 80 percent 

confidence level of maximum pitting rates for long-term (up to 17-year duration) underground 

corrosion tests of bare steel pipe coupons without cathodic protection in a variety of soils, 

including native and nonnative backfill. The staff also noted that given the configuration of a 

limited area being exposed to corrosion, the pitting rate could be higher. In contrast, the internal 

environment of the tank is in all likelihood less conducive to corrosion than that of a soil 

environment. Based on a NACE 2006 Paper, “In Support of Direct Assessment Reassessment 

Intervals,” Table 2, “Uhlig’s Corrosion Rate for Steel in Soil According to Soil Resistivity and 

Drainage,” average pitting corrosion rates in steel pipe buried in low resistivity and poor 

drainage soils is 5.5 mpy. Although not directly comparable to the environment in the fuel oil 

storage tank, higher corrosion rates would not be anticipated given the testing for contaminants 

that the applicant conducted. Applying this pitting corrosion rate to the applicant’s design data 

demonstrates sufficient margin to conclude that the intended function(s) of the tank will continue 

to be met between inspections.

The staff finds the applicant’s response acceptable because the applicant has shown that there 

is sufficient margin over a 10-year period to provide reasonable assurance that any corrosion 

occurring due to fuel oil being exposed to the bare metal internal surface of the emergency 

diesel fuel oil storage tank would not challenge the minimum requirements for the tank. 

Furthermore, the preventive measures listed by the applicant will further mitigate the chance of 

corrosion to less than what would be expected for buried steel material. In addition, the periodic 

sampling of the tank to check for corrosion will allow the applicant to take corrective actions 

should any corrosion exist. Therefore, the staff’s concern described in RAI B2.1.16-2 is 

resolved.

On January 22, 2013, the staff held a telephone conference call with the applicant regarding a 

revision to Commitment No. 12 provided by LRA Amendment 14 dated October 31, 2012. In its 

revision to Commitment No. 12, the applicant stated that the blisters in the coating of the train A 

EDG fuel oil storage tank were to be scraped off and the bare metal inspected before the period 

of extended operation. The staff noted that, in the commitment revision, the applicant did not 

indicate whether the blistered areas would be repaired after they were scraped and inspected. 

During the telephone conference call, the staff stated that it had concerns over whether the 

removal of the blisters, without subsequent repair, could potentially weaken the integrity of the 

remaining coating and could lead to coating debris entering into the fuel oil and subsequently 

becoming a debris source that could impact the safety function of the EDG. The applicant 

stated during the telephone conference call that the intention was to repair the coating after the 

blisters were removed. Therefore, by letter dated January 24, 2013, the applicant provided LRA 

Amendment 20 which revised Commitment No. 12 to state that the coating would be repaired 
AGING MANAGEMENT REVIEW RESULTS

3-167

after inspection and before the period of extended operation. By letter dated February 28, 2013, 

the applicant provided LRA Amendment 22 which revised Commitment No.12 to state that the 

coating will be repaired after inspection and six months before the period of extended operation 

or by the end of Callaway’s last RFO before the period of extended operation, whichever occurs 

later. The staff finds this acceptable because repairing the coating will provide reasonable 

assurance that the remaining coating will not become a debris source. The staff’s concern 

regarding Commitment No. 12 is resolved.

Based on its audit and review of the application and a review of RAI B2.1.16-2, the staff finds 

that the applicant has appropriately evaluated plant-specific and industry operating experience

and that implementation of the program has resulted in the applicant taking corrective action. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M30 was evaluated.

FSAR Supplement. LRA Section A1.16 provides the FSAR supplement for the Fuel Oil 

Chemistry Program. The staff reviewed this FSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

noted that the applicant committed (Commitment No. 12) to implement the enhancements to the 

program six months before the period of extended operation for managing aging of applicable 

components during the period of extended operation. The staff also noted that the applicant 

committed (Commitment No. 12) to scraping, inspecting for aging, and repairing the blisters in 

the train A emergency diesel generator fuel oil storage tank six months prior to the period of 

extended operation or by the end of the last RFO before the period of extended operation, 

whichever occurs later. 

The staff noted that the applicant modified LRA Section A.1.16 in response to RAI 3.0.3-2 and 

RAI 3.0.3-2a by letter dated April 23, 2014, to address loss of coating integrity. The staff also 

noted that the applicant committed (Commitment No. 12) to revise the Fuel Oil Chemistry 

Program procedures to address loss of coating integrity as described above in 

Enhancement No. 7.

The staff finds that the information in the FSAR supplement, as amended by letters dated 

January 24, 2013, February 28, 2013, and April 23, 2014, is an adequate summary description 

of the program. The staff noted that the applicant’s FSAR-SP states that ASTM Standards 

D4057 and D975 also will be used to administer the Fuel Oil Chemistry Program. The staff 

finds this acceptable because the GALL Report AMP XI.M30 references these standards as 

examples of acceptable standards for use.

Conclusion. On the basis of its audit and review of the applicant’s Fuel Oil Chemistry Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. Also the staff reviewed the enhancements and confirmed 

that their implementation through Commitment No. 12 six months before the period of extended 

operation will make the AMP adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

FSAR 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

3-168

3.0.3.2.10 Reactor Vessel Surveillance 

Summary of Technical Information in the Application. LRA Section B2.1.17, as amended by 

letters dated June 5, 2012, and October 31, 2012, describes the existing Reactor Vessel 

Surveillance Program as consistent, with enhancements, with GALL Report AMP XI.M31, 

“Reactor Vessel Surveillance.” The LRA states that the AMP manages loss of fracture 

toughness for reactor vessel beltline materials exposed to reactor coolant and neutron flux in 

accordance with the requirements of 10 CFR Part 50, Appendix H, and ASTM E 185-82, 

“Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power 

Reactor Vessels.” The LRA also states that surveillance capsule test results are used to 

demonstrate compliance with the Charpy upper-shelf energy (USE) requirements of 

10 CFR Part 50, Appendix G, and the pressurized thermal shock (PTS) requirements of 

10 CFR 50.61; and they are also used to revise pressure-temperature (P-T) limit curves and 

project the end-of-license neutron fluence. In accordance with the LRA, the last-tested 

surveillance capsule removed from the reactor vessel was exposed to neutron fluence 

equivalent to about 54 effective full power years (EFPY), which slightly exceeds the 60-year 

peak reactor vessel wall neutron fluence. The LRA further states that one of the two standby 

capsules was removed at 71 EFPY of equivalent exposure and is stored in the spent fuel pool 

for reinsertion into the reactor vessel or testing as deemed appropriate. The other standby 

capsule will be removed at approximately 108 EFPY of equivalent exposure, consistent with 

ASTM E 185-82, which states that capsules may be removed from the reactor vessel when the 

capsule neutron fluence is between one and two times the peak fluence calculated for the 

reactor vessel at the end of operating life. In addition, the LRA states that changes to the 

capsule withdrawal schedule will be submitted to the staff for approval, as appropriate.

Staff Evaluation. During its audit, the staff reviewed the applicant’s statement of consistency 

with the GALL Report. The staff compared program elements one through six of the applicant’s 

program to the corresponding program elements of GALL Report AMP XI.M31. For the 

“detection of aging effects” program element, the staff determined the need for additional 

information, which resulted in the issuance of RAIs, as discussed below. 

The “detection of aging effects” program element in GALL Report AMP XI.M31 recommends 

that the Reactor Vessel Surveillance Program have at least one capsule with a projected 

neutron fluence equal to or exceeding the 60-year peak reactor vessel wall neutron fluence 

before the end of the period of extended operation. This program element also recommends 

that the program includes withdrawal of one capsule at an outage in which the capsule receives 

a neutron fluence of between one and two times the peak reactor vessel wall neutron fluence at 

the end of the period of extended operation and includes testing of the capsule in accordance 

with the requirements of ASTM E 185-82. During its audit, the staff noted that the applicant’s 

program was not specific about whether the last surveillance capsule tested under this program 

would meet the above criterion for adequate aging management for 60 years of plant operation. 

Therefore, by letter dated June 22, 2012, the staff issued RAI B2.1.17-1 requesting that the 

applicant identify the neutron fluence (E greater than 1.0 MeV) for this capsule, as determined 

from the capsule dosimetry analysis.

In its response dated July 20, 2012, the applicant stated that “Capsule X” was the last 

surveillance capsule that was tested, and the capsule was exposed to a neutron fluence of 

3.33 x 1019 n/cm2 (E greater than 1.0 MeV), based on the neutron fluence calculated in 

WCAP-15400-NP, “Analysis of Capsule X from The Ameren-UE Callaway Unit 1 Reactor Vessel 

Surveillance Program,” dated June 2000. The applicant also stated that the program 

description section and operating experience section of LRA Section B2.1.17 were revised as 
AGING MANAGEMENT REVIEW RESULTS

3-169

described in LRA Amendment 3, dated June 5, 2012, to identify the neutron fluence for 

“Capsule X.”

The staff finds the applicant’s response acceptable because the applicant provided the 

information necessary for the staff to confirm that the applicant’s surveillance program is 

consistent with the “detection of aging effects” program element, which states that the program 

have at least one capsule with a projected neutron fluence equal to or exceeding the 60-year 

peak reactor vessel wall neutron fluence before the end of the period of extended operation. 

Specifically, the staff confirmed that “Capsule X,” which was the last capsule tested, was 

exposed to a neutron fluence of 3.33 x 1019 n/cm2 (E greater than 1.0 MeV). The staff also 

confirmed that this capsule fluence exceeds the projected 60-year peak reactor vessel wall 

neutron fluence of 2.94 x 1019 n/cm2 (E greater than 1.0 MeV) described in LRA Section 4.2.1, 

consistent with the GALL Report. The staff finds that LRA Section B2.1.17 was appropriately 

revised by LRA Amendment 3, dated June 5, 2012, to identify the neutron fluence for 

“Capsule X.” The staff’s concern described in RAI B2.1.17-1 is resolved.

Based on its review of the applicant’s response to RAI B.2.17-1, the staff finds that the 

surveillance capsule withdrawal schedule criteria of ASTM E 185-82 is satisfied for 60 years of 

plant operation by the withdrawal and testing of “Capsule X,” as documented in 

WCAP-15400-NP. 

The staff noted that the remaining two surveillance capsules are designated as “standby” 

capsules in LRA Section B2.1.17. By letter dated June 22, 2012, the staff issued RAI B2.1.17-2 

requesting that the applicant identify these standby surveillance capsules. In its response dated 

July 20, 2012, the applicant stated that the standby surveillance capsules are “Capsule W” and 

“Capsule Z.” The applicant clarified that “Capsule Z” was previously removed from the reactor 

vessel at 71 EFPY of equivalent reactor vessel exposure and is currently stored in the spent fuel 

pool for reinsertion into the reactor vessel or future testing. The applicant also stated that 

“Capsule W” will be removed at approximately 108 EFPY of equivalent reactor vessel exposure. 

The applicant further stated that LRA Section B2.1.17 was revised by LRA Amendment 3, dated 

June 5, 2012, to identify these standby surveillance capsules.

The staff finds the applicant’s response acceptable because the applicant amended LRA 

Section B2.1.17 to specifically identify the two standby surveillance capsules. The staff finds 

that the maintenance of these two standby capsules satisfies the recommendation of the 

“detection of aging effects” program element in GALL Report AMP XI.M31, which states that the 

program should retain additional capsules within the reactor vessel to support additional testing, 

as needed. The staff’s concern described in RAI B2.1.17-2 is resolved.

The staff also reviewed the portions of the “detection of aging effects” and “monitoring and 

trending” program elements associated with enhancements to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

these enhancements follows.

Enhancement 1. LRA Section B2.1.17 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that following withdrawal of 

the final capsule, RV neutron fluence will be determined by ex-vessel dosimetry. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.M31 and finds that the applicant’s proposal to use ex-vessel dosimetry for monitoring 

neutron fluence following withdrawal of the final capsule will provide appropriate supplemental 

neutron fluence data and is, therefore, acceptable. As part of this enhancement, the applicant 

also stated that the testing specification will be enhanced to require that pulled and tested 
AGING MANAGEMENT REVIEW RESULTS

3-170

surveillance capsules are placed in storage for future reconstitution or reinsertion unless given 

NRC approval to discard. The staff reviewed this enhancement against the corresponding 

program element in GALL Report AMP XI.M31 and finds it acceptable because when it is 

implemented it will ensure that any standby capsules tested in the future will be appropriately 

stored for future reconstitution and reinsertion, as needed, consistent with the recommendation 

of the “detection of aging effects” program element.

Enhancement 2. LRA Section B2.1.17 states an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to specifically require the evaluation of the impact of plant operation changes on the extent of 

RV embrittlement. The staff reviewed this enhancement against the corresponding program 

element in GALL Report AMP XI.M31 and finds it acceptable because when it is implemented it 

will ensure that the applicant’s program is consistent with the recommendation of the 

“monitoring and trending” program element, which states that if future plant operations exceed 

RV embrittlement limitations or bounds, such as operating at a lower cold-leg temperature or 

higher fluence, the impact of plant operation changes on the extent of RV embrittlement is 

evaluated.

Based on its audit of the applicant’s Reactor Vessel Surveillance Program and review of the 

applicant’s responses to RAIs B2.1.17-1 and B2.1.17-2, the staff finds that program elements 

one through six, for which the applicant claimed consistency with the GALL Report, are 

consistent with the corresponding program elements of GALL Report AMP XI.M31. In addition, 

the staff reviewed the enhancements associated with the “detection of aging effects” and 

“monitoring and trending” program elements and finds that when implemented, they will make 

the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.17, as amended by letter dated June 5, 2012, 

summarizes operating experience related to the Reactor Vessel Surveillance Program. As an 

example of how the Reactor Vessel Surveillance Program will be effective in providing sufficient 

material data and dosimetry to monitor irradiation embrittlement during the period of extended 

operation, the applicant identified that (1) the last-tested capsule (Capsule X) specimens were 

exposed to a neutron fluence equivalent to approximately 54 EFPY and (2) the specimen test 

results satisfy the Charpy USE acceptance criterion of 10 CFR Part 50, Appendix G and the 

PTS screening criteria of 10 CFR 50.61. The applicant also noted that the specimen test results 

demonstrate that adjusted nil-ductility reference temperatures based on the surveillance data 

are less than those used in the calculation of the P-T limit curves, thereby demonstrating margin 

in the operating 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. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 
AGING MANAGEMENT REVIEW RESULTS

3-171

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M31 was evaluated.

FSAR Supplement. LRA Section A1.17 provides the FSAR supplement for the Reactor Vessel 

Surveillance Program. The staff reviewed this FSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR 

Table 3.0-1 and noted several inconsistencies between the two descriptions.

The staff noted that SRP-LR Table 3.0-1 recommends that the FSAR supplement provide that 

(1) any future tests of surveillance capsules will meet the requirements of ASTM E 185-82, 

(2) any changes to the capsule withdrawal schedule will be submitted to the NRC for approval,

and (3) untested capsules placed in storage will be maintained for future reinsertion. The staff 

noted that these attributes of the program have been adequately described in LRA 

Section B2.1.17; however, they are not specifically addressed in the Reactor Vessel 

Surveillance Program FSAR supplement (LRA Section A1.17). 

By letter dated October 3, 2012, the staff issued RAI A1.17-1 requesting that the applicant 

revise the FSAR supplement for this program so that it is consistent with the recommended 

description for this program in SRP-LR Table 3.0-1. In its response dated October 31, 2012, the 

applicant stated that LRA Section A1.17 has been revised under LRA Amendment 14 to 

address the three SRP-LR Table 3.0-1 program attributes listed above. LRA Amendment 14 

revisions to LRA Section A1.17 were provided as part of the applicant October 31, 2012, RAI 

response. The staff reviewed these revisions and determined that LRA Section A1.17, as 

revised, adequately describes the three program attributes listed above and is therefore 

consistent with the recommended FSAR supplement description for this program provided in 

SRP-LR Table 3.0-1. Therefore, the staff finds that RAI A1.17-1 is resolved. 

The staff also noted that through LRA Table A4-1, “License Renewal Commitments,” the 

applicant committed (Commitment No. 13) to enhance the Reactor Vessel Surveillance Program 

six months before the period of extended operation to:

• determine the reactor vessel neutron fluence by ex-vessel dosimetry, following 

withdrawal of the final capsule

• require that pulled and tested surveillance capsules be placed in storage for future 

reconstitution or reinsertion unless given NRC approval to discard 

• require that plant operation changes be evaluated to determine the impact on reactor 

vessel embrittlement.

The staff finds that the program enhancements described in Commitment No. 13 are consistent 

with the discussion of program enhancements in LRA Section B2.1.17. The staff finds that the 

information in the FSAR supplement, as amended by letters dated October 31, 2012, and 

February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Reactor Vessel Surveillance 

Program, the staff determined that the 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. 13 six months before the 

period of extended operation will make the AMP adequate to manage the applicable aging 

effects. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 
AGING MANAGEMENT REVIEW RESULTS

3-172

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.11 Selective Leaching 

Summary of Technical Information in the Application. LRA Section B2.1.19 describes the new

Selective Leaching Program as consistent, with an exception, with GALL Report AMP XI.M33, 

“Selective Leaching.” The LRA states that a one-time visual inspection and mechanical 

methods will be used to determine if a loss of material due to selective leaching is occurring. 

The LRA states that a sample of 20 percent of the population, up to a maximum of 

25 component inspections, will be established for each material and environment combination. 

The LRA also states that if selective leaching is detected, followup evaluations will be 

performed. The LRA further states that the Selective Leaching Program will manage gray cast 

iron and copper alloy with greater than 15-percent zinc components within the fire protection, 

CVC, service water, compressed air, ESW, plant heating, fuel building HVAC, auxiliary building 

HVAC, containment purge, and oily waste systems that are within the scope of license renewal 

and exposed to treated water, raw water, waste water, or groundwater.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M33. 

The staff also reviewed the portions of the “parameters monitored or inspected” and “monitoring 

and trending” 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 B2.1.19 states an exception to the “parameters monitored or 

inspected” and “monitoring and trending” program elements. In this exception, the applicant 

stated that selective leaching inspections of buried gray cast iron components exposed to raw 

water or groundwater do not need to be provided if the components are within the scope of the 

fire protection system, have been installed in accordance with NFPA Standard 24, and the 

activity of the fire protection system jockey pump is required to be monitored on an interval not 

to exceed 1 month. The applicant stated that the exception is consistent with the fire protection 

aging management requirements of GALL Report AMP XI.M41, “Buried and Underground 

Piping and Tanks.”

The staff noted that GALL Report AMP XI.M41 specifically states that the program does not 

address selective leaching and that GALL Report AMP XI.M33 is applied in addition to the 

GALL Report AMP XI.M41. Since selective leaching cannot be detected by flow monitoring or 

operation of a jockey pump, a hardness test or alternative mechanical examination is needed to 

determine if selective leaching is occurring. Therefore, by letter dated July 5, 2012, the staff 

issued RAI B2.1.19-1 requesting that the applicant explain how buried gray cast iron 

components in the fire protection system will be managed for loss of material due to selective 

leaching.

In its response dated August 6, 2012, the applicant stated that it revised the exception for the 

“detection of aging effects” program element to opportunistically inspect buried gray cast iron 

fire protection valves. The revised exception also requires that when any buried gray cast iron 

fire protection valves are removed from the fire protection system, the applicant will send 
AGING MANAGEMENT REVIEW RESULTS

3-173

specimens from at least one of the valves to a laboratory for metallurgical testing to determine 

the extent, if any, of selective leaching. The applicant also stated that a minimum of two 

metallurgical tests will be performed within the 5 years before entering the period of extended 

operation. The applicant revised the AMP and the FSAR supplement to reflect the revised 

exception.

The staff finds the applicant’s response and the revised exception acceptable because the 

applicant will perform opportunistic inspections of the buried gray cast iron valves to detect if 

selective leaching is occurring. Although the applicant did not specify a sample size, it did 

commit to send two samples for metallurgical testing within the 5 years before entering the 

period of extended operation. Metallurgical testing more accurately detects degradation due to 

selective leaching than simply scraping and chipping the metal. The staff’s concern described 

in RAI B2.1.19-1 is resolved.

Based on its audit of the applicant’s Selective Leaching Program and review of the applicant’s 

response to RAI B2.1.19-1, the staff finds that program elements one through six for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M33. The staff also reviewed the revised exception 

associated with the “detection of aging effects” program element, and its justification, and finds 

that the AMP, with the exception, is adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.19 summarizes operating experience related to the 

Selective Leaching Program. LRA Section B2.1.19 states that plant-specific operating 

experience was reviewed to ensure that the operating experience discussed in the 

corresponding GALL Report AMP is bounding. Additionally, the applicant searched the 

Callaway CAP to determine if selective leaching had been identified for components with the 

applicable material and environment combinations. The applicant stated that it did not identify 

any occurrences of selective leaching during its search of plant-specific historical information. 

The applicant also stated that plant-specific operating experience will be gained as the program 

is implemented during the period of extended operation and will be factored into the program 

through its 10 CFR 50 Appendix B Quality Assurance Program.

As discussed in the audit report, the staff reviewed CAR operating experience report for 

AMP XI.M33 and conducted an independent review of the applicant’s CAR database. Although 

not cited in the LRA, the applicant identified one occurrence of selective leaching, which 

occurred in the EDG jacket water heat exchanger tubes. The tubes were constructed of 

admiralty brass. The removed tubes were sent to the EPRI NDE Center for examination. One 

of the root causes for the degraded tubes was “dezincification of the admiralty brass tubing.” 

During RFO 17, the applicant replaced the EDG jacket water and lube oil cooler heat 

exchangers with ones that have super-austenitic stainless steel tubes, which are not susceptible 

to selective leaching. Additionally, during RFO 18, the applicant replaced the intercooler heat 

exchangers. The staff reviewed the AMR results for all heat exchanger tubes and confirmed 

that all tubes listed are constructed of materials not susceptible to 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. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 
AGING MANAGEMENT REVIEW RESULTS

3-174

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M33 was evaluated.

FSAR Supplement. LRA Section A1.19 provides the FSAR supplement for the Selective 

Leaching Program. By letter dated August 6, 2012, the applicant revised (LRA Amendment 5) 

the FSAR supplement to reflect a revision to the exception. The staff reviewed the revised 

FSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed (Commitment No. 15) to implement the new Selective Leaching Program within the 

5-year period and no later than six months before entering the period of extended operation for 

managing aging of applicable components.

The staff finds that the information in the FSAR supplement, as amended by letters dated 

August 6, 2012, and February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Selective Leaching Program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exception and its 

justification and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR 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 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Summary of Technical Information in the Application. LRA Section B2.1.23 describes the new

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as 

consistent, with an exception, with GALL Report AMP XI.M38, “Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components.” The LRA states that the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program addresses internal 

surfaces exposed to plant indoor air, ventilation atmosphere, atmosphere and weather, 

condensation, borated water leakage, diesel exhaust, and lubricating oil to manage cracking, 

loss of material, hardening, and loss of strength. The LRA also states that the AMP proposes to 

manage these aging effects through opportunistic visual inspections during periodic system, 

component, and maintenance activities. The LRA further states that inspections will be 

augmented by physical manipulation of polymers, and volumetric evaluations will be performed 

when appropriate. 

As a result of recent staff reviews of several LRAs and of industry OE, the staff has determined 

that additional recommendations beyond those in the GALL Report should be considered in 

regards to managing loss of coating integrity for internal coatings of piping, piping components, 

heat exchangers, and tanks. By letters dated October 7, 2013, and March 25, 2014, the staff 

issued RAI 3.0.3-2 and RAI 3.0.3-2a, respectively, to address loss of coating integrity. In its 

responses dated December 20, 2013, and April 23, 2014, the applicant revised its Internal 
AGING MANAGEMENT REVIEW RESULTS

3-175

Surfaces in Miscellaneous Piping and Ducting Components Program to address loss of coating 

integrity for the service water pump strainers and the service water piping from the circulating 

and service water pump house to the ESW system connection. The staff’s evaluations of the 

applicant’s responses to RAI 3.0.3-2 and RAI 3.0.3-2a are documented in SER Section 3.0.3.4. 

The staff’s evaluation of changes to LRA Sections B2.1.23 and A1.23 to address loss of coating 

integrity follows in the Staff Evaluation and FSAR Supplement sections below.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M38. 

As discussed in the audit report, the “scope of program” program element in the LRA does not 

describe the components included within the scope of the program. GALL Report AMP XI.M38 

states that the program includes internal surfaces of metallic piping, piping components, 

ducting, polymeric components, and other components. 

By letter dated June 5, 2012, the applicant submitted LRA Amendment 3, supplementing its 

description of the components included in the scope of the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to include metallic piping, piping 

components, ducting, polymeric components, and other components. The applicant also 

updated the FSAR supplement in LRA Section A1.23 to reflect the specific component types 

that are in the scope of this program. The staff reviewed the supplemental information and 

noted that the description of components in the amended scope of the program is consistent 

with GALL Report AMP XI.M38. 

LRA Amendment 3 also revised the program description to include additional guidance for 

conducting inspections of a representative sample of components. Specifically, the applicant 

amended the program to state that opportunistic inspections will be supplemented, if needed, to 

ensure that at least 20 percent of each component population (defined as components having 

the same material, environment, and aging effect combination), up to a maximum of 

25 components, will be inspected. By letter dated March 13, 2014, the applicant provided 

additional detail in LRA Sections A1.23 and B2.1.23, stating that the representative sampling 

described above will occur, at a minimum, in each 10-year period during the period of extended 

operation and that these inspections will focus on components most susceptible to degradation. 

Opportunistic inspections will continue in each 10-year period despite meeting the sampling 

limit. 

The staff reviewed the supplemental information regarding minimum inspection sampling and 

noted that it is consistent with GALL Report AMP XI.M38, as revised by LR-ISG-2012-02, 

“Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation.” This LR-ISG revises GALL Report AMP XI.M38 to include 

recommendations for minimum inspection sample size and frequency. 

As amended by letters dated April 23, 2014, and June 5, 2014, LRA Section B2.1.23 provides a 

list of procedure activities associated with coatings inspections (e.g., base line inspections, 

extent of inspections), training and qualification of individuals involved in coating inspections, 

acceptance criteria, and corrective actions. These activities and the corresponding staff 

evaluation are documented in the responses to RAI 3.0.3-2a Request Nos. (2), (5), and (6) in 

SER Section 3.0.3.4.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements 
AGING MANAGEMENT REVIEW RESULTS

3-176

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 B2.1.23 states an exception to the “scope of program,” “parameters 

monitored or inspected,” “detection of aging effects,” and “monitoring and trending” program 

elements. In this exception, the applicant stated that the GALL Report recommends a visual 

examination of the internal surface of components within the scope of the program. The 

applicant also stated that, since the diesel exhaust is not available for internal surface 

inspection, a volumetric examination will be performed in place of visual examinations. The 

staff reviewed this exception against the corresponding program elements in GALL Report 

AMP XI.M38 and finds it acceptable because volumetric inspection is an adequate inspection 

method to identify and manage cracking and loss of material for steel and stainless steel piping, 

piping components, and elements exposed to a diesel exhaust environment. The staff also 

reviewed the program’s inspection frequency for managing these materials, environments, and 

aging effects and found the use of periodic, opportunistic inspections applied during periodic 

surveillance and maintenance activities to be consistent with the GALL Report 

recommendations and, therefore, acceptable. 

Based on its audit of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program, the staff finds that program elements one through six for which 

the applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M38. In addition, based on its review of the 

applicant’s responses to RAIs 3.0.3-2 and 3.0.3-2a, the staff finds that the applicant’s program 

changes to address loss of coating integrity are consistent with recommended measures 

acceptable to the staff for addressing loss of coating integrity for internal coatings as described 

in SER Section 3.0.3.4. The staff also reviewed the exception associated with the “scope of 

program,” “parameters monitored or inspected,” “detection of aging effects,” and “monitoring 

and trending” program elements, and its justification, and finds that the AMP, with the exception, 

is adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.23 summarizes operating experience related to the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

LRA states that internal surface monitoring using visual inspections is already in use at the 

Callaway plant with results trended and used for work planning and prioritization. The LRA 

states that a review of the current inspections applied to internal surface components has 

indicated that these inspections have been effective. The LRA also states that internal 

inspections have been used during maintenance activities for the centrifugal charging pump 

room cooler, which revealed a loss of material due to corrosion of threaded tube end plugs. The 

LRA further states that these indications were evaluated and corrective action was completed. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 
AGING MANAGEMENT REVIEW RESULTS

3-177

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M38 was evaluated.

FSAR Supplement. LRA Section A1.23, as amended by letters dated June 5, 2013, 

December 20, 2013, March 13, 2014, and April 23, 2014, provides the FSAR supplement for the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

staff reviewed this FSAR supplement description of the program against the recommended 

description for this type of program as described in LR-2012-02, Table 3.0-1. The staff noted 

that the applicant committed (Commitment No. 18) to implement the new Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program six months before entering 

the period of extended operation for managing the applicable aging effects. 

The staff finds that the information in the FSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program, the staff determines that 

the program elements for which the applicant claimed consistency with the GALL Report are 

consistent. In addition, the staff reviewed the exception and its justification and determined that 

the AMP, with the exception, is adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

FSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.13 Lubricating Oil Analysis 

Summary of Technical Information in the Application. LRA Section B2.1.24 describes the 

existing Lubricating Oil Analysis Program as consistent, with enhancements, with GALL Report 

AMP XI.M39, “Lubricating Oil Analysis.” The LRA states that the program manages oil 

environments to prevent loss of material and reduction of heat transfer. The LRA states that the 

program does not manage component surfaces directly, but maintains lubricating oil 

contaminants (primarily water and particulates) within acceptable limits, thereby preserving an 

environment that is not conducive to loss of material or reduction of heat transfer. The LRA also 

states that the program includes sampling, analysis, and condition monitoring activities to 

identify detrimental contaminants, such as water, particulates, and specific wear elements. The 

LRA further states that corrective actions are taken when the component’s oil sample has phase 

separated water or water content exceeds an established target value. In addition the LRA 

states that the One-Time Inspection Program will be used to verify the effectiveness of the 

Lubricating Oil Analysis Program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M39. 

The staff also reviewed the portions of the “scope of program,” “detection of aging effects,” and 

“acceptance criteria” program elements associated with enhancements to determine whether 

the program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these enhancements follows.
AGING MANAGEMENT REVIEW RESULTS

3-178

Enhancement 1. LRA Section B2.1.24 states an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that before the period of extended 

operation, procedures will be enhanced to indicate that lubricating oil contaminants are 

maintained within acceptable limits, thereby preserving an environment not conducive to loss of 

material or reduction in heat transfer. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M39 and finds it acceptable because 

when it is implemented it will make the existing Lubricating Oil Program consistent with the 

GALL Report AMP.

Enhancement 2. LRA Section B2.1.24 states an enhancement to the “detection of aging 

effects,” and “acceptance criteria” program elements. In this enhancement, the applicant stated 

that procedures will be enhanced to state the testing standards for water content and particle 

count. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M39 and finds it acceptable because when it is implemented it will make 

the existing Lubricating Oil Program consistent with the GALL Report AMP.

Enhancement 3. LRA Section B2.1.24 states an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to state that phase separated water in any amount is not acceptable. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M39 and 

finds it acceptable because when it is implemented it will make the existing lubricating oil 

program consistent with the GALL Report AMP.

Based on its audit of the applicant’s Lubricating Oil Program, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M39. In addition, 

the staff reviewed the enhancements associated with the “scope of program,” “detection of 

aging effects,” and “acceptance criteria” program elements and finds that when implemented, 

they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.24 summarizes operating experience related to the 

Lubricating Oil Analysis Program. The LRA states that in 2004, during an analysis of the 

auxiliary feedwater pump turbine lubricating oil, the oil sample from the reservoir was found to 

contain elevated water content (over 5,000 parts per million). The LRA states that the cause 

was identified as a turbine steam leak from the outboard gland casing that migrated into the 

lube oil system. The LRA also states that the steam leak was repaired, and the oil quality was 

restored through an oil change. The LRA further states that in 2009, during a routine analysis of 

the turbine-driven auxiliary feedwater pump lubricating oil, the oil sample on the outboard 

bearing reservoir was observed to be dark because of elevated iron content. The LRA states 

that the cause was determined to be an improperly installed bearing retainer ring, and the ring 

was subsequently installed correctly. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation. 
AGING MANAGEMENT REVIEW RESULTS

3-179

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.M39 was evaluated.

FSAR Supplement. LRA Section A1.24 provides the FSAR supplement for the Lubricating Oil 

Analysis Program. The staff reviewed this FSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 19) to enhance the Lubricating Oil 

Analysis Program, as described above, six months before the period of extended operation for 

managing aging of applicable components during the period of extended operation.

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Lubricating Oil Analysis 

Program, the staff determined that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements 

and confirmed that their implementation through Commitment No. 19 six months before the 

period of extended operation will make the AMP adequate to manage the applicable aging 

effects. The staff concluded that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR supplement for this AMP and concluded that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.2.14 Buried and Underground Piping and Tanks

Summary of Technical Information in the Application. LRA Section B2.1.25 describes the new 

Buried and Underground Piping and Tanks Program as consistent, with exceptions, with 

GALL Report AMP XI.M41, “Buried and Underground Piping and Tanks.” The LRA states that 

the AMP addresses steel, stainless steel, and HDPE piping and tanks exposed to a buried or 

underground environment to manage the effects of loss of material, cracking, blistering, and 

changes in color of the external surfaces of these components. The LRA also states that the 

AMP will manage these aging effects through preventive, mitigative, and inspection activities, 

including coatings, quality of backfill, cathodic protection, periodic inspections, and monitoring of 

the fire protection jockey pump activity.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M41.

By letter dated December 19, 2012, the applicant submitted LRA Amendment 18, which stated 

that no direct visual inspections would be required for buried, in-scope HDPE piping because it 

is encased in controlled low-strength material. The staff finds this acceptable because it is 

consistent with LR-ISG-2011-03, “Changes to the Generic Aging Lessons Learned (GALL) 

Report Revision 2 Aging Management Program (AMP) XI.M41, ‘Buried and Underground Piping 

and Tanks’.”
AGING MANAGEMENT REVIEW RESULTS

3-180

For the “scope of program,” “preventive actions,” “detection of aging effects,” and “acceptance 

criteria” program elements, the staff determined the need for additional information, which 

resulted in the issuance of RAIs, as discussed below.

During its audit, the staff reviewed license renewal drawings for the emergency diesel engine 

fuel oil storage and transfer system. The system appears to include in-scope underground 

piping; however, LRA Table 3.3.2-21, “Auxiliary Systems–Summary of Aging Management 

Evaluation–Emergency Diesel Engine Fuel Oil Storage and Transfer System,” does not include 

any AMR items associated with underground piping. By letter dated July 5, 2012, the staff 

issued RAI B2.1.25-1 requesting that the applicant clarify whether there is underground piping in 

the emergency diesel engine fuel oil storage and transfer system that is within the scope of 

license renewal, and if there is, to describe how the piping will be managed for aging.

In its response dated August 6, 2012, the applicant stated that the emergency diesel engine fuel 

oil storage and transfer system has in-scope underground carbon steel piping, which will be age 

managed for loss of material by the Buried and Underground Piping and Tanks Program. The 

applicant revised LRA Table 3.3.2-21 and Section B2.1.25 to include these components.

The staff finds the applicant’s response acceptable because the aging of the underground 

components in the emergency diesel engine fuel oil storage and transfer system will be 

managed for loss of material by the Buried and Underground Piping and Tanks Program, which 

is consistent with the GALL Report, and the LRA has been amended to reflect the change. The 

staff’s concern described in RAI B2.1.25-1 is resolved.

The “preventive actions” program element in GALL Report AMP XI.M41 recommends that 

coatings are provided based on environmental conditions, and if coatings are not provided, a 

justification is provided in the LRA. However, during its audit, the staff noted that the applicant’s 

Buried and Underground Piping and Tanks Program states that coatings for buried stainless 

steel piping are only required to protect from a chloride environment to prevent stress-corrosion 

cracking. In addition, it states that the design temperature of the UHS is 95 °F (35 °C), and the 

maximum temperature of the refueling water storage tank is 120 °F (49 °C). The basis 

document further states that these temperatures are below the threshold temperature for 

stress-corrosion cracking as stated in GALL Report Section IX.D. The staff recognizes that the 

temperature threshold of 140 °F (60 °C) for stress-corrosion cracking in stainless steel in 

Table IX.D of the GALL Report implies that this threshold is applicable in treated water 

environments where the level of contaminants is controlled. However, the soil environment is 

not controlled to preclude the potential for significant levels of contaminants. Given that 

contaminants can accumulate in the soil due to normal environmental interactions, the 

140 °F(60 °C) threshold may not apply to buried piping. In addition, the GALL Report, item 

AP-137, states that stainless steel components exposed to soil are susceptible to loss of 

material caused by pitting and crevice corrosion. By letter dated July 5, 2012, the staff issued 

RAI B2.1.25-2 requesting that the applicant provide the results of soil sampling in the vicinity of 

in-scope buried uncoated stainless steel piping that demonstrate that loss of material due to 

pitting and crevice corrosion, and stress-corrosion cracking will not occur due to exposure to 

contaminants in the soil. If this is not the case, the applicant was asked to state how these 

aging effects will be managed.

In its response dated August 6, 2012, as amended by letter dated August 21, 2012, the 

applicant stated that a soil survey conducted on July 9, 2012, sampled four locations in the 

same excavation ditch (measuring 15 feet by 12 feet by 12 feet) containing two in-scope 

stainless steel pipes. The results of the soil samples indicated that the pH was 7.6 to 8.0, 
AGING MANAGEMENT REVIEW RESULTS

3-181

chlorides were less than 2.7 ppm, soil resistivity was above 10,000 ohm-cm, and redox potential 

was in the range of -44 to 17 mV.

Based on a review of “Corrosion Resistance of Stainless Steels in Soils and in Concrete,” paper 

presented at the Plenary Days of the Committee on the Study of Pipe Corrosion and Protection, 

Ceocor, Biarritz, October 2001, by Pierre-Jean Cunat, the staff noted the following:

• Buried pipelines suffer from corrosion when the pH is less than 4.5 and soil resistivity is 

less than 1000 ohm-cm.

• The paper states that, “[i]n principle, stainless steels should be in the passive state in 

soils, but the presence of water and aggressive chemical species such as chloride ions, 

sulphates and as well as types of bacteria and stray current can cause localized 

corrosion. This probability increases with increasing chloride ion content and higher 

redox potential.”

• Table 2, “Critical value of Cl- for a number of stainless steels in aqueous chloride 

containing environment,” cites a threshold of 500 ppm for chlorides.

The staff finds the applicant’s response acceptable because four samples demonstrated a low 

corrosion potential for buried stainless steel piping; therefore, the 140 °F (60 °C) threshold is 

acceptable. The staff’s concern described in RAI B2.1.25-2 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M41 states that the 

fire water jockey pump performance may be monitored in place of conducting excavated direct 

visual examinations of in-scope buried fire water system piping. During its audit, the staff noted 

that the applicant’s Buried and Underground Piping and Tanks Program credits this feature of 

AMP XI.M41; however, the staff noted that there have been numerous leaks in the fire water 

system piping. Therefore, it was not clear to the staff if the fire water jockey pump has sufficient 

non-running time between pump runs such that a change due to leakage could be detected. By 

letter dated July 5, 2012, the staff issued RAI B2.1.25-4, requesting that the applicant provide a 

summary of trend results for the fire water jockey pump for the past 5 years and explain whether 

there is sufficient non-running time between pump runs to detect leaks in in-scope buried piping. 

If the trend results are not capable of demonstrating this, state the basis for why monitoring fire 

water jockey pump performance is sufficient to ensure that the fire water system will meet its 

intended function during the period of extended operation.

In its response dated August 6, 2012, the applicant stated that a 5-year review of jockey pump 

run data demonstrated that typically there are 15 minutes between runs of the pump. The 

applicant stated that “[o]peration of the pump is monitored daily in the [c]ontrol [r]oom, and an 

alarm is received when run time becomes excessive (200 seconds).” The applicant also stated 

that a system engineer performs monthly trend reviews of pump operation. The applicant 

further stated that the jockey pump has been used successfully as a troubleshooting tool to 

locate leakage and quantify leaks by isolating portions of the system and checking run times on 

the jockey pump.

The staff finds the applicant’s response acceptable because a 5-year review of trend data 

demonstrated that there are sufficient periods of time when the pump is not running to use run 

time as a performance measure, in that a change from the normal 15 minutes downtime can be 

easily detected during trending. Therefore, the jockey pump trend data can be effectively used 

to age manage the buried fire protection piping. The staff’s concern described in RAI B2.1.25-4 

is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-182

The “acceptance criteria” program element in GALL Report AMP XI.M41 states that “[c]riteria for 

soil-to-pipe potential are listed in NACE RP0285-2002 and SP0169-2007.” NACE SP0169-2007 

Section 6.2.2.2.2 states, “[i]n some situations, such as the presence of sulfides, bacteria, 

elevated temperatures, acid environments, and dissimilar metals, the criteria in 

Paragraph 6.2.2.1 may not be sufficient.” NACE SP0169-2007 Section 6.2.2.3.3 states, “[t]he 

use of excessive polarized potentials on externally coated pipelines should be avoided to 

minimize cathodic disbondment of the coating.” However, during its audit, the staff found that 

the “Close-Interval Survey and Direct Current Voltage Gradient Survey Buried Fire Water 

Protection Piping,” report dated May 7, 2008, recommended that for locations not 

meeting -850 mV criterion, station personnel should determine whether the alternative 100 mV 

potential shift criterion would demonstrate acceptable cathodic protection. In addition, it 

recommended that locations more negative than -1,200 mV be addressed to ensure that coating 

disbondment does not occur. LR-ISG-2011-03 states that when dissimilar metals are present in 

the environment (e.g., steel in relation to the copper grounding grid) the 100 mV criterion is only 

acceptable if it can be demonstrated that the most noble metal will be adequately protected. If 

the applicant will use the 100 mV criterion on in-scope components during the period of 

extended operation, it should provide the basis for protecting the most noble metal. In addition, 

to verify consistency with the GALL Report AMP XI.M41, the staff must understand the 

applicant’s approach to locations more negative than -1,200 mV. By letter dated July 5, 2012, 

the staff issued RAI B2.1.25-5 requesting that the applicant state whether the 100 mV 

polarization will be used as acceptance criterion, and if so, to state the basis for how the most 

noble buried in-scope material will be adequately protected. The staff also asked the applicant 

to state whether as-left survey findings will be allowed to be more negative than -1,200 mV, and 

if they will, to state the basis for why protective coating disbondment will not occur.

In its response, dated August 6, 2012, the applicant stated that:

The Buried and Underground Piping and Tanks Program will use the 100 mV 

polarization as an acceptance criterion based on protecting the most noble metal 

in a dissimilar metal environment consistent with NACE SP0169-2007 

Section 6.2 criteria. Protection of the most noble buried in-scope material will 

consist of evaluating the buried metallic piping and tanks that are electrically tied 

together. Using published industry galvanic series charts, the most anodic 

material will be identified and then raised 100 mV greater than the published 

number in relation to the copper-copper sulfate half-cell. Instances where 

protection cannot be demonstrated with this method will be entered into the 

Corrective Action Program. The EPRI sponsored Cathodic Protection User’s 

Group will be used to provide operating experience associated with the 100 mV 

criteria.

In addition, the applicant stated that any instant-off reading more negative than -1200 mV will be 

investigated and appropriate corrective actions will be taken. Given that LR-ISG-2011-03, 

“Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, ‘Buried and 

Underground Piping and Tanks,” Table 6a, “Cathodic Protection Acceptance Criteria,” provides 

specific cathodic protection criteria and does not cite NACE SP0169-2007, the intent of the 

applicant’s reference to NACE SP0169-2007 is not clear. In relation to the applicant’s 

statement, “[p]rotection of the most noble buried in-scope material will consist of evaluating the 

buried metallic piping and tanks that are electrically tied together,” it is not clear to the staff why 

the applicant did not include the copper grounding grid in the evaluation scope. The staff could 

not determine how the applicant would apply the galvanic series chart in relation to as-found 

cathodic protection survey data. Finally, the staff believes that when the 100 mV polarization 
AGING MANAGEMENT REVIEW RESULTS

3-183

criterion is used, there must be some way (e.g., buried coupons, electrical resistance probes) to 

verify that the most anodic material is being protected. By letter dated October 1, 2012, the staff 

issued RAI B2.1.25-5a requesting that the applicant state: the basis for use of the 100 mV 

criterion absent a means to verify its effectiveness in preventing corrosion of the least noble 

metal; why the copper grounding grid was not included in the scope of buried items to be 

evaluated in relation to consideration of the galvanic series chart, specifically how the 100 mV 

criterion will be applied in relation to the galvanic series chart and for which materials the 

criterion will be used; what methods will be used to confirm the results of the cathodic protection 

surveys; and revise the Buried and Underground Piping and Tanks Program and FSAR 

supplement to reflect the use of this method and state what actions will be taken if the chosen 

method indicates that corrosion of in-scope buried components is occurring more rapidly than 

expected.

In its response, dated October 31, 2012, the applicant stated the following:

• Given that the in-scope buried piping is not electrically isolated either from the grounding 

grid or plant systems, bonding jumpers were used in the design of the cathodic 

protection system to minimize the effects of stray currents, and no data exists on the 

results of mixed metal impacts between the grounding grid and the buried piping. Thus, 

there is no basis at this time to support use of the 100mV.

• During research of galvanic series charts, it was identified that there exists a wide range 

of polarization readings for similar metals. This varying range did not provide an 

adequate basis for which to draw acceptance criterion from and therefore will not be 

used. The staff noted that this portion of the response eliminates the need to respond to 

why the copper grounding grid was not included in the scope of buried items to be 

evaluated because it only had to be included if the applicant was going to use the 

galvanic series to justify use of the 100 mV criterion.

• Corrosion coupons will be used to ensure that the cathodic protection system is 

providing sufficient protection for buried steel components within the scope of license 

renewal. Troubleshooting of the cathodic protection system will be conducted if 

corrosion rates are demonstrated to be higher than expected.

The applicant did not provide sufficient details on how coupons will be used, such as coupon 

characteristics, coupon placement, analysis of coupon results, acceptance criteria, and, during 

the time period when the effectiveness is indeterminate (i.e., it may take several years for the 

actual pitting or general corrosion to proceed beyond nominal thickness measurements of the 

coupon), how many inspections of under-protected buried pipe will occur. By letter dated 

December 27, 2012, the staff issued RAI B2.1.25-5b requesting that the applicant address the 

above issues.

In its response, dated January 24, 2013, the applicant removed references to the use of 

coupons from LRA Sections A1.25 and B2.1.25. The applicant stated that if the cathodic 

protection system does not meet the availability and effectiveness criteria of LR-ISG-2011-03, 

Table 4a, “Inspections of Buried Pipe,” the Category D, E, or F inspection criteria will be used as 

applicable. 

The staff finds the applicant’s response acceptable because Table 4a inspection category D, E, 

or F is the appropriate inspection category to use if an installed cathodic protection system is 

not meeting availability and effectiveness goals. The applicant’s proposal is consistent with 
AGING MANAGEMENT REVIEW RESULTS

3-184

LR-ISG-2011-03. The staff’s concerns described in RAI B2.1.25-5, B2.1.25-5a, and B2.1.25-5b 

are resolved.

The staff also reviewed the portions of the “preventive actions” and “detection of aging effects” 

program elements associated with 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 B2.1.25 originally stated an exception to the “preventive actions” 

program element for HDPE piping that is not coated. By letter dated December 19, 2012, the 

applicant amended its LRA to remove Exception 1 from the Buried and Underground Piping and 

Tanks Program. The staff finds it acceptable to remove this exception because 

LR-ISG-2011-03 states that buried polymeric materials do not need to be coated. 

Exception 2. LRA Section B2.1.25 originally stated an exception to the “detection of aging 

effects” program element to exclude UT of underground piping to detect internal corrosion. By 

letter dated December 19, 2012, the applicant amended its LRA to remove Exception 2 from the 

Buried and Underground Piping and Tanks program. The staff finds it acceptable to remove this 

exception because LR-ISG-2011-03 removed the recommendation to conduct UT examinations 

of underground piping to detect internal corrosion. 

Exception 3. LRA Section B2.1.25 originally stated an exception to the “detection of aging 

effects” program element for expansion of samples if adverse indications are found in the 

expanded sample. By letter dated December 19, 2012, the applicant amended its LRA to 

remove Exception 3 from the Buried and Underground Piping and Tanks program. The staff 

finds it acceptable to remove this exception because the program is consistent with the revised 

AMP as documented in LR-ISG-2011-03, which states that if adverse indications are found in 

the expanded sample (i.e., the doubled sample size based on detecting the initial adverse 

condition), further increases in inspection sample size should be based on an analysis of extent 

of cause and extent of condition. 

Based on its audit and review of the applicant’s responses to RAIs B2.1.25-1, B2.1.25-2, 

B2.1.25-4, B2.1.25-5, B2.1.25-5a, and B2.1.25-5b, the staff finds that the program elements for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03. The staff also reviewed the exceptions associated with the “preventive 

actions” and “detection of aging effects” program elements and their justifications, including the 

basis for the removal of the exceptions, and finds that the AMP is adequate to manage the 

applicable aging effects.

Operating Experience. LRA Section B2.1.25 summarizes operating experience related to the 

Buried and Underground Piping and Tanks Program. The applicant stated that a fire protection 

loop leak was detected by a change in jockey pump performance, and the leak was promptly 

repaired. The applicant also stated that close interval and cathodic protection surveys have 

detected areas where the buried piping is not being adequately cathodically protected. 

Corrective actions were implemented or are in planning to adjust the system to provide the 

correct level of protection. The applicant further stated that from 2008 to 2009 portions of the 

ESW system were replaced with HDPE piping because of material conditions of the system, 

including pinhole leaks, pitting, and other localized degradation of the pressure boundary. 

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 
AGING MANAGEMENT REVIEW RESULTS

3-185

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, resulting in the issuance of an RAI, as discussed below.

LRA Table 3.3.2-4 states that there are steel piping, strainer, and valve components in the 

ESW system. Given that these steel components are in the same environment as the 

components that were replaced with HDPE material, it is possible that the degradation of the 

steel piping will occur at the same rate (on a unit length basis) as experienced in the past for the 

entire system. Also, given inconsistent site-wide performance of the cathodic protection system, 

the staff lacked sufficient information to determine if four inspections in each 10-year period will 

ensure that the intended function(s) of the portions of the ESW that have not been replaced with 

HDPE piping will be met during the period of extended operation. By letter dated July 5, 2012, 

the staff issued RAI B2.1.25-6 requesting that the applicant state the basis for why four 

inspections in each 10-year period, starting 10 years before the period of extended operation, of 

buried steel piping in the ESW system are sufficient.

In its response dated August 6, 2012, the applicant stated that AMP XI.M41 recommends that 

four inspections be conducted in locations where cathodic protection has not been operated 

consistent with the AMP recommendations as long as coatings and backfill are consistent with 

AMP standards. The applicant also stated that, while the cathodic protection system is not 

currently being operated in accordance with the recommendations in the AMP, the ESW piping 

coatings and backfill do meet AMP XI.M41 recommendations and, therefore, four inspections in 

the 10-year period before the period of extended operation would be appropriate. The applicant 

further stated that, if operation of the cathodic protection system were to be brought into 

conformance with the recommendations in AMP XI.M41 during the period of extended 

operation, one inspection would be conducted in each 10-year period. The applicant stated if, 

after the cathodic protection system has been upgraded to meet the recommendations of 

AMP XI.M41, further degradation of the ESW piping were to occur, the number of inspections 

would be increased consistent with the recommendations in AMP XI.M41 for adverse 

conditions.

The staff noted that based upon a review of the response to RAI B2.1.1-1, associated with the 

ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, and 

RAI B2.1.10-6, associated with the Open-Cycle Cooling Water System Program, the applicant 

categorized failures that have occurred in the ESW piping. The former RAI response states that 

leaks have occurred because of MIC and that no leaks have occurred since 2005. The latter 

RAI response states that only one leak has occurred to date in buried ESW piping, and this leak 

was caused by MIC. It was not clear to the staff if any of these leaks occurred because of 

external MIC. The staff noted that, based on its review of plant-specific operating experience, 

three leaks and one instance of coating degradation occurred in fire protection piping. It was 

not clear to the staff if the buried fire protection piping leaks and coating degradation occurred in 

locations with the same specifications for backfill as for the ESW piping. If the ESW piping 

leaks that the MIC caused originated from the outside surface of the buried piping or the fire 

protection buried piping leaks occurred in locations where the backfill specifications were the 

same as for the ESW piping, four inspections in the 10-year period before the period of 

extended operation would not be consistent with the recommendations in LR-ISG-2011-03. The 

staff also noted that LR-ISG-2011-03 revised the recommendation related to the number of 
AGING MANAGEMENT REVIEW RESULTS

3-186

buried piping inspections for instances in which cathodic protection does not meet availability 

and effectiveness goals from 4 per 10-year period (starting 10 years before the period of 

extended operation) to 7, 10, and 12 inspections in each of the 10-year periods, respectively. 

By letter dated October 1, 2012, the staff issued RAI B2.1.25-6a requesting that the applicant 

state if any of the ESW leaks originated from the outside surface of the buried piping, whether 

buried fire protection leaks originating from the outside surface of the buried piping occurred in 

locations where the backfill specifications were the same as those for the in-scope ESW piping, 

and the basis for why four inspections would be sufficient to ensure that the buried in-scope 

ESW piping would meet its intended function(s) for instances where cathodic protection does 

not meet availability and effectiveness goals recommended in LR-ISG-2011-03.

In its response, dated October 31, 2012, the applicant stated the following: 

• None of the leaks in the ESW system originated from the outside surface of the buried 

pipe.

• The fire protection leaks that originated from the outside surface of buried piping were all 

on piping that was installed in commercial-grade backfill, whereas the backfill for buried 

piping within the power block meets the requirements of Table 2a, “Preventive Actions 

for Buried Piping and Tanks,” of LR-ISG-2011-03.

• For sections of piping that do not meet the availability or effectiveness criteria 

(i.e., 85 percent and 80 percent, respectively) recommended in LR-ISG-2011-03, the 

inspection quantities of Preventive Action Category E of Table 4a, “Inspections of Buried 

Pipe,” will be met.

• The number of inspections is consistent with Category E because backfill and coatings 

have been provided in accordance with Table 2a of LR-ISG-2011-03, and plant 

operating experience has not identified any leaks or significant coating degradation 

associated with in-scope buried piping.

The staff finds the applicant’s response acceptable, in part, because (a) the leaks from ESW 

piping have not occurred because of external coating degradation, (b) the leaks originating from 

external coating degradation in the fire water system piping have been located in areas where 

the backfill is commercial grade, (c) the backfill within the power block (i.e., where in-scope 

piping is located) meets the quality requirements of Table 2a of LR-ISG-2011-03, and (d) there 

is no plant-specific operating experience related to piping leakage or coating degradation for 

in-scope buried piping where the backfill requirements meet Table 2a of LR-ISG-2011-03, such 

as ESW piping. In addition, the applicant cited the 85-percent availability and 80-percent 

effectiveness criteria for cathodic protection from LR-ISG-2011-03. The staff does not agree 

that all of the conditions for the applicability of the Category E inspection quantities have been 

met. In that regard, Table 4a, footnote 2.E.ii.c, states that, to use Category E, the soil must 

have been demonstrated to be not corrosive for the material type. Footnote 7 of this table 

provides the recommendations related to soil sampling. The staff recognizes that, in its 

response to RAI B2.1.25-2, above, the applicant provided soil sample results for portions of 

buried stainless steel piping. Given the potential for variability in soil corrosivity, these sample 

results do not meet the intent of the recommendations in footnote 7 for steel piping. 

In addition, the staff recognizes that corrosion coupons will be used in areas where the cathodic 

protection system has been demonstrated to be ineffective. However, the staff did not believe 

that corrosion coupons can be substituted for soil sample results in regard to selection of the 

appropriate inspection category. By letter dated December 27, 2012, the staff issued 
AGING MANAGEMENT REVIEW RESULTS

3-187

RAI B2.1.25-6b requesting that the applicant provide soil sample results from the vicinity of 

buried in-scope steel piping sufficient to meet the recommendations of footnote 7 of 

LR-ISG-2011-03 Table 4a if available, and if not available, commit to completing the soil 

sampling during the 10-year period before the period of extended operation and in each 

subsequent 10-year period of extended operation. Alternatively, or if the soil is demonstrated to 

be corrosive, the staff requested that the applicant revise the Buried and Underground Piping 

and Tanks Program to ensure that the number of buried pipe inspections will meet Category F 

in the 10-year period before the period of extended operation and in each subsequent 10-year 

interval where the cathodic protection system does not meet the availability and effectiveness 

criteria of LR-ISG-2011-03, and revise the FSAR Supplement to reflect the need to conduct soil 

sampling where the cathodic protection system does not meet the criteria of LR-ISG-2011-03.

In its response dated January 24, 2013, the applicant stated the following:

• Soil sample results in the vicinity of buried in-scope steel piping are not available.

• When the cathodic protection system does not meet availability or effectiveness criteria, 

soil sampling will be conducted. The soil samples will be conducted during the 10-year 

period prior to the period of extended operation and in each subsequent 10-year period. 

The samples will be obtained and tested to the recommendations included in 

LR-ISG-2011-03, Table 4a, Footnote 7. If the soil is not corrosive, the number of 

inspections will be based on Table 4a inspection category E. If the soil is corrosive, the 

number of inspections will be based on Table 4a inspection category F.

• LRA Section B2.1.25 has been revised to state the requirements for soil sampling and 

the required number of inspections.

• LRA Section A1.25 has been revised to reflect the need to perform soil sampling.

The staff finds the applicant’s response acceptable because the soil sampling frequency and 

parameters and inspection quantities based on the results of the soil sampling are consistent 

with LR-ISG-2011-03. The staff’s concerns described in RAI B2.1.25-6, B2.1.25-6a, and 

B2.1.25-6b are resolved.

The staff noted that the response to RAI B2.1.14-5 related to the Fire Water System Program 

states “[t]he coal tar enamel that is on the FPS can be expected to have a service life ranging 

from 15 to 50 years depending on soil environment. Plant operating experience reflects that 

some of the coating for buried fire protection system piping is nearing the end of its service life.” 

It is not clear to the staff whether the portion of the fire water system where the coating is 

nearing the end of its service life is in-scope piping. If in-scope piping is affected, then 

LR-ISG-2011-03 recommends that 15, 20, and 25 inspections be conducted in each respective 

10-year period (e.g., 15 inspections in the 30- to 40-year period) starting 10 years before the 

period of extended operation if the cathodic protection system is not meeting availability or 

effectiveness goals. By letter dated October 1, 2012, the staff issued RAI B2.1.25-7 requesting 

that the applicant state whether the portion of the fire water system where the coating is nearing 

the end of its service life is within the scope of license renewal, whether the coating on any 

other buried in-scope piping is nearing the end of its service life, and, if the coatings on any 

buried in-scope steel piping are approaching end of life, state the basis for why four inspections 

would be sufficient to ensure that the buried in-scope ESW piping would meet its intended 

function(s) for instances where cathodic protection does not meet availability and effectiveness 

goals recommended in LR-ISG-2011-03.
AGING MANAGEMENT REVIEW RESULTS

3-188

In its response, dated October 31, 2012, the applicant stated that:

The information previously provided regarding the 15-50 year service life for coal 

tar enamel applied to buried piping was given to provide general information 

about the coating for a variety of applications and environmental considerations. 

This time frame was not intended to convey that, at a specific time, the coating 

will no longer provide protection for the buried piping.

The applicant also stated that inspections of in-scope buried fire protection and other 

system piping have shown no significant degradation of the coatings, and there is no 

indication that there are any sections of buried piping which are nearing the end of the 

coating service life. The applicant updated Table 1 of the original response to 

RAI B2.1.14-5 to reflect that the leak resulting from external degradation of the coating 

and piping was not in an in-scope portion of buried fire protection system. 

The staff finds the applicant’s response acceptable because the information on coating life was 

provided in a general, not specific, context; plant-specific inspections have demonstrated that 

in-scope coatings are not approaching end-of-life; and subsequent excavated direct visual 

inspections of buried piping conducted by this program will provide further evidence of the 

condition of the coatings on the piping. The staff’s concern described in B2.1.25-7 is resolved.

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

RAIs B2.1.25-6, B2.1.25-6a, B2.1.25-6b, and B2.1.25-7, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M41 was evaluated.

FSAR Supplement. LRA Section A2.1.25 provides the FSAR supplement for the Buried and 

Underground Piping and Tanks Program. The staff reviewed this FSAR supplement description 

of the program against the recommended description for this type of program as described in 

SRP-LR Table 3.0-1 and noted that the applicant’s Buried and Underground Piping and Tanks 

Program states that the preventive actions of the program will be consistent with the GALL 

Report. However, during its audit, the staff identified five CARs spanning 2006 through 2010 

citing weakness in cathodic protection system performance. In addition, a Close-Interval Survey 

and Direct Current Voltage Gradient Survey-Buried Fire Water Protection Piping, dated 

May 2008, states that 23 percent of the fire protection system, representing 2,658 feet of piping, 

was inadequately protected. Given that plant-specific operating experience demonstrates a 

long period of degraded performance of the cathodic protection system, further details on 

cathodic protection system availability and effectiveness should be included in the FSAR 

supplement summary description. The licensing basis for this program for the period of 

extended operation may not be adequate if the applicant does not incorporate this information 

into its FSAR supplement. 

By letter dated July 5, 2012, the staff issued RAI B2.1.25-3 requesting that the applicant revise 

the LRA Section A1.25 discussion of cathodic protection to include a discussion that the 

cathodic protection system meets NACE SP0169 or NACE RP0285, that it is monitored for 

effectiveness at least once a year, and that potential difference and current measurements are 

trended to identify changes in the effectiveness of the systems and coatings.

In its response, dated August 6, 2012, the applicant revised LRA Sections A1.25 and B2.1.25 to 

state that the cathodic protection system is operated consistent with the guidance in NACE 

SP0169-2007 for piping and NACE RP0285-2002 for tanks, that trending of the cathodic 
AGING MANAGEMENT REVIEW RESULTS

3-189

protection system is performed to identify changes in the effectiveness of the system and to 

ensure that the rectifiers are available to protect buried components, and that an annual 

cathodic protection survey is performed consistent with NACE SP0169-2007.

The staff finds the applicant’s response acceptable because the FSAR supplement has been 

updated; therefore, the FSAR will include an adequate description of the programs and activities 

for managing the effects of aging for the period of extended operation related to operation of the 

cathodic protection system. The staff’s concern described in RAI B2.1.25-3 is resolved.

The FSAR supplement for the Buried and Underground Piping and Tanks Program is consistent 

with the corresponding program description in SRP-LR Table 3.0-1. 

The staff also noted that the applicant committed (Commitment No. 20) to implement the new 

Buried and Underground Piping and Tanks Program within the 10-year period and no later than 

six months before entering the period of extended operation for managing aging of applicable 

components.

The staff finds that the information in the FSAR supplement, as amended by letter dated 

August 6, 2012, January 24, 2013, and February 28, 2013, is an adequate summary description 

of the program.

Conclusion. On the basis of its audit and review of the applicant’s Buried and Underground 

Piping and Tanks Program, the staff determines that the program elements for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M41, as modified by LR-ISG-2011-03. In addition, 

the staff reviewed the exceptions, including the basis for the removal of the exceptions, and 

determines that the AMP is adequate to manage the applicable aging effects. The staff also 

reviewed the amended FSAR supplement for this AMP and concludes that it provides an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.15 ASME Section XI, Subsection IWE 

Summary of Technical Information in the Application. LRA Section B2.1.26 describes the 

existing ASME Section XI, Subsection IWE Program as consistent, with enhancements, with 

GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE.”

The LRA states that the ASME Section XI, Subsection IWE Program addresses the carbon steel 

containment liner plate and its integral attachments, containment hatches and airlocks, and 

pressure-retaining bolting exposed to plant indoor air to manage the effects of cracking, loss of 

material, loss of sealing, loss of preload, and loss of leak tightness through surface and 

volumetric examinations. The LRA states that the primary inspection method is a general visual 

examination (VT-1 and VT-3), and ultrasonic thickness measurements are performed, as 

required. The LRA also states that the IWE containment ISIs satisfy the requirements of the 

2001 Edition of ASME Code Section XI (through the 2003 addenda), supplemented with the 

applicable requirements of 10 CFR 50.55a(b)(2)(ix). The LRA further states that the ASME 

Code edition, consistent with the provisions of 10 CFR 50.55a, will be used during the period of 

extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S1. For the “parameters 
AGING MANAGEMENT REVIEW RESULTS

3-190

monitored or inspected” program element, the staff determined the need for additional

information, which resulted in the issuance of an RAI as discussed below. 

The “parameters monitored or inspected” program element in GALL Report AMP XI.S1 

recommends the examination of moisture barriers for wear, damage, erosion, tear, surface 

cracks, or other defects that permit intrusion of moisture in the inaccessible areas of the 

pressure-retaining surfaces of the metal containment shell or liner. Furthermore, ASME Code 

Section XI, Subsection IWE, Table-2500-1 “Examination Category E-A” requires 100 percent 

general visual examinations of moisture barriers (E1.30) during each examination period. 

However, during its audit, the staff found that the applicant’s ASME Section XI, Subsection IWE 

Program did not include inspection of moisture barriers as part of the IWE program. In addition, 

during the audit, the staff did not find any reference to the moisture barriers in the IWE periodic 

examination inspection reports. By letter dated July 9, 2012, the staff issued RAI B2.1.26-1 

requesting the applicant to confirm if moisture barriers, as shown in Figure IWE-2500-1 of the 

ASME Code Section XI, Subsection IWE, are installed in the Callaway containment, and if 

moisture barriers have been installed, provide justification for not including the examinations of 

“moisture barriers” during each examination period.

In its response dated August 9, 2012, the applicant stated that “the Callaway Plant does not 

have a moisture barrier seal at the interface between the steel containment liner and the internal 

concrete structures. A fill slab is installed directly over the horizontal liner plate on the floor and 

directly against the vertical liner plate on the wall.” As part of its response, the applicant revised 

the LRA (LRA Amendment 6) to delete reference to moisture barriers in the scope of the IWE 

inspections. 

On August 23, 2012, the staff held a telephone conference call with the applicant to discuss its

response to RAI B2.1.26-1. During the call, the applicant stated that based on the search of 

plant records, it was not able to find any documentation that could identify the existence of 

moisture barrier seals. Furthermore, NRC regional staff also verified drawings and photographs 

in the applicant’s CAR 200403564 response to NRC IN 2004-09 and confirmed that Callaway 

does not have a moisture barrier seal. Therefore, the staff concluded that Callaway does not 

have a moisture barrier seal at the interface between the steel containment liner and the internal 

concrete structures. 

The staff finds the applicant’s response acceptable because the NRC regional staff confirmed 

the applicant’s claim of absence of moisture barrier seals at the interface between the steel 

containment liner and the internal concrete structures and, therefore, the applicant’s AMP is 

consistent with GALL Report AMP XI.S1 acceptance criteria. The staff’s concern described in 

RAI B2.1.26-1 is resolved.

The staff also reviewed the portions of the “preventive actions” and “detection of aging effects” 

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 B2.1.26 states an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that the procedures will be 

enhanced before the period of extended operation to specify that whenever replacement of

bolting is required, bolting material, installation torque or tension, and use of lubricants and 

sealants are in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the 

additional recommendations of NUREG-1339. The staff reviewed this enhancement against the 

corresponding program element in the GALL Report AMP XI.S1 and finds it acceptable because 
AGING MANAGEMENT REVIEW RESULTS

3-191

when it is implemented it will prevent or mitigate degradation and failure of bolting and will make 

the ASME Section XI, Subsection IWE Program consistent with the recommendations identified 

in the GALL Report AMP.

Enhancement 2. The LRA Section B2.1.26 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the procedures will be 

enhanced to perform additional surface examinations of stainless steel penetration sleeves, 

dissimilar metal welds, bellows, and steel components subject to cyclic loading for cracking, 

unless Appendix J testing is adequate to identify cracking. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.S1 and finds it acceptable 

because, when it is implemented, it will make the ASME Section XI, Subsection IWE Program 

consistent with the recommendations identified in the GALL Report AMP.

Based on its audit of the applicant’s ASME Section XI, Subsection IWE Program and review of 

the applicant’s response to RAI B2.1.26-1, the staff finds that program elements one through six 

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S1. In addition, the staff reviewed 

the enhancements associated with the “preventive actions” and “detection of aging effects” 

program elements and finds that when implemented, they will make the AMP adequate to 

manage the applicable aging effects.

Operating Experience. LRA Section B2.1.26 summarizes operating experience related to the 

ASME Code Section XI, Subsection IWE Program. The LRA states that “[e]xams are conducted 

every other [RFO] to meet the frequency requirements of once per period of 3-1/3 years.” The 

LRA states that a weld defect was identified in normal sump B that required an augmented 

examination during the next inspection period. The LRA states that the results of this evaluation 

were documented in Callaway’s CAP. The LRA also states that the augmented examinations 

were completed in the first period of the second interval, and the weld defect was repaired. The 

LRA further states that based on a review of 10 years of Callaway operating experience, no 

significant degradation or corrosion of the components of the containment liner have been 

identified. However, in 2002, along the circumference of the containment building liner plate, 

five minor randomly spaced surface corrosion areas were identified, and repairs of these areas 

were completed. In addition the LRA states that these examples provide objective evidence 

that the ASME Section XI, Subsection IWE Program is capable of both monitoring and detecting 

the aging effects associated with the program, and that there is confidence that the continued 

implementation of the program will effectively identify aging before loss of intended function of 

the containment building liner plate.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 
AGING MANAGEMENT REVIEW RESULTS

3-192

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.S1 was evaluated.

FSAR Supplement. LRA Section A1.26 provides the FSAR supplement for the ASME 

Section XI, Subsection IWE Program. The staff reviewed this FSAR supplement description of 

the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 21) to 

enhance the existing ASME Section XI, Subsection IWE Program six months before the period 

of extended operation for managing aging of applicable components during the period of 

extended operation. The staff finds that the information in the FSAR supplement, as amended 

by letter dated February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI, 

Subsection IWE Program, the staff determines that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the 

enhancements and confirmed that their implementation through Commitment No. 21, six 

months before the period of extended operation, will make the AMP adequate to manage the 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for this AMP and concluded 

that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2.16 ASME Section XI, Subsection IWF 

Summary of Technical Information in the Application. LRA Section B2.1.28 describes the 

existing ASME Section XI, Subsection IWF Program as consistent, with enhancements, with 

GALL Report AMP XI.S3, “ASME Section XI, Subsection IWF.” The LRA states that the ASME 

Section XI, Subsection IWF Program addresses supports for Class 1, 2, and 3 piping and 

components. The LRA also states that supports are selected and examined in accordance with 

the requirements of ASME Code Section XI, Subsection IWF. The LRA further states that the 

primary inspection method is periodic visual examination.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S3.

For the “preventive actions,” and “detection of aging effects” program elements, the staff 

determined the need for additional information, which resulted in the issuance of RAIs, as 

discussed below.

The “preventive actions” program element in GALL Report AMP XI.S3 recommends refraining 

from using molybdenum disulfide and other lubricants containing sulfur for high-strength bolting 

applications. The “detection of aging effects” program element in GALL Report AMP XI.S3 

recommends volumetric examination for high-strength structural bolting (actual measured yield 

strength greater than or equal to 150 ksi or 1,034 MPa) in sizes greater than 1-inch nominal 

diameter. However, during its audit, the staff found that the applicant’s ASME Section XI, 

Subsection IWF Program does not clearly state that molybdenum disulfide and other lubricants 

containing sulfur have not been used in the past. The applicant’s program also does not 

discuss the number of high-strength bolts within the scope of the program or how the bolts will 

be selected for volumetric inspection. Therefore, by letter dated July 9, 2012, the staff issued 
AGING MANAGEMENT REVIEW RESULTS

3-193

RAI B2.1.28-1 requesting that the applicant explain how many high-strength bolts are within the 

scope of the ASME Section XI, Subsection IWF Program and how bolts will be selected for 

volumetric inspection. The staff also requested the applicant to provide the plant-specific 

operating experience regarding lubricants containing sulfur and how these lubricants would be 

addressed during the period of extended operation.

In its response dated August 9, 2012, the applicant stated that a review of plant documentation, 

including drawings, specifications, procurement documents, and keyword database searches, 

did not identify any structural bolts greater than 1-inch diameter with a specified minimum yield 

strength greater than or equal to 150 ksi. Based on this review, the applicant concluded that 

there are no structural bolts within the scope of license renewal for which augmented volumetric 

examinations are necessary. The applicant further stated that molybdenum disulfide is 

excluded from the list of acceptable lubricants in plant procedures.

The staff finds the applicant’s response acceptable because the applicant clearly stated that no 

high-strength structural bolts in sizes greater than 1-inch nominal diameter are within the scope 

of license renewal. The applicant also stated that molybdenum disulfide is not an acceptable 

lubricant per plant procedures. Therefore, stress-corrosion cracking of high strength structural 

bolts is not a concern, and the additional recommendations in the GALL Report AMP for 

high-strength bolting are not applicable. The staff’s concern described in RAI B2.1.28-1 is 

resolved.

The “preventive actions” program element in GALL Report AMP XI.S3 recommends following 

the preventive actions discussed in Section 2 of the Research Council for Structural 

Connections, “Specification for Structural Joints Using ASTM A325 or A490 Bolts,” if 

ASTM A325, ASTM F1852, or ASTM A490 bolts are used within the scope of the program. 

However, during its audit, the staff found that the applicant’s ASME Section XI, Subsection IWF 

Program does not clearly state whether or not ASTM A325, ASTM F1852, or ASTM A490 bolts 

are used within the scope of the program. Therefore, by letter dated July 9, 2012, the staff 

issued RAI B2.1.28-2 requesting that the applicant clarify whether ASTM A325, ASTM F1852, 

or ASTM A490 bolts are used within the scope of the program, and if so explain how the 

recommended preventive actions will be addressed during the period of extended operation.

In its response dated August 9, 2012, the applicant stated that Commitment No. 22 and the 

enhancement associated with the “preventive actions” program element in LRA Section B2.1.28 

have been revised to include the preventive actions discussed in Section 2 of the Research 

Council for Structural Connections, “Specification for Structural Joints Using ASTM A325 or 

A490 Bolts,” if ASTM A325, ASTM F1852, or ASTM A490 structural bolts are used for 

replacement bolting during the period of extended operation.

The staff finds the applicant’s response acceptable because the applicant revised the LRA and 

committed (Commitment No. 22) to use the GALL Report recommended reference for 

preventive actions associated with ASTM A325, ASTM F1852, and ASTM A490 structural bolts. 

The staff’s concern described in RAI B2.1.28-2 is resolved.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” and “detection of aging effects” 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 B2.1.28 states an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that whenever replacement of 
AGING MANAGEMENT REVIEW RESULTS

3-194

bolting is required, bolting material, installation torque or tension, and use of lubricants and 

sealants will be in accordance with the applicable EPRI guidelines, ASTM standards, American 

Institute of Steel Construction (AISC) specifications, and NUREG recommendations to prevent 

or mitigate SCC. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S3 and finds it acceptable because, when it is implemented, it 

will align the applicant’s program with the recommended guidance provided in the GALL Report. 

Additional information regarding specific preventive actions taken for high-strength bolts is 

provided in the RAI discussions above. 

Enhancement 2. LRA Section B2.1.28 states an enhancement to the “parameters monitored or 

inspected,” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that high-strength bolting (actual measured yield strength greater than or equal 

to 150 ksi or 1,034 MPa) in sizes greater than 1-inch nominal diameter will receive a volumetric 

examination comparable to that of ASME Code Section XI, Table IWB-2500-1. In response to 

RAI B2.1.28-1, the applicant clarified that no high-strength structural bolting exists within the 

scope of license renewal; therefore, the applicant deleted this enhancement. The staff reviewed 

this change and found it acceptable because there are no high-strength structural bolts within 

the scope of license renewal. Additional information on this issue is provided in the 

RAI discussions above. 

Based on its audit of the applicant’s ASME Section XI, Subsection IWF Program and review of 

the applicant’s responses to RAIs B2.1.28-1 and B2.1.28-2, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.S3. In addition, 

the staff reviewed the enhancements associated with the “preventive actions” program element 

and finds that when implemented it will make the AMP adequate to manage the applicable 

aging effects.

Operating Experience. LRA Section B2.1.28 summarizes operating experience related to the 

ASME Section XI, Subsection IWF Program. The LRA states that a review of the owner activity 

reports since 2000 indicates there have been no conditions found through IWF inspections that 

required repair, replacement, or engineering evaluation. The LRA further states that 

100 percent of the supports required per category F-A were inspected during the past inspection 

interval, and no signs of aging were found.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff identified operating experience for which it determined the need for 

additional clarification and resulted in the issuance of an RAI, as discussed below.

ASME Code Section XI, Subsection IWF states, that to the extent practical, the same supports 

selected for examination during the first inspection interval shall be examined during each 

successive inspection interval. Recent industry operating experience has revealed situations 

where supports within the IWF sample were degraded, but did not meet the ASME Code 

threshold for repair. The supports were reworked to as-new condition and remained in the IWF 

sample. If ASME Code Section XI, Subsection IWF supports that are part of the inspection 

sample are reworked to as-new condition, they are no longer representative of the other 
AGING MANAGEMENT REVIEW RESULTS

3-195

supports in the population in regard to age-related degradation. Subsequent ASME Code

Section XI, Subsection IWF inspections of the same sample would not represent the age-related 

degradation of the rest of the population. The LRA and the associated basis documents 

provided no discussion of how this issue would be addressed, or how the IWF sample would be 

altered if a support within the original sample was reworked. Therefore, by letter dated 

July 9, 2012, the staff issued RAI B2.1.28-3 requesting the applicant explain how the ASME 

Section XI, Subsection IWF Program would address a situation where supports in the sample 

population are reworked or replaced even though they do not necessarily require corrective 

actions per the ASME Code Section XI, Subsection IWF acceptance criteria.

In its response dated August 9, 2012, the applicant stated that the ASME Code Section XI, 

Subsection IWF Program has not reworked or replaced any supports in the sample population 

unless corrective actions were required per ASME Code Section XI, Subsection IWF 

acceptance criteria. The applicant further stated that if supports are reworked or replaced they 

are not included in subsequent sample selections. 

The staff finds the applicant’s response acceptable because the applicant stated that supports 

that have been reworked in the past are not included in the inspection sample population, and 

any supports that are reworked or replaced in the future will be removed from the subsequent 

inspection population. Removing reworked or replaced supports from future inspection samples 

addresses the staff’s concern that the supports may no longer be representative of the general 

population. The staff’s concern described in RAI B2.1.28-3 is resolved.

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

RAI B2.1.28-3, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience, and that implementation of the program has resulted in the 

applicant taking corrective action. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.S3 was 

evaluated. 

FSAR Supplement. LRA Section A1.28 provides the FSAR supplement for the ASME 

Section XI, Subsection IWF Program. The staff reviewed this FSAR supplement description of 

the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 22) to 

implement the associated enhancements of the existing ASME Section XI, Subsection IWF

Program six months before the period of extended operation for managing aging of applicable 

components during the period of extended operation. The staff finds that the information in the 

FSAR supplement, as amended by letters dated August 9, 2012, and February 28, 2013, is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s ASME Section XI, 

Subsection IWF Program, 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. 22 six months 

before the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. The staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR 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

3-196

3.0.3.2.17 Structures Monitoring

Summary of Technical Information in the Application. LRA Section B2.1.31 as amended by 

letters dated August 9, 2012, and October 11, 2012, describes the existing Structures 

Monitoring Program as consistent, with enhancements, with GALL Report AMP XI.S6, 

“Structures Monitoring.” The LRA states that the Structures Monitoring Program implements the 

requirements of 10 CFR 50.65, “Requirements for Monitoring the Effectiveness of Maintenance 

at Nuclear Power Plants,” consistent with guidance of NUMARC 93-01, Revision 2, “Industry 

Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” and 

RG 1.160, Revision 2, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants”. 

The LRA states that the Structures Monitoring Program monitors the condition of structures and 

structural supports that are within the scope of license renewal to manage the following aging 

effects:

• concrete cracking and spalling

• cracking

• cracking and distortion

• cracking, blistering, change in color

• cracking, loss of material

• cracking, loss of bond, and loss of material (spalling, scaling)

• increase in porosity and permeability, cracking, loss of material (spalling, scaling)

• increase in porosity and permeability, loss of strength

• loss of material

• loss of material (spalling, scaling) and cracking

• loss of mechanical function

• loss of preload

• loss of sealing

• reduction in concrete anchor capacity

The LRA also states that Callaway is committed to RG 1.127, “Inspection of Water-Control 

Structures Associated with Nuclear Power Plants,” and the scope of the Structures Monitoring 

Program includes water-control structures and masonry walls. The LRA, as amended by letter 

dated August 9, 2012, clarifies that the inspections of all structural components, including 

masonry walls and water-control structures, are performed at intervals of no more than 5 years. 

The LRA further states that Callaway does not take credit for any coatings to manage the aging 

of structural components, and that coating degradation is used only as an indicator of the 

condition of underlying material.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S6.

For the “scope of program,” “parameters monitored or inspected,” “detection of aging effects,” 

and “acceptance criteria” program elements, the staff determined the need for additional 

information, which resulted in the issuance of RAIs, as discussed below.

The “scope of program” program element in GALL Report AMP XI.S6 recommends inspection 

of all structures, structural components, component supports, and structural commodities within 

the scope of license renewal that are not covered by other structural AMPs. Examples of 

structures, structural components, and commodities in the scope of the program are: 
AGING MANAGEMENT REVIEW RESULTS

3-197

• concrete and steel structures

• structural bolting

• anchor bolts and embedments

• component support members

• pipe whip restraints and jet impingement shields

• transmission towers

• panels and other enclosures

• racks, sliding surfaces

• sump and pool liners 

• electrical cable trays and conduits

• trash racks associated with water control structures

• electrical duct banks

• manholes, doors, penetration seals, and tube racks 

However, during its audit, the staff found that the applicant’s Structures Monitoring Program has 

excluded penetrations, pipe and raceway supports, cable trays, anchor bolts, transmission 

towers, electrical conduits, and the UHS retention pond from the scope of the existing AMP. 

The staff notes that the applicant has committed to enhance the procedures to specify 

inspections of penetrations, transmission towers, electrical conduits, raceways (equivalent to 

pipe and raceway supports), cable trays, electrical cabinets and enclosures, and associated 

anchorages. However, to date, none of these structures have been inspected and the applicant 

has no plans to inspect them until the period of extended operation. Baseline inspection and 

trending of degradation in the excluded structures before the period of extended operation is 

necessary for appropriate aging management. By letter dated July 9, 2012, the staff issued 

RAI B2.1.31-5 requesting the applicant to provide a summary description of plans and a 

schedule for baseline inspection and trending of degradation of the structures excluded by the 

existing program, but which are included as an enhancement to the Structures Monitoring 

Program for the period of extended operation. The staff also requested the applicant to provide 

the technical basis for not including these structures in the baseline inspection as part of the 

Structures Monitoring Program.

In its response dated August 9, 2012, the applicant stated that:

...baseline inspections of penetrations, transmission towers, electrical conduits, 

raceways, cable trays, electrical cabinets/enclosures, and associated 

anchorages will be completed by December 31, 2017. These baseline 

inspections will be performed as part of the Structures Monitoring [P]rogram, 

which has been enhanced to add these components to its scope. Previously, 

these components were considered to be part of their respective mechanical or 

electrical systems. Beginning with these baseline inspections and continuing 

through the period of extended operation, these components will be within the 

scope of the Structures Monitoring [P]rogram for all inspections, monitoring, and 

trending that may be required. The [UHS] retention pond is already within the 

scope of the Structures Monitoring [P]rogram and will continue to be so.

The staff finds the applicant’s response acceptable because the applicant has committed 

(Commitment No. 23) to complete the baseline inspection of these components by 

December 31, 2017. A baseline inspection of these components, before the period of extended 

operation, will provide for adequate monitoring and trending, which is necessary to demonstrate 
AGING MANAGEMENT REVIEW RESULTS

3-198

that the components will be age managed through the period of extended operation. The staff’s 

concern described in RAI B2.1.31-5 is resolved.

The “parameters monitored or inspected” program element in GALL Report AMP XI.S6 

recommends inspection of all structures on a frequency not to exceed 5 years. However, during 

its audit, the staff found that although the applicant’s Structures Monitoring Program basis 

document states that inspections are performed at intervals of not more than 5 years, no 

discussion of the inspection interval is provided in the LRA or the FSAR supplement program 

summary. The inspection frequency needs to be captured in the FSAR supplement to provide 

the staff reasonable assurance that the programs will be properly implemented during the period 

of extended operation. By letter dated July 9, 2012, the staff issued RAI B2.1.31-1 requesting 

that the applicant include a statement of the inspection interval in the FSAR supplement for the 

Structures Monitoring, Masonry Wall, and RG 1.127 Inspection of Water-Control Structures 

Associated with Nuclear Power Plants programs.

In its response dated August 9, 2012, the applicant stated that the FSAR supplements of the 

Structures Monitoring, Masonry Wall, and RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants programs have been revised to specify that inspections 

of all structural components, including masonry walls and water-control structures, are 

performed at intervals of no more than 5 years.

The staff finds the applicant’s response acceptable because the FSAR supplements for the 

Structures Monitoring, Masonry Wall, and RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants programs have been revised to specify that inspections 

of all structural components, including masonry walls and water-control structures, are 

performed at intervals of no more than 5 years, which is consistent with the inspection 

frequency recommended in GALL Report AMPs XI.S5, XI.S6, and XI.S7. The staff’s concern 

described in RAI B2.1.31-1 is resolved.

The “parameters monitored or inspected” and “detection of aging effects” program elements in 

GALL Report AMP XI.S6 state that ACI 349.3R and ANSI/American Society of Civil Engineers 

(ASCE) 11 provide an acceptable basis for selection of parameters to be monitored or inspected 

for concrete and steel structural elements and that qualifications of inspection and evaluation 

personnel specified in ACI 349.3R are acceptable for license renewal. However, during its 

audit, the staff found that the applicant’s Structures Monitoring Program basis documents 

indicate that the inspection methods, including walkdown examination guidance, and 

qualification requirements for inspectors are not consistent with ACI 349.3R. Callaway 

procedure ESP-ZZ-01013, Section 4.0, states that an assigned engineer from the civil/structural 

design group will perform the engineering responsibilities for the Maintenance Rule Structures 

Inspection Program. The assigned engineer will possess the experience and skills in 

civil/structural engineering, consistent with the requirements of the current civil/structural 

position guide and engineering qualification module. This is inconsistent with the requirements 

specified in ACI 349.3R, which states that the responsible-in-charge engineer should be a 

licensed professional engineer, knowledgeable in the design, evaluation, and ISI of concrete 

structures and performance requirements of nuclear safety-related structures; or structural 

engineering graduate of an Accreditation Board for Engineering and Technology, Inc., 

accredited college or university with at least 10 years’ experience in the design, construction, 

and inspection of concrete structures, and with knowledge of the performance requirements of 

nuclear safety-related structures and potential degradation processes. In addition, ACI 349.3R 

recommends a three-tier quantitative evaluation criteria for inspection of structures; however, 

the walkdown guidelines in Callaway procedure ESP-ZZ-01013 require inspection based on a 
AGING MANAGEMENT REVIEW RESULTS

3-199

qualitative acceptance criteria. By letter dated July 9, 2012, the staff issued RAI B2.1.31-2 

requesting that the applicant explain the reason for inconsistency in inspection methods and 

inspector qualifications as described in LRA Section B2.1.31 and implementing procedure 

ESP-ZZ-01013.

In its response dated August 9, 2012, as supplemented by letter dated October 11, 2012, the 

applicant stated that “LRA Table A4-1 Item 23, documents the plant commitment to enhance the 

Structures Monitoring Program procedures to specify inspector qualifications in accordance with 

ACI 349.3R-96.” The applicant further stated that LRA Section B2.1.31 and LRA Table A4-1 

Commitment No. 23 have been revised to enhance the Structures Monitoring Program 

procedures to specify that acceptance criteria and critical parameters for monitoring degradation 

and guidance for identifying unacceptable conditions requiring further technical evaluation or 

corrective action are in accordance with the three-tier quantitative evaluation criteria 

recommended in ACI 349.3R.

The staff finds the applicant’s response acceptable because the applicant has committed 

(Commitment No. 23) to enhance the program to specify inspector qualification in accordance 

with ACI 349.3R and, by letter dated October 11, 2012, the applicant revised the LRA and 

Commitment No. 23 to clarify that the Structures Monitoring Program procedures will be 

enhanced to specify that acceptance criteria and critical parameters for monitoring degradation 

and guidance for identifying unacceptable conditions requiring further technical evaluation or 

corrective action are in accordance with the three-tier quantitative evaluation criteria 

recommended in ACI 349.3R. The staff’s concern described in RAI B2.1.31-2 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.S6 recommends 

periodic sampling and testing of groundwater and assessing the impact of any changes in its 

chemistry on below-grade concrete structures. For plants with non-aggressive groundwater/soil 

(pH greater than 5.5, chlorides less than 500 ppm, or sulfates less than 1,500 ppm), the 

program recommends: (a) evaluating the acceptability of inaccessible areas when conditions 

exist in accessible areas that could indicate the presence of, or result in, degradation to such 

inaccessible areas and (b) examining representative samples of the exposed portions of the 

below-grade concrete, when excavated for any reason. The GALL Report also recommends 

that for plants with aggressive groundwater/soil (pH less than 5.5, chlorides greater than 

500 ppm, or sulfates greater than 1,500 ppm) or where the concrete structural elements have 

experienced degradation, a plant-specific AMP accounting for the extent of the degradation 

experienced should be implemented to manage the concrete aging during the period of 

extended operation. However, during its audit, the staff found that the applicant’s Structures 

Monitoring Program has identified two wells that have shown seasonal increases in chloride 

levels of up to 680 mg/L while the pH and sulfate concentrations have remained 

non-aggressive. The LRA states that the aplicant will continue to monitor the results from the 

groundwater samples and will perform an engineering evaluation to determine if any adverse 

aging effects have occurred in any inaccessible concrete structural elements. The LRA does 

not provide any details on how the aging of the inaccessible concrete elements will be managed 

during the period of extended operation because of the presence of high chloride 

concentrations. By letter dated July 9, 2012, the staff issued RAI B2.1.31-6 requesting that the 

applicant provide historical results, including season variations, for groundwater chemistry, and 

provide details on how the aging of the inaccessible concrete elements will be managed during 

the period of extended operation because of the presence of high chloride concentrations.

In its response dated August 9, 2012, the applicant stated that:
AGING MANAGEMENT REVIEW RESULTS

3-200

[b]eginning in November 2009, 24 monthly groundwater samples were taken 

from 11 sampling wells around the Callaway site. Sulfates and pH levels were 

well within acceptable limits with no significant seasonal variations. Samples 

taken from one well in August and September of 2010 showed chloride levels of 

520 ppm and 570 ppm. In March and April of 2011, samples taken from a 

different well had chloride levels of 660 ppm and 610 ppm. All other samples 

showed chloride to be below the 500 ppm threshold for classifying groundwater 

as aggressive.

The applicant also stated that an engineering evaluation was performed to assess the impact, if 

any, on existing below-grade structures because of the elevated levels of chloride that have 

been detected in the groundwater monitoring wells, concluding that there is no indication that 

Callaway has concrete or reinforcing steel degradation resulting from aggressive groundwater. 

The applicant further stated that:

Callaway will continue to monitor groundwater for pH, chlorides, and sulfates 

every [5] years through the period of extended operation, and the results will be 

evaluated by engineering to assess the impact, if any, on below-grade structures. 

The Structures Monitoring [P]rogram monitors the plant structures with scheduled 

visual examination of the accessible structures and opportunistic examination of 

inaccessible structures. These examinations will continue through the period of 

extended operation to confirm the absence of concrete degradation due to 

aggressive groundwater.

The staff finds the applicant’s response acceptable because although the increased chloride 

levels have since returned within the limits for classifying the environment as non-aggressive, 

the applicant conducted an engineering evaluation and concluded that there was no indication 

of concrete or reinforcing steel degradation resulting from aggressive groundwater. Additionally, 

the applicant stated that opportunistic inspections of inaccessible areas are performed and that 

pH, chlorides and sulfates will continue to be monitored every 5 years through the period of 

extended operation, which is consistent with the GALL Report recommendations. Therefore, 

the staff’s concern described in RAI B2.1.31-6 is resolved.

The “acceptance criteria” program element in GALL Report AMP XI.S6 recommends that the 

acceptance criteria be derived from design codes and standards that include ACI 349.3R, 

ACI 318, ANSI/ASCE 11, or the relevant AISC specifications as applicable, and consider 

industry and plant operating experience. The criteria are directed at the identification and 

evaluation of degradation that may affect the ability of the structure or component to perform its 

intended function. Applicants that are not committed to ACI 349.3R and elect to use 

plant-specific criteria for concrete structures should describe the criteria and provide a technical 

basis for deviations from those in ACI 349.3R. However, during its audit, the staff found that the 

applicant’s Structures Monitoring Program basis document states that the Callaway Structures 

Monitoring Program provides guidance for the determination of performance criteria for SSCs 

included within the scope of the Maintenance Rule. These guidelines were used to establish 

the inspection attributes for SSCs. Callaway’s Structures Monitoring Program uses 

“Acceptable,” “Acceptable with Deficiencies,” and “Unacceptable” to classify levels of aging 

effects for each inspection attribute. The staff also notes that the applicant has committed 

(Commitment No. 23) to enhance the Structures Monitoring Program to quantify acceptable 

criteria and critical parameters for monitoring degradation. As part of its enhancement to the 

AMP, the applicant has also committed (Commitment No. 23) to incorporate in its procedures 

applicable industry codes, standards, and guidelines for acceptance criteria. The staff was not 
AGING MANAGEMENT REVIEW RESULTS

3-201

clear what industry standard the acceptance criteria was based on, nor was the acceptance 

criteria consistent with ACI 349.3R. By letter dated July 9, 2012, the staff issued RAI B2.1.31-3 

requesting that the applicant provide the basis for the acceptance criteria described in 

Appendix D of procedure ESP-ZZ-01013. The staff also requested the applicant to explain the 

inconsistency between the Structures Monitoring Program acceptance criteria of “Acceptable,” 

“Acceptable with Deficiencies,” and “Unacceptable,” as identified in procedure ESP-ZZ-01013

Section 7.5 and the quantitative acceptance criteria described in ESP-ZZ-01013, Appendix D.

In its response dated August 9, 2012, the applicant stated the following:

[t]he acceptance criteria for the Structures Monitoring [P]rogram are based on 

those provided in ACI 349.3R. For inspection of components and materials that 

are not specifically addressed in ACI 349.3R, the acceptance criteria are 

modified as necessary to account for the nature of the component being 

inspected. The markup of the [s]tructures [m]onitoring procedure has been 

revised to align with the criteria of ACI 349.3R and to clarify the definitions of the 

[a]cceptance [c]riteria categories so that they also align with ACI 349.3R.

In addition, in a letter dated October 11, 2012, the applicant revised LRA Table A4-1, 

Commitment No. 23, to clarify that the acceptance criteria will be revised to be in accordance 

with the three-tier quantitative evaluation criteria recommended in ACI 349.3R. The staff finds 

the applicant’s response acceptable because the applicant committed (Commitment No. 23) to 

revise the structures monitoring procedure to align with the criteria of ACI 349.3R. Therefore, 

the staff’s concern described in RAI B2.1.31-3 is resolved. 

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of these enhancements 

follows.

Enhancement 1. LRA Section B2.1.31 states an enhancement to the “scope of program” 

program element. In this enhancement, as amended by letter dated May 6, 2014, the applicant 

stated that procedures will be enhanced to include the main access facility, the nitrogen storage 

tank foundation and pipe trench, and the reinforced concrete structures under the turbine 

building and in the yard (which provide a return flow path for the circulating water system), in the 

scope of Structures Monitoring Program. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S6 and finds it acceptable because 

when it is implemented it will make the program consistent with the GALL Report 

recommendations by including all structures within the scope of license renewal, not covered by 

other structural AMPs, in the scope of the program.

Enhancement 2. LRA Section B2.1.31 states an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that plant procedures will be 

enhanced to specify that guidelines of EPRI NP-5769, EPRI NP-5067, EPRI TR-104213, and 

the additional recommendations of NUREG-1339 will be used whenever replacement of bolting 

is required. The applicant also stated that plant procedures will be enhanced to specify the 

preventive actions for storage, lubricants, and SCC potential discussed in Section 2 of the 

Research Council for Structural Connections publication, “Specification for Structural Joints 

Using ASTM A325 or A490 Bolts,” for ASTM A325, ASTM F1852, and/or ASTM A490 structural 

bolts. The staff reviewed this enhancement against the corresponding program elements in 
AGING MANAGEMENT REVIEW RESULTS

3-202

GALL Report AMP XI.S6 and finds it acceptable because when it is implemented it will make 

the program consistent with the GALL Report recommendations.

Enhancement 3. LRA Section B2.1.31, as amended by letter dated August 9, 2012, states an 

enhancement to the “scope of program” and “parameters monitored or inspected” program 

elements. In this enhancement, the applicant stated that procedures will be enhanced to 

specify inspections of penetrations, transmission towers, electrical conduits, raceways, 

cabletrays, electrical cabinets and enclosures, and associated anchorages, and to complete a 

baseline inspection of these components before December 31, 2017. The applicant also stated 

that procedures will be enhanced to specify that groundwater is monitored for pH, chlorides, and 

sulfates; and every 5 years, at least two samples are tested and the results are evaluated by 

engineering to assess the impact, if any, on below-grade structures. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S6 and 

finds it acceptable because when it is implemented it will make the program consistent with the 

GALL Report recommendations for periodic sampling of groundwater chemistry (pH, chlorides, 

and sulfates) to assess its impact, if any, on below-grade concrete structures.

Enhancement 4. LRA Section B2.1.31 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that procedures will be 

enhanced to specify that structural bolts greater than 1-inch in diameter with actual measured 

yield strength greater than or equal to 150 ksi are evaluated for susceptibility to SCC, and if 

necessary, visual inspections are supplemented with volumetric or surface examinations. 

However, by letter dated August 9, 2012, in response to RAI B2.1.28-1, the applicant amended 

the LRA to delete this enhancement because it performed a review and concluded that there 

are no structural bolts within the scope of license renewal for which augmented volumetric 

examinations are required. The staff’s review of the applicant’s response to RAI B2.1.28-1 is 

documented in SER Section 3.0.3.2.16.

Enhancement 5. LRA Section B2.1.31 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that procedures will be 

enhanced to specify inspector qualification in accordance with ACI 349.3R-96. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.S6 and finds it acceptable because when it is implemented it will make the program 

consistent with the GALL Report recommendations for inspector qualifications.

Enhancement 6. LRA Section B2.1.31, as amended by letters dated August 9, 2012, and 

October 11, 2012, states an enhancement to the “acceptance criteria” program element. In this 

enhancement, the applicant stated that procedures will be enhanced to quantify acceptance 

criteria and critical parameters for monitoring degradation and to provide guidance for identifying 

unacceptable conditions requiring further technical evaluation or corrective action in accordance 

with the three-tier quantitative evaluation criteria recommended in ACI 349.3R. The applicant 

also stated that procedures will be enhanced to incorporate applicable industry codes, 

standards, and guidelines for acceptance criteria.

By letter dated August 9, 2012, in response to RAI B2.1.31-4, as discussed below, the applicant 

revised this enhancement to state that procedures will be enhanced to specify that degradation 

associated with seismic isolation gaps, obstructions of these gaps, or questionable material in 

these gaps, will be inspected and evaluated. By letter dated January 24, 2013, the applicant 

revised the LRA to indicate that initial inspections have been completed and any corrective 

actions resulting from these inspections will be completed no later than December 31, 2017. 

The staff reviewed this enhancement against the corresponding program elements in 
AGING MANAGEMENT REVIEW RESULTS

3-203

GALL Report AMP XI.S6 and finds it acceptable because the applicant has revised the 

Structures Monitoring Program to clarify that acceptance criteria will be in accordance with ACI 

349.3R, and when it is implemented, it will make the program consistent with the GALL Report 

recommendations for acceptance criteria. Additionally, the applicant has committed 

(Commitment No. 23) to complete corrective actions resulting from initial inspections no later 

than December 31, 2017.

Based on its audit of the applicant’s Structures Monitoring Program and review of the applicant’s 

responses to RAIs B2.1.31-1, B2.1.31-2, B2.1.31-3, B2.1.31-5, and B2.1.31-6, the staff finds 

that program elements one through six for which the applicant claimed consistency with the 

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

AMP XI.S6. In addition, the staff reviewed the enhancements associated with the “scope of 

program,” “preventive actions,” “parameters monitored or inspected,” “detection of aging 

effects,” and “acceptance criteria” program elements and finds that when implemented, they will 

make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.31 summarizes operating experience related to the 

Structures Monitoring Program. The LRA states that a 2002 structural inspection report of the 

fuel building identified an instance of cracking on the interior face of the exterior wall, with 

leachate observed coming through the crack; however, the leaking was not severe enough to 

warrant corrective action. The LRA states that inspections in 2010 did not identify any further 

cracking or leaking of leachate in this area.

The LRA also states that the applicant performs continuous monitoring of the spent fuel pool 

liner leak chase channels. The observed leakage has been small, remained steady, and does 

not challenge makeup capability. The exterior spent fuel pool walls show no evidence of 

external leakage, thus indicating that the leakage is contained within the leak chase channels.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI, as 

discussed below.

The GALL Report recommends that the Structures Monitoring Program operating experience, 

including past corrective actions resulting in program enhancements or additional programs, 

should provide objective evidence to support a determination that the effects of aging will be 

adequately managed so that the structure and component-intended functions will be maintained 

during the period of extended operation. During the audit, the staff reviewed operating 

experience and performed plant walkdowns. During the audit, the staff observed that 

elastomers in the seismic gaps of the containment, turbine and auxiliary buildings have been 

degraded and are not functional. The applicant identified this condition in 2006 and has caused 

in-leakage of ground and rain water into the buildings. In addition, the staff observed that in one 

area in the auxiliary building, the elastomer has been replaced with a foreign material. Lack of 

flexible elastomer gap can cause seismic interaction between the buildings, resulting in stresses 

not considered in the design that may affect the structural integrity of the structures during the 

period of extended operation. By letter dated July 9, 2012, the staff issued RAI B2.1.31-4 
AGING MANAGEMENT REVIEW RESULTS

3-204

requesting that the applicant provide a summary of the plans and its schedule to replace the 

nonfunctional elastomers located in seismic gaps.

In its response dated August 9, 2012, the applicant stated that:

[s]eismic isolation gaps at the roof, base slab, and exterior walls are constructed 

with waterstops embedded in the concrete. The elastomeric compressible 

material that is visible at the edge of the joint is a separate component from the 

waterstops. FSAR-SP Figure 3.8-85 shows typical isolation joint details. The 

intended function of the seismic isolation gap compressible material is to shelter

and protect the gap from debris intrusion so that seismic isolation is maintained.

The applicant also stated that:

[i]nspections for all accessible seismic gaps between buildings will be performed 

before December 31, 2012. An engineer familiar with the seismic design of the 

plant will evaluate the results of these inspections. Any corrective actions 

resulting from these inspections will be completed no later than 

December 31, 2017.

The staff finds the applicant’s response acceptable because, by letter dated January 24, 2013, 

the applicant revised the LRA to indicate that the initial inspections have been completed and 

the applicant has committed (Commitment No. 23) to take any corrective actions necessary by 

December 31, 2017. Inspection of these gaps, removal of foreign material, and corrective 

action taken to ensure the gaps remain free of foreign material will ensure that seismic isolation 

of the buildings is maintained. The staff’s concern described in RAI B2.1.31-4 is resolved.

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

RAI B2.1.31-4, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. Operating experience related to the applicant’s program 

demonstrates that it can adequately manage the effects of aging on SSCs within the scope of 

the program and that implementation of the program has resulted in the applicant taking 

corrective actions.

FSAR Supplement. LRA Section A1.31 provides the FSAR supplement for the Structures 

Monitoring Program. The staff reviewed this FSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 23) to enhance the Structures 

Monitoring Program procedures six months before the period of extended operation for 

managing aging of applicable components during the period of extended operation. The staff 

finds that the information in the FSAR supplement, as amended by letters dated August 9, 2012, 

October 11, 2012, and February 28, 2013, is an adequate summary description of the program.

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. Also, the staff reviewed the enhancements 

and confirmed that their implementation through Commitment No. 23 six months before the 

period of extended operation will make the AMP adequate to manage the applicable aging 

effects. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 
AGING MANAGEMENT REVIEW RESULTS

3-205

reviewed the FSAR 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 Protective Coating Monitoring and Maintenance Program

Summary of Technical Information in the Application. LRA Section B2.1.33 describes the 

existing Protective Coating Monitoring and Maintenance Program as consistent, with an 

exception and enhancements, with GALL Report AMP XI.S8, “Protective Coating Monitoring 

and Maintenance Program.” The LRA states the program manages “loss of coating integrity for 

Service Level I coatings inside containment so that the intended functions of post-accident 

safety systems that rely on water recycled through the containment sump/drain system are 

maintained consistent with the [CLB].” The LRA states that the program includes visual 

examination of accessible Service Level I coatings inside containment, including those applied 

to the steel containment liner, structural steel, supports, penetrations, concrete walls and floors.

The LRA states that general visual inspections of the containment building Service Level I 

coatings are conducted once each fuel cycle. The LRA also states that characterization of 

deficient areas is performed to allow evaluation of the deficiency for future surveillance or repair, 

and prioritization of repairs. The LRA further states that characterization of blistering, cracking, 

flaking, peeling, delamination, and rusting is consistent with ASTM D 5163-08, “Standard Guide 

for Establishing a Program for Condition Assessment of Coating Service Level I Coating 

Systems in Nuclear Power Plants.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S8.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” “acceptance criteria,” and 

“corrective actions” 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 B2.1.33 states an exception to the “scope of program” program 

element. In this exception the applicant stated that it will not be committing to all of the 

requirements noted in RG 1.54, Revision 2, “Service Level I, II, and III Protective Coatings 

Applied to Nuclear Power Plants.” RG 1.54 covers Service Level I, II, and III coatings, whereas 

GALL Report AMP XI.S8 is applicable to Service Level I coating. The applicant is committed to 

RG 1.54 in as much as it addresses Service Level I coating. The staff reviewed this exception 

against the corresponding program element in GALL Report AMP XI.S8 and finds it acceptable 

because the program is committed to those requirements in RG 1.54 regarding Service Level I 

coatings inside containment. 

Enhancement 1. LRA Section B2.1.33 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that procedures will be 

enhanced to specify parameters monitored or inspected to include any visible defects, such as 

blistering, cracking, flaking, peeling, rusting, or physical damage. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.S8 and finds 

it acceptable because when it is implemented it will make the program consistent with the 

recommendations in GALL Report AMP XI.S8.
AGING MANAGEMENT REVIEW RESULTS

3-206

Enhancement 2. LRA Section B2.1.33 states an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the procedures will be 

enhanced to specify inspection frequencies, personnel qualifications, inspection plans, 

inspection methods, and inspection equipment that meet the requirements of ASTM D 5163-08. 

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.S8 and finds it acceptable because when it is implemented it will make 

the program consistent with the recommendations in GALL Report AMP XI.S8.

Enhancement 3. LRA Section B2.1.33 states an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that the procedures will be 

enhanced to specify a pre-inspection review of the previous two monitoring reports and, based 

on inspection results, prioritize repair areas as either needing repair during the same outage or 

as postponed to future outages, but under surveillance in the interim period. The staff reviewed 

this enhancement against the corresponding program element in GALL Report AMP XI.S8 and 

finds it acceptable because when it is implemented it will make the program consistent with the 

recommendations in GALL Report AMP XI.S8.

Enhancement 4. LRA Section B2.1.33 states an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that the procedures will be 

enhanced to specify characterization, documentation, and testing consistent with 

ASTM D 5163-08 Sections 10.2 through 10.4 and to specify an evaluation of the inspection 

reports by the responsible coating evaluation specialist who prepares a summary of findings 

and recommendations for future surveillance or repair. The staff reviewed this enhancement 

against the corresponding program element in GALL Report AMP XI.S8 and finds it acceptable 

because GALL Report AMP XI.S8 recommends ASTM D 5163-08 as an acceptable method for 

characterization, documentation, and testing of Service Level I coatings, and when the 

enhancement is implemented it will make the program consistent with the recommendations in 

GALL Report AMP XI.S8.

Enhancement 5. LRA Section B2.1.33 states an enhancement to the “corrective actions” 

program element. In this enhancement, the applicant stated that the procedures will be 

enhanced to specify that the inspection reports prioritize repair areas as either needing repair 

during the same outage or as postponed to future outages, but under surveillance in the interim 

period. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S8 and finds it acceptable because GALL Report AMP XI.S8

recommends that a recommended corrective action plan be provided for defective areas, and 

when the enhancement is implemented it will make the program consistent with the 

recommendations in GALL Report AMP XI.S8.

Based on its audit of the applicant’s Protective Coating Monitoring and Maintenance Program, 

the staff finds that program elements one through six for which the applicant claimed 

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

GALL Report AMP XI.S8. The staff also reviewed the exception associated with the “scope of 

program” program element and its justification and finds that the AMP, with exception, is 

adequate to manage the applicable aging effects. In addition, the staff reviewed the 

enhancements associated with the “parameters monitored or inspected,” “detection of aging 

effects,” “monitoring and trending,” “acceptance criteria,” and “corrective actions” program 

elements and finds that when implemented they will make the AMP adequate to manage the 

applicable aging effects.
AGING MANAGEMENT REVIEW RESULTS

3-207

Operating Experience. LRA Section B2.1.33 summarizes operating experience related to the 

Protective Coating Monitoring and Maintenance Program. 

The applicant stated that damaged coatings were identified at several locations during the 

coating condition assessment of RFO 16 (fall 2008). The applicant reported that the total 

surface area of the degraded coatings identified was conservatively estimated at 7 square feet. 

The applicant stated that the damaged coatings were evaluated and removed before exiting the 

RFO.

The applicant stated that several areas of damaged coatings were identified during the coating 

condition assessment for RFO 17 (spring 2010). The applicant reported that the total surface 

area of the degraded coatings identified was conservatively estimated at 10 square feet. The 

applicant stated that the damaged coatings were removed. The applicant stated that damaged 

coatings were identified at several locations during the coating condition assessment of RFO 18 

(fall 2011). The applicant reported that the total surface area of the degraded coatings identified 

was conservatively estimated at 10 square feet. The applicant stated that the damaged 

coatings were evaluated and removed. The applicant also stated that the damaged coatings did 

not impact the results of the containment recirculation sump strainer indeterminate coatings 

calculation.

The staff reviewed the operating experience information in the application and during the audit 

to determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.S8 was evaluated.

FSAR Supplement. LRA Section A1.33 provides the FSAR supplement for the Protective 

Coating Monitoring and Maintenance Program. The staff reviewed this FSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 24) to 

enhance the existing Protective Coating Monitoring and Maintenance Program six months 

before the period of extended operation for managing aging of applicable components during 

the period of extended operation. The staff finds that the information in the FSAR supplement, 

as amended by letter dated February 28, 2013, is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s Protective Coating Monitoring 

and Maintenance Program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. In addition, the staff 

reviewed the exception and its justification and determines that the AMP, with the exception, is 

adequate to manage the applicable aging effects. Also, the staff reviewed the enhancements 

and confirmed that their implementation through Commitment No. 24 six months before the 

period of extended operation will make the AMP adequate to manage the applicable aging 
AGING MANAGEMENT REVIEW RESULTS

3-208

effects. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR 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 Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements

Summary of Technical Information in the Application. LRA Section B2.1.34 describes the 

existing Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program as consistent, with enhancements, with 

GALL Report AMP XI.E1, “Insulation Material for Electrical Cables and Connections Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements.” The applicant stated that non-EQ 

cables, connections, and terminal blocks within the scope of license renewal in accessible areas 

with an adverse localized environment are inspected. The applicant also stated that at least 

once every 10 years, the non-EQ cables, connections, and terminal blocks within the scope of 

license renewal in accessible areas are visually inspected for embrittlement, discoloration, 

cracking, melting, swelling, or surface contamination.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.E1. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “acceptance criteria,” and “corrective actions” program 

elements associated with 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 B2.1.34 states an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to include all accessible in-scope cable in an adverse localized environment. The staff reviewed 

this enhancement against the corresponding program element in GALL Report AMP XI.E1 and 

finds it acceptable because when it is implemented the applicant’s AMP will be consistent with 

the recommendations of GALL Report AMP XI.E1 for the “scope of program” program element.

Enhancement 2. LRA Section B2.1.34 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” “acceptance criteria,” and “corrective actions” program 

elements. In this enhancement, the applicant stated that procedures will be enhanced to ensure 

there are no unacceptable visual indications of surface anomalies. The applicant also stated 

that all unacceptable visual indications of cable jacket and connection insulation surface 

anomalies will be subject to an engineering evaluation for “parameters monitored or inspected,” 

“detection of aging effects,” “acceptance criteria,” and “corrective actions” program elements. 

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.E1 and finds it acceptable because when it is implemented the applicant’s 

AMP will be consistent with the recommendations of GALL Report AMP XI.E1.

Based on its audit of the applicant’s Insulation Material for Electrical Cables and Connections 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff finds 

that program elements one through six for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 
AGING MANAGEMENT REVIEW RESULTS

3-209

AMP XI.E1. In addition, the staff reviewed the enhancements associated with the “scope of 

program,” “parameters monitored or inspected,” “detection of aging effects,” “acceptance 

criteria,” and “corrective actions” program elements and finds that when implemented they will 

make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.34 summarizes operating experience related to the 

Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program. The applicant stated that in 2007 an 

anomaly in high potential test results on phase B was noted while testing a 13.8 kV cable to a 

nonsafety-related 4160 V transformer. The applicant also stated that the cable had not failed 

and was identified for trending. In addition, the applicant stated that no instances of reduced 

insulation resistance in an adverse localized environment have been identified.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.E1 was evaluated. 

FSAR Supplement. LRA Section A1.34 provides the FSAR supplement for the Insulation 

Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program. The staff reviewed this FSAR supplement description of 

the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 25) to 

enhance the existing Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program six months before the period 

of extended operation for managing aging of applicable components during the period of 

extended operation. The staff finds that the information in the FSAR supplement, as amended 

by letter dated February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Insulation Material for 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements 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. 25 six months 

before the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. The staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR 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

3-210

3.0.3.2.20 Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation 

Circuits

Summary of Technical Information in the Application. LRA Section B2.1.35, as amended by 

letter dated April 25, 2012, describes the existing Insulation Material for Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits Program as consistent, with enhancements, with GALL Report 

AMP XI.E2, “Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.” The 

LRA states that this program manages reduced insulation resistance to ensure that cables and 

connections used in sensitive instrumentation circuits with high voltage low-level current signals 

within the ex-core neutron monitoring system are capable of performing their intended functions. 

The LRA also states that all high voltage cables to radiation monitors within the scope of license 

renewal are managed by the EQ of Electric Components Program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.E2. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “acceptance criteria,” and “corrective actions” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of these enhancements 

follows.

Enhancement 1. LRA Section B2.1.35 states an enhancement to the “scope of program” and 

“acceptance criteria” program elements. In this enhancement, the applicant stated that 

procedures will be enhanced to identify the scope of cables requiring aging management. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.E2 and finds it acceptable because when it is implemented the applicant’s AMP will be 

consistent with the GALL Report AMP XI.E2 “scope of program” and “acceptance criteria” 

program elements.

Enhancement 2. LRA Section B2.1.35, as amended by letter dated April 25, 2012, states an 

enhancement to the “parameters monitored or inspected” and “detection of aging effects” 

program elements. The applicant stated that procedures will be enhanced to require 

engineering review of surveillance results every 10 years. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.E2 and finds it acceptable 

because when it is implemented the applicant’s AMP will be consistent with the GALL Report 

AMP XI.E2 “parameters monitored or inspected” and “detection of aging effects” program 

elements.

Enhancement 3. LRA Section B2.1.35, as amended by letter dated April 25, 2012, states an 

enhancement to the “corrective actions” program element. The applicant stated that procedures 

will be enhanced to ensure corrective actions are initiated when surveillance results do not meet 

acceptance criteria and to require an engineering evaluation be performed. When an 

unacceptable condition or situation is identified, a determination is also made as to whether the 

review of surveillance results or the cable testing frequency needs to be increased. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.E2 and finds it acceptable because when it is implemented the applicant’s AMP will be 

consistent with the GALL Report AMP XI.E2 “corrective actions” program element.
AGING MANAGEMENT REVIEW RESULTS

3-211

Based on its audit of the applicant’s Insulation Material for Electrical Cables and Connections 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits Program, the staff finds that program elements one through six for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.E2. In addition, the staff reviewed 

the enhancements associated with the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “acceptance criteria,” and “corrective actions” program 

elements and finds that when implemented they will make the AMP adequate to manage the 

applicable aging effects.

Operating Experience. LRA Section B2.1.35 summarizes operating experience related to the 

Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits Program. In CAR 

No. 200404746, the applicant stated that signal noise was found on signal cable B on 

channel N61. The channel consists of two fission chambers in one detector housing with two 

signal cables. Testing of the system identified high noise on signal cable B and the applicant 

determined that a bad solder joint created the bad cable connection. The applicant took 

corrective action to pull the new cable.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP XI.E2 was evaluated. 

FSAR Supplement. LRA Section A1.35 provides the FSAR supplement for the Insulation 

Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits Program. The staff reviewed this 

FSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed (Commitment No. 26) to enhance the existing Insulation Material for Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits Program six months before the period of 

extended operation for managing aging of applicable components during the period of extended 

operation. The staff finds that the information in the FSAR supplement, as amended by letters 

dated April 25, 2012, and February 28, 2013, is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the applicant’s Insulation Material for 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits Program, the staff determines that those 

program elements for which the applicant claimed consistency with the GALL Report are 
AGING MANAGEMENT REVIEW RESULTS

3-212

consistent. Also, the staff reviewed the enhancements and confirmed that their implementation 

through Commitment No. 26 six months before the period of extended operation will make the 

AMP adequate to manage the applicable aging effects. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.2.21 Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

Summary of Technical Information in the Application. LRA Section B2.1.36, as amended by 

letters dated April 25, 2012, and August 9, 2012, describes the existing Inaccessible Power 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program as 

consistent, with enhancements, with GALL Report AMP XI.E3, “Inaccessible Power Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The LRA states that the 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program manages reduced insulation resistance of power cables (greater than or 

equal to 400 V) to minimize aging effects that could potentially lead to failure of the cable’s 

insulation system. The LRA states that the program provides reasonable assurance that the 

intended functions of inaccessible or underground power cables exposed to wetting or 

submergence are maintained consistent with the CLB through the period of extended operation. 

The LRA also states that manholes, pits, and duct banks that contain in-scope non-EQ 

inaccessible power cables will be inspected for water collection. In addition, the LRA states that 

the inspection will include direct observation that the cables are not submerged or immersed in 

water, cables/splices and support structures are intact, and dewatering/drainage systems 

(i.e., sump pumps) and associated alarms operate properly. Inspection and water removal is 

performed based on plant experience with an inspection frequency of at least annually and after 

event-driven occurrences (such as heavy rain or flooding). In addition, operation of dewatering 

devices will be inspected before any known or predicted heavy rain or flooding events. The 

LRA further states that the first inspection for license renewal is to be completed before the 

period of extended operation. Finally, the LRA states that in-scope inaccessible power cables 

will be tested to provide an indication of the conductor insulation condition with the first tests for 

license renewal completed before the period of extended operation and every 6 years 

thereafter. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.E3.

For the “scope of program,” “detection of aging effects,” and “corrective actions” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below.

The “scope of program” program element in GALL Report AMP XI.E3 recommends a voltage 

level of greater than or equal to 400 V. However, during its audit, the staff found that the 

applicant’s “scope of program” program element of basis document CW-AMP-B2.1.36, 

“Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements,” does not indicate the voltage level of in-scope inaccessible power cable 

(i.e., greater than or equal to 400 V). Additionally, LRA FSAR supplement A1.36 and LRA 
AGING MANAGEMENT REVIEW RESULTS

3-213

Appendix A, Table A4-1, “License Renewal Commitments,” do not specify inaccessible power 

cable voltage level. 

By letter dated July 9, 2012, the staff issued RAI B2.1.36-1 requesting that the applicant explain 

why the “scope of program” program element for basis document CW-AMP-B2.1.36, 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements, LRA Section A1.36, “Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements,” and LRA Table A4-1, “License Renewal 

Commitments,” do not reference in-scope inaccessible power cable voltage level (greater than 

or equal to 400 V). 

In its response dated August 9, 2012, the applicant stated that LRA Table A4-1 item 27, LRA 

Section A1.36, and the enhancement to “scope of program” program element in LRA 

Section B2.1.36, have been revised as shown by LRA Amendment 6 to indicate that in-scope 

non-EQ inaccessible power cables are greater than or equal to 400 V. The applicant also 

stated that it revised basis document CW-AMP-B2.1.36 to indicate that in-scope non-EQ 

inaccessible power cables are greater than or equal to 400 V.

The staff finds the applicant’s response acceptable because all of the aforementioned 

documents in question were revised by the applicant to indicate in-scope inaccessible power 

cable voltage level as greater than or equal to 400 V consistent with the recommendations of 

GALL Report AMP XI.E3. The staff’s concern described in RAI B2.1.36-1 is resolved.

GALL Report AMP XI.E3 recommends that periodic actions be taken to prevent inaccessible 

power cables from being exposed to significant moisture, such as identifying and inspecting 

in-scope accessible cable conduit ends and cable manholes for water collection, and draining 

the water as needed. However, during its audit, the staff found that the “scope of program” 

program element of the Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program does not include in-scope manholes MH59-8A and 

MH59-8B. 

By letter dated July 9, 2012, the staff issued RAI B2.1.36-2 requesting that the applicant explain 

why in-scope manholes MH59-8A and MH59-8B are not included in the “scope of program” 

program element of its Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program.

In its response dated August 9, 2012, the applicant stated that “basis document 

CW-AMP B2.1.36, Element 3.1, Scope of Program, has been revised to include MH59-8A and 

MH59-8B.”

The staff finds the applicant’s response acceptable because the basis document 

CW-AMP-B2.1.36 was revised to include all in-scope manholes consistent with the 

recommendations of GALL Report AMP XI.E3. The staff’s concern described in RAI B2.1.36-2 

is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.E3 recommends that 

power cables exposed to significant moisture be tested at least once every 6 years and be 

adjusted based on test results (including trending of degradation where applicable) and 

operating experience. However, during its audit, the staff found that the applicant’s “detection of 

aging effects” program element of its Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program, draft procedure EDP-ZZ-07001, and LRA 
AGING MANAGEMENT REVIEW RESULTS

3-214

Section A1.36 do not state that test frequencies are adjusted based on test results as well as 

operating experience. 

By letter dated July 9, 2012, the staff issued RAI B2.1.36-4 requesting that the applicant explain 

why the “detection of aging effects” program element of basis document CW-AMP-B2.1.36, LRA 

Section A1.36, and draft procedure EDP-ZZ-07001 do not include adjusting test frequencies 

based on test results and operating experience consistent with the recommendations in 

GALL Report AMP XI.E3 “detection of aging effects” program element.

In its response dated August 9, 2012, the applicant stated that LRA Sections A1.36, B2.1.36, 

and LRA Table A4-1 item 27 have been revised as shown by LRA Amendment 6 to read “[t]he 

first test for license renewal will be completed before the period of extended operation with 

subsequent tests performed at least every [6] years thereafter and adjusted based on test 

results and operating experience.” The applicant also stated that basis document 

CW-AMP-B2.1.36, “detection of aging effects” program element and draft procedure 

EDP-ZZ-07001 paragraphs 4.1.8 and 4.1.9 have been enhanced to state that the frequency of 

inspection and test is “...adjusted based on test results and operating experience...”

The staff finds the applicant’s response acceptable because all of the aforementioned 

documents in question were revised consistent with the recommendations in GALL Report 

AMP XI.E3 “detection of aging effects” program element. The staff’s concern described in 

RAI B2.1.36-4 is resolved.

During the audit the staff found that draft procedure EDP-ZZ-07001 Section 2.0, “Scope,” states 

that Table 2, “Underground Cable Requiring Aging Management,” lists the inaccessible power 

cables not subject to EQ requirements and within the scope of license renewal aging 

management. Table 2 lists additional cables not in-scope of basis document CW-AMP-B2.1.36 

or the Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program. Additionally, in-scope cable CA-3331L2 is duplicated in Table 2 with 

different routing.

By letter dated July 9, 2012, the staff issued RAI B2.1.36-6 requesting that the applicant 

reconcile Table 2 and Section 2, “Scope,” descriptions. The staff also requested the applicant 

to identify cables in-scope of license renewal and associated AMPs, including the Inaccessible 

Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program 

(GALL Report AMP XI.E3) in Table 2. In addition, the staff requested the applicant to provide 

clarification on duplicate cable listing for CA-3331L2 in Table 2.

In its response dated August 9, 2012, the applicant stated that Procedure EDP-ZZ-07001 has 

been revised to include the following:

• Section 2.0 third paragraph states: “Table 2 lists underground cable requiring aging 

management”

• [a]dded column to Table 2 enhancement to identify whether the cable will be managed 

by XI.E1 or XI.E3

• [r]evised Table 2 to reflect Cable CA-3331L2 is routed from MH59-1A, through MH59-4, 

and to MH59-5

The staff finds the applicant’s response acceptable because the differences in the two 

documents for in-scope cables have been reconciled. Additionally, the applicant provided the 
AGING MANAGEMENT REVIEW RESULTS

3-215

requested clarification to the duplicate cable listing. The staff’s concern described in 

RAI B2.1.36-6 is resolved.

The “corrective actions” program element in GALL Report AMP XI.E3 recommends corrective 

actions are taken and an engineering evaluation is performed when the test or inspection 

acceptance criteria are not met. However, during its audit, the staff found that the applicant’s 

draft procedure EDP-ZZ-07001, Section 4.2.3, states that appropriate corrective actions shall be 

taken if significant aging that results from adverse environments is identified or suspected. The 

corrective action is not consistent with the GALL Report AMP XI.E3 “corrective actions” program 

element or basis document CW-AMP-B2.1.36.

By letter dated July 9, 2012, the staff issued RAI B2.1.36-7 requesting that the applicant explain 

why the corrective actions as described in draft procedure EDP-ZZ-07001, Section 4.2.3, are 

not consistent with GALL Report AMP XI.E3.

In its response dated August 9, 2012, the applicant stated that “[p]aragraph 4.2.6 of 

procedure EDP-ZZ-07001 markup was redundant to paragraph 4.3.10, which is cited in basis 

document CW-AMP B2.1.36, Element 7, Corrective Actions.” The applicant also stated that 

procedure EDP-ZZ-07001 markup has been revised to remove the redundancy in 

paragraph 4.2.6, and corrective actions remain in paragraph 4.3.10 as described in the basis 

document.

The staff finds the applicant’s response acceptable because procedure EDP-ZZ-07001 was 

revised consistent with the applicant’s basis document and the recommendations in the 

GALL Report AMP XI.E3 “corrective actions” program element. The staff’s concern described in 

RAI B2.1.36-7 is resolved.

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” “monitoring and trending,” “acceptance 

criteria,” and “corrective actions” program elements associated with enhancements to determine 

whether the program will be adequate to manage the aging effects for which it is credited. The 

staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, states an enhancement to the “scope of program” program element. In this 

enhancement, the applicant stated that procedures will be enhanced to identify the power 

cables (greater than or equal to 400 V), manholes, pits, and duct banks that are within the 

scope of the Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.E3 and finds it acceptable because 

when it is implemented it will be consistent with the recommendations of GALL Report 

AMP XI.E3 “scope of program” program element with regard to identification of in-scope 

inaccessible power cables.

Enhancement 2. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, states an enhancement to the “preventive actions” program element. In this 

enhancement, the applicant stated that procedures will be enhanced to include periodic 

inspection of manholes, pits, and duct banks and to confirm (1) cables are not submerged or 

immersed in water, (2) cables/splices and cable support structures are intact, and 

(3) dewatering/drainage systems (i.e., sump pumps) and associated alarms operate properly. 

The applicant stated that inspections will be performed at least annually based on water 

accumulation over time and after event-driven occurrences (e.g., heavy rain or flooding). The 
AGING MANAGEMENT REVIEW RESULTS

3-216

applicant also stated that operation of dewatering devices will be inspected and confirmed 

before any known or predicted heavy rain or flooding events. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.E3 and finds 

it acceptable because when it is implemented it will be consistent with the recommendations of 

the GALL Report AMP XI.E3 “preventive actions” program element.

Enhancement 3. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, states an enhancement to the “parameters monitored or inspected” program 

element. In this enhancement, the applicant stated that procedures will be enhanced to confirm 

cables are not submerged or immersed in water, cable/splices and cable support structures are 

intact, dewatering/drainage systems (i.e., sump pumps) and associated alarms operate 

properly, and power cables subject to significant moisture are tested periodically. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.E3 and finds it acceptable because when it is implemented it will be consistent with the 

recommendations of the GALL Report AMP XI.E3 “parameters monitored or inspected” program 

element.

Enhancement 4. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, states an enhancement to the “detection of aging effects” program element. In 

this enhancement, the applicant stated that procedures will be enhanced to ensure that in-scope 

power cables are tested at least once every 6 years and adjusted based on test results and 

operating experience. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.E3 and finds it acceptable because when it is implemented it 

will be consistent with the recommendations of the GALL Report AMP XI.E3 “detection of aging 

effects” program element.

Enhancement 5. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, states an enhancement to the “monitoring and trending” program element. In 

this enhancement, the applicant stated that procedures will be enhanced to require comparing 

results to previous test results to evaluate for additional information on the rate of cable 

degradation. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.E3 and finds it acceptable because when it is implemented it 

will be consistent with the recommendations of the GALL Report AMP XI.E3 “monitoring and 

trending” program element.

Enhancement 6. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, states an enhancement to the “acceptance criteria” program element. In this 

enhancement, the applicant stated that procedures will be enhanced to confirm cables are not 

submerged or immersed in water, cable/splices and cable support structures are intact, and 

dewatering/drainage systems (i.e., sump pumps) and associated alarms operate properly. The 

applicant also stated that acceptance criteria for cable testing will be defined before each test. 

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.E3 and finds it acceptable because when it is implemented it will be 

consistent with the recommendations of the GALL Report AMP XI.E3 “acceptance criteria” 

program element.

Enhancement 7. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, states an enhancement to the “corrective actions” program element. In this 

enhancement, the applicant stated that procedures will be enhanced to require an engineering 

evaluation when the test or inspection acceptance criteria are not met. The staff reviewed this 
AGING MANAGEMENT REVIEW RESULTS

3-217

enhancement against the corresponding program element in GALL Report AMP XI.E3 and finds 

it acceptable because when it is implemented it will be consistent with the recommendations of 

the GALL Report AMP XI.E3 “corrective action” program element.

Based on its audit of the applicant’s Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program and review of the applicant’s responses to 

RAIs B2.1.36-1, B2.1.36-2, B2.1.36-4, B2.1.36-6, and B2.1.36-7, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.E3. In addition, 

the staff reviewed the enhancements associated with the “scope of program,” “preventive 

actions,” “parameters monitored or inspected,” “detection of aging effects,” “monitoring and 

trending,” “acceptance criteria,” and “corrective actions” program elements and finds that when 

implemented they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B2.1.36, as amended by letters dated April 25, 2012, and 

August 9, 2012, summarizes operating experience related to the Inaccessible Power Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Program. The applicant 

stated that it had been performing inspections of safety-related manhole MH01 on a 36-month 

frequency. The applicant stated that water was found in MH01 in 2003 and 2009 with water 

being below medium-voltage safety-related cables and in 2006 with all cables submerged. The 

applicant determined that the manhole cover seals were degraded. The applicant also stated 

that corrective actions included (1) new seals being installed since 2009 after each inspection of 

MH01, (2) inspection frequency for MH01 was changed from 36 to 6 months, and (3) foundation 

sealant, drain pipes, and flashing were installed for MH01 in 2010. The applicant further stated 

that the as-found water level for MH01A dropped from 30 to 15 in. and from 24 to 2 in. for 

MH01B. The applicant stated that the existing program tests cable periodically with no 

degradation of safety-related cables noted. In addition, the applicant implemented new 

preventive maintenance in 2011 to inspect for water level and pump out all in-scope manholes 

weekly. The applicant further stated that a modification to install sump pumps in all in-scope 

manholes is currently underway with five manholes completed as of March 12, 2012. The 

applicant noted that operating experience with the Inaccessible Power Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program has not identified any cable 

failures as a result of submergence. 

The staff also reviewed recent integrated inspection reports (January 20, 2010, 

January 26, 2011, May 4, 2011, July 18, 2011, and August 24, 2011). No findings were noted 

for manholes or cable submergence. In addition, during the audit the staff conducted 

walkdowns of in-scope manholes MH59-31, MH59-01A, MH59-01B, MH59-12, MH59-20, 

MH59-19, and switchyard control house cable pit 2 confirming locations, labeling, cover 

integrity, and susceptibility to surface water runoff. The staff noted that manhole MH59-12 with 

sump pump installed was opened for inspection with no issues noted. The staff reviewed 

corrective action reports documenting manhole inspection findings and corrective action taken, 

including water removal, revised inspection frequencies, cable test guidance, and the 

development of a modification package and associated work orders to install sump pumps in 

in-scope manholes.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 
AGING MANAGEMENT REVIEW RESULTS

3-218

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI as 

discussed below.

The staff reviewed the applicant’s response to GL 2007-01, “Inaccessible or Underground 

Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients,” 

which requested, in part, that applicants provide a history of inaccessible or underground power 

cable failures. The applicant’s response stated that one failure of a 480 V AC power cable 

within the scope of 10 CFR 50.65 was noted (voltage range of 480 V AC to 1.5 kV AC). A 

definitive root cause for the failure was not determined by the applicant. Cable damage during 

installation leading to eventual failure was suspected based on the replacement cable being in 

service for 17 years. Although CAR 201008001 was written to address the lack of a medium 

voltage cable strategy at Callaway and not a specific cable failure, the staff noted during the 

audit that CAR 201008001 also states that some cable failures at Callaway were attributed to 

water submergence.

By letter dated July 9, 2012, the staff issued RAI B2.1.36-5 requesting that the applicant 

describe the cable failures at Callaway that have been attributed to submergence and describe 

any changes to the existing program as a result of operating experience gained from these 

failures.

In its response dated August 9, 2012, the applicant stated that after the audit a search for cable 

failures at Callaway confirmed that no cable failures that could be directly attributed to water 

submergence have occurred and, therefore, the statement in CAR 201008001 was inaccurate. 

The applicant stated that the inaccuracy in CAR 201008001 was entered as an adverse 

condition into the Callaway CAP and as corrective action, to verify that there have been no 

cable failures at Callaway attributed to submergence, an independent document review was 

conducted and the text in CAR 201008001 was revised to remove the inaccurate statement. 

The applicant also stated that its response to GL 2007-01 and the discussion of plant operating 

experience for the Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program correctly state that operating experience with the existing 

program did not identify any cable failures attributed to submergence or water intrusion.

The staff finds the applicant’s response acceptable because the applicant resolved the 

inaccuracy in CAR 201008001 by taking corrective actions which consisted of performing an 

independent review that confirmed no cable failures directly attributed to water submergence 

have occurred at Callaway and revising the text in the CAR to remove the inaccurate statement. 

The staff’s concern described in RAI B2.1.36-5 is resolved.

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

RAI B2.1.36-5, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective action. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.E3 was

evaluated. 

FSAR Supplement. LRA Section A1.36 provides the FSAR supplement for the Inaccessible 

Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements 

Program. The staff reviewed this FSAR supplement description of the program against the 

recommended description for this type of program as described in SRP-LR Table 3.0-1 and 

noted that the enhancements listed in LRA Table A4-1, Commitment No. 27, and the AMP 
AGING MANAGEMENT REVIEW RESULTS

3-219

description in LRA Section A1.36, are not in agreement. Specifically, LRA Table A4-1 includes 

enhancements that state the following but are not addressed in LRA Section A1.36.

• operation of dewatering devices will be inspected and confirmed before any known or 

predicted heavy rain or flooding events

• test results will be compared to previous test results to evaluate for additional 

information on the rate of cable degradation

• acceptance criteria for cable testing will be defined before each test

• an engineering evaluation will be required when the test or inspection acceptance 

criteria are not met

The licensing basis for this program for the period of extended operation may not be adequate if 

the applicant does not incorporate this information into its FSAR supplement (LRA 

Section A1.36). By letter dated July 9, 2012, the staff issued RAI B2.1.36-3 requesting that the 

applicant explain why the above enhancements described in LRA Table A4-1, Commitment 

No. 27 are not included LRA Section A1.36 consistent with the recommendations in 

GALL Report AMP XI.E3.

In its response dated August 9, 2012, the applicant stated that LRA Section A1.36 has been 

revised as shown by LRA Amendment 6 and basis document CW-AMP-B2.1.36 has been 

revised to include: 

• test results will be compared to previous test results to evaluate for additional 

information on the rate of cable degradation

• acceptance criteria for cable testing will be defined before each test

• an engineering evaluation is required when the test or inspection acceptance criteria are 

not met

The staff also noted that by letter dated April 25, 2012, the applicant revised LRA Section A1.36 

to include the following: “[d]ewatering devices will be inspected and operation confirmed before 

any known or predicted heavy rain or flooding events.”

The staff finds the applicant’s response acceptable because LRA Section A1.36 and basis 

document CW-AMP-B2.1.36 have been revised and are consistent with each other and the 

recommendations in GALL Report AMP XI.E3. Therefore, the FSAR supplement for the 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program is consistent with the corresponding program description in SRP-LR 

Table 3.0-1. The staff’s concern described in RAI B2.1.36-3 is resolved.

The staff also noted that the applicant committed (Commitment No. 27) to enhance the existing 

Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program six months before the period of extended opertion for managing aging 

of applicable components during the period of extended operation. The staff finds that the 

information in the FSAR supplement, as amended by letters dated April 25, 2012, 

August 9, 2012, and February 28, 2013, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inaccessible Power Cables 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff 

determines that those program elements for which the applicant claimed consistency with the 
AGING MANAGEMENT REVIEW RESULTS

3-220

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation through Commitment No. 27 six months before the period of extended 

operation will make the AMP adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

FSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.22 Fatigue Monitoring

Summary of Technical Information in the Application. LRA Section B3.1 describes the existing

Fatigue Monitoring Program as consistent, with enhancements, with GALL Report AMP X.M1, 

“Fatigue Monitoring.” The LRA states that the program manages fatigue cracking caused by 

anticipated cyclic strains in metal components of the RCPB. The LRA also states that the 

Fatigue Monitoring Program ensures that actual plant experience remains bounded by the 

thermal and pressure transient numbers and severities analyzed in the design calculations; 

otherwise, corrective actions are taken to maintain the design and licensing basis. The LRA 

further states that the Fatigue Monitoring Program tracks fatigue by one of the following 

methods: (1) the cycle counting monitoring method, (2) the cycle-based fatigue (CBF) 

monitoring method, and (3) the stress-based fatigue (SBF) monitoring method. In addition, the 

LRA states that the program will be enhanced to include environmentally-assisted fatigue (EAF) 

for a set of RCS sample locations, which includes fatigue monitoring of the NUREG/CR-6260 

sample locations for a newer-vintage Westinghouse Plant and plant-specific bounding EAF 

locations. The LRA also states that the supporting environmental factors calculations will be 

performed with NUREG/CR-6909 or NUREG/CR-6583 for carbon and low-alloy steels, 

NUREG/CR-6909 or NUREG/CR-5704 for austenitic stainless steels, and NUREG/CR-6909 for 

nickel alloys.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP X.M1.

The staff noted that LRA Section 4.3.1.1 provides additional details on the Fatigue Monitoring 

Program’s monitoring methods. Specifically, it states that the cycle counting monitoring method 

tracks transient event cycles affecting the location to ensure that the number of transient events 

analyzed by the design calculations are not exceeded. The staff noted that this method relies 

on ensuring that the actual severity of transients is less than the design severity in order to 

count the number of design transient cycles, which is discussed in Enhancement 2. The staff 

finds it conservative that the applicant records transients as full design transient cycles because 

the severity of actual transients is typically less than the design transient definition; thus, this 

equates to a lower actual accumulated fatigue usage when compared to the design assumption. 

The staff noted that this method compares the numbers of cycles that have occurred to the 

corresponding allowable values used in associated fatigue analyses. The staff finds the use of 

cycle counting to be capable of managing metal fatigue because it ensures that the 

assumptions used in a fatigue evaluation remain valid, thus, ensuring the design limit is not 

exceeded.

Furthermore, LRA Section 4.3.1.1 states that the CBF monitoring method uses the cycle 

counting results and stress intensity ranges generated with the ASME Code Section III methods 

to perform CUF calculations for a given location, and the fatigue accumulation is tracked to 
AGING MANAGEMENT REVIEW RESULTS

3-221

determine if the ASME Code allowable fatigue limit of 1.0 is approached. The staff noted that 

the applicant’s program includes corrective actions that address the issue when actual transient 

severity exceeds design transient severity, which is consistent with the “detection of aging 

effects” program element of GALL Report AMP X.M1. The staff finds the use of CBF monitoring 

to be capable of managing metal fatigue because it periodically calculates cumulative fatigue 

usage based on the cycle counts and design transient severity to ensure the design limit is not 

exceeded through the period of extended operation.

Finally, LRA Section 4.3.1.1 states that the SBF monitoring method computes a “real time” 

stress history for a given component from data collected by plant instruments to calculate 

transient pressure and temperature and the corresponding stress history at the critical location 

in the component. The staff noted that the use of actual plant data such as local pressure and 

thermal conditions to calculate actual fatigue usage is consistent with the “parameters 

monitored or inspected” program element of GALL Report AMP X.M1 for more “detailed 

monitoring.” The staff finds the use of SBF monitoring to be capable of managing metal fatigue 

because it periodically calculates cumulative fatigue usage based on the conditions that are 

actually occurring at the applicant’s site during transients to ensure the design limit is not 

exceeded through the period of extended operation. 

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “monitoring and trending,” “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 B3.1 states an enhancement to the “scope of program” program 

element. In this enhancement, as amended by letter dated October 17, 2013, the applicant 

stated that procedures will be enhanced to include fatigue usage calculations that consider the 

effects of the reactor water environment for a set of sample reactor coolant pressure boundary 

locations and reactor vessel internals locations with fatigue usage calculations. The reactor 

coolant pressure boundary set includes the NUREG/CR-6260 sample locations for a 

newer-vintage Westinghouse Plant, and plant-specific bounding EAF locations. The 

enhancement also states that procedures will be enhanced to ensure that the fatigue crack 

growth analyses, which support the leak-before-break (LBB) analyses, ASME Code Section XI 

evaluations, and the high-energy line break (HELB) selection criterion, remain valid by counting 

the transients used in the analyses.

The “scope of program” program element of GALL Report AMP X.M1 states for purposes of 

monitoring and tracking applicants should include, for a set of sample RCS components, fatigue 

usage calculations that consider the effects of the reactor water environment. This sample set 

is to include the locations identified in NUREG/CR-6260 and additional plant-specific component 

locations in the RCPB if they may be more limiting than those considered in NUREG/CR-6260. 

Consistent with the recommendations of GALL Report AMP X.M1, the applicant proposed to 

enhance its program to address EAF for the NUREG/CR-6260 sample locations for a 

newer-vintage Westinghouse Plant and plant-specific bounding EAF locations. The staff’s 

review of the applicant’s evaluation of the NUREG/CR-6260 sample locations for a 

newer-vintage Westinghouse Plant and the methodology to identify plant-specific bounding EAF 

locations is documented in SER Section 4.3.4.2. The staff noted that in response to 

Applicant/Licensee Action Item No.8, Item 5, to MRP-227-A, the applicant is also addressing the 

effects of reactor water environment on reactor vessel internals locations with fatigue usage 

calculations. The staff noted that, regardless of whether the components are reactor coolant 
AGING MANAGEMENT REVIEW RESULTS

3-222

pressure boundary or reactor vessel internals, they are both exposed to the same water 

environment and are impacted by environmentally assisted fatigue. Thus, the staff finds it 

appropriate and acceptable that the reactor vessel internal locations are included into the 

Fatigue Monitoring Program for consideration and aging management of environmentally 

assisted fatigue.

The staff noted that the applicant also proposed to include fatigue crack growth analyses, which 

support the LBB analyses, ASME Code Section XI evaluations, and the HELB break selection 

criterion, within the scope of its Fatigue Monitoring Program during the period of extended 

operation. Since this portion of the applicant’s enhancement is beyond the recommendations of 

GALL Report AMP X.M1, the staff’s review was performed in accordance with SRP-LR 

Section A.1.2.3.1, “Scope of Program,” which states that the scope of the program should 

include the specific SCs for which program manages aging. The staff noted that these analyses 

use the same design transients monitored by the cycle counting monitoring method of the 

program. The staff finds the use of the cycle counting method for these analyses appropriate 

because it will ensure that corrective actions are taken before any assumptions used in these 

analyses have the possibility of becoming invalid. The staff’s review of each method is 

described above.

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP X.M1 and finds it acceptable because, when it is implemented, the applicant 

will have addressed EAF for the NUREG/CR-6260 locations and potential additional 

plant-specific component locations consistent with the GALL Report. In addition, as described 

above, the staff finds it acceptable that the applicant includes reactor vessel internal locations 

with fatigue usage calculations in the Fatigue Monitoring Program for aging management of 

environmentally assisted fatigue. The staff also finds this enhancement acceptable because, 

consistent with SRP-LR Section A.1.2.3.1, the Fatigue Monitoring Program specifically identifies 

the additional analyses that will be added to the Fatigue Monitoring Program and also includes 

measures, as described above, of ensuring that the assumptions used in these fatigue crack 

growth analyses remain valid during the period of extended operation; otherwise, corrective 

actions will be taken.

Enhancement 2. LRA Section B3.1 states an enhancement to the “preventive actions” program 

element. In this enhancement, the applicant stated that procedures will be enhanced to require 

the review of the temperature and pressure transient data from the operator logs and plant 

instrumentation to ensure actual transient severity is bounded by the design and to include 

environmental effects where applicable. Furthermore, if a transient occurs that exceeds the 

design transient definition, the event is documented in the CAP, and corrective actions 

are taken.

The “preventive actions” program element of GALL Report AMP X.M1 states that the program 

prevents the fatigue TLAAs from becoming invalid by ensuring that the fatigue usage resulting 

from actual operational transients does not exceed the code design limit of 1.0, including 

environmental effects where applicable. Furthermore, this could be caused by the numbers of 

actual plant transients exceeding the numbers used in the fatigue analyses or by the actual 

transient severity exceeding the bounds of the design transient definitions.

The staff noted that the applicant’s program is existing, which has been monitoring transients 

since initial plant startup, and that an essential part of a fatigue management program is to 

ensure that the design severity of a transient is not exceeded during plant operation. Therefore, 

considering that there is this enhancement to the program, it is not clear to the staff how the 
AGING MANAGEMENT REVIEW RESULTS

3-223

applicant ensures accumulated transients from initial plant startup will be bounded by the design 

transients before procedure enhancement.

By letter dated June 22, 2012, the staff issued RAI B3.1-1 requesting the applicant to explain 

how the existing program ensures that transients from initial plant startup are either bounded by 

the design transient or accurately captured by the Fatigue Monitoring Program. In addition, the 

applicant was requested to justify the purpose of the enhancement if the existing program 

already includes provisions for comparing transient severity between actual and design 

transients.

In its response dated July 20, 2012, the applicant stated that the RCPB components are 

designed to withstand the operating transients as defined in FSAR Section 3.9(N).1.1 and the 

system specifications. The applicant stated that the plant operating procedures and technical 

specifications are designed to ensure that the severity of plant events is bounded by those 

described in the design analyses (e.g., maximum rates of change of temperatures, pressures, 

flows) and that the existing Fatigue Monitoring Program requires a review of the design transient 

tracking log at least once per cycle to ensure that components are maintained within their 

design limits. The applicant also confirmed that this review draws on multiple data sources 

(e.g., CAP, plant computer, operator logs/rounds, strip charts, and FatiguePro data) to assure 

that the actual transients have been appropriately characterized and are bounded by the design 

transients. The applicant further stated that if a thermal or pressure transient occurs that is not 

bounded by the design transient, the event is documented in the CAP and an engineering 

evaluation is performed to determine the impact on applicable components and analyses.

The staff finds this approach by the existing Fatigue Monitoring Program appropriate because 

the applicant periodically ensures that design limits are not exceeded by reviewing information 

from, but not limited to, the plant computer, operator logs, and strip charts to characterize actual 

plant transients. Thus, the applicant’s existing program includes this fundamental aspect of a 

fatigue monitoring program. The applicant stated that the existing program already includes 

provisions for comparing severity between actual transients and design transients and that the 

enhancement was added to document the process within the procedure.

The staff finds the applicant’s response to RAI B3.1-1 acceptable because the Fatigue 

Monitoring Program already includes provisions for comparing design and actual transient 

severity, which ensures an accurate cycle count through the period of extended operation, and 

the applicant confirmed that the enhancement is only meant for a programmatic update of its 

procedures. The staff’s concern described in RAI B3.1-1 is resolved.

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

Fatigue Monitoring Program will procedurally document provisions for comparing design and 

actual transient severity to ensure the bounds of the design transient definitions are not 

exceeded and will be consistent with the recommendations of GALL Report AMP X.M1.

Enhancement 3. LRA Section B3.1 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that procedures will be 

enhanced to include additional transients that contribute significantly to fatigue usage identified 

by evaluation of ASME Code Section III fatigue and fatigue crack growth analyses. The 

enhancement, as amended by letter dated October 17, 2013, also states that procedures will be 

enhanced to include additional locations that receive more detailed monitoring. These locations 

were identified by evaluation of ASME Section Ill fatigue analyses and the locations evaluated for 

effects of the reactor water environment. In addition, reactor vessel internals locations with fatigue 
AGING MANAGEMENT REVIEW RESULTS

3-224

usage calculations will be evaluated for the effects of the reactor water environment. Furthermore, 

the monitoring methods will be benchmarked consistent with NRC RIS 2008-30, “Fatigue 

Analysis of Nuclear Power Plant Components.”

The “parameters monitored or inspected” program element of GALL Report AMP X.M1 states 

that the program monitors all plant design transients that cause cyclic strains, which are 

significant contributors to the fatigue usage factor. Furthermore, the number of occurrences of 

the plant transients that cause significant fatigue usage for each component is to be monitored. 

Alternatively, more detailed monitoring of local pressure and thermal conditions may be 

performed to allow the actual fatigue usage for the specified critical locations to be calculated.

The staff noted that the applicant proposed to identify additional transients that were included in 

fatigue crack growth analyses, which support the LBB analyses, ASME Code Section XI 

evaluations, and the HELB break selection criterion. Since this portion of the applicant’s 

enhancement is beyond the recommendations of GALL Report AMP X.M1, the staff’s review 

was performed in accordance with SRP-LR Section A.1.2.3.3, “Parameters Monitored or 

Inspected,” which states the aging effects that the program manages are identified and linked 

between the parameter(s) that will be monitored and how the monitoring of these parameters 

will ensure adequate aging management. The staff noted that the specific aging effects 

evaluated in these fatigue crack growth analyses will be managed by the Fatigue Monitoring 

Program because the program ensures that the assumptions used in these analyses remain 

valid during the period of extended operation; otherwise, corrective actions are taken.

The staff noted that this enhancement implies that the evaluation to identify additional transients 

that contribute significantly to fatigue usage of ASME Code Section IIl fatigue and used in 

fatigue crack growth analyses will be completed in the future. However, LRA Section 4.3.1 

states that LRA Table 4.3-2 lists the transients that the Fatigue Monitoring Program monitors. In 

addition, it states that the transients included in the program were identified through a review of 

the design and licensing analyses. Based on LRA Section 4.3.1, it seems that a review of the 

design and licensing analyses has already been performed; therefore, it is not clear to the staff 

what will be enhanced in the procedures. By letter dated June 22, 2012, the staff issued 

RAI B3.1-2 requesting the applicant to clarify the discrepancy between LRA Section B3.1 and 

LRA Section 4.3.1 and the actions associated with this enhancement to the procedures to 

include additional transients that contribute significantly to fatigue usage identified by evaluation 

of ASME Code Section III fatigue and fatigue crack growth analyses.

In its response dated July 20, 2012, the applicant stated that the review and evaluation of ASME 

Code Section IIl fatigue and fatigue crack growth analyses to identify transients that contribute 

significantly to fatigue usage has been completed. In addition, the applicant clarified that this 

enhancement in LRA Section B3.1 requires incorporation of transients that contribute 

significantly to fatigue usage into the Fatigue Monitoring Program and that a revision to the LRA 

was provided by letter dated June 5, 2012. The applicant stated that implementing procedures 

will be revised to require cycle counting of transients that contribute significantly to fatigue 

usage into the Fatigue Monitoring Program. 

The staff reviewed the revision made by letter dated June 5, 2012, to clarify the discrepancy 

identified in RAI B3.1-2. As a result, the staff finds the applicant’s response to RAI B3.1-2

acceptable because it was clarified that the review to identify transients that contribute 

significantly to fatigue usage has been completed and that this enhancement is a programmatic 

update of procedures. In addition, the staff finds the response acceptable because the review 

to identify these additional transients is consistent with the recommendations of GALL Report 
AGING MANAGEMENT REVIEW RESULTS

3-225

AMP X.M1 and ensures that the transient assumptions used in ASME Code Section Ill fatigue 

and fatigue crack growth analyses will remain valid through the period of extended operation. 

The staff’s concern described in RAI B3.1-2 is resolved.

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

Fatigue Monitoring Program will ensure the tracking of all transients that contribute significantly 

to fatigue usage, including EAF for reactor coolant pressure boundary components and reactor 

vessel internal components with fatigue usage calculations. In addition, the staff finds the 

applicant’s enhancement acceptable because, when implemented, it will specifically identify 

those locations that will receive more detailed fatigue monitoring, which is consistent with the 

GALL Report. Furthermore, the staff finds the applicant’s enhancement acceptable because, 

consistent with SRP-LR Section A.1.2.3.3, the program will also ensure the tracking of all 

transients used as assumptions in fatigue crack growth analyses to confirm their validity during 

the period of extended operation.

Enhancement 4. LRA Section B3.1 states an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that procedures will be enhanced 

to project the transient count and fatigue accumulation of monitored components into the future. 

The “monitoring and trending” program element of GALL Report AMP X.M1 states that trending 

is assessed to ensure that the fatigue usage factor remains below the design limit during the 

period of extended operation, thus minimizing fatigue cracking of metal components caused by 

anticipated cyclic strains in the material. 

The staff noted that trending of cycle counts and fatigue usage ensure that there is an ample 

amount of time for corrective actions to be taken to ensure that the cycle count limits and fatigue 

usage limits are not exceeded. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP X.M1 and finds it acceptable because when it is 

implemented the Fatigue Monitoring Program will be consistent with the GALL Report. In 

addition, it provides ample time for the applicant to take corrective actions when the trending of 

transient counts and fatigue accumulation exceed the established action limits to ensure that the 

cycle count limits and fatigue usage limits are not exceeded. 

The staff noted that the applicant included an enhancement to the “acceptance criteria” program 

element to include cycle count and fatigue usage action limits to initiate corrective actions if the 

design limits are expected to be exceeded within the next three fuel cycles. The staff’s 

evaluation of this enhancement to the “acceptance criteria” program element is discussed 

below.

Enhancement 5. LRA Section B3.1 states an enhancement to the “acceptance criteria” program 

element. In this enhancement, the applicant stated that procedures will be enhanced to include 

additional cycle count and fatigue usage action limits, which permit completion of corrective 

actions if the design limits are expected to be exceeded within the next three fuel cycles. The 

applicant also stated that the fatigue results associated with the NUREG/CR-6260 sample 

locations for a newer vintage Westinghouse plant and plant-specific bounding EAF locations will 

account for environmental effects on fatigue. The applicant further stated that the cycle count 

action limits for the hot-leg surge nozzle will incorporate the 60-year cycle projections used in 

the hot-leg surge nozzle EAF analysis.

The “acceptance criteria” program element of GALL Report AMP X.M1 states the acceptance 

criterion is maintaining the cumulative fatigue usage below the design limit through the period of 
AGING MANAGEMENT REVIEW RESULTS

3-226

extended operation, with consideration of the reactor water environmental fatigue effects 

described in the program description and scope of program. 

The staff noted that establishing action limits provides the applicant sufficient time for activities 

such as resource use and planning future activities to ensure that corrective actions will be 

completed before the design limits, including EAF results, are exceeded. The staff finds that 

setting the action limit for both cycle counts and fatigue usage, such that actions are taken if the 

design limits are expected to be exceeded within the next three fuel cycles, to be conservative.

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

Fatigue Monitoring Program will establish action limits to ensure corrective actions are taken 

before a design limit, including EAF results, is exceeded during the period of extended 

operation, which is consistent with the GALL Report.

Enhancement 6. LRA Section B3.1 states an enhancement to the “corrective actions” program 

element. In this enhancement, the applicant stated that procedures will be enhanced to include 

appropriate corrective actions to be invoked if a component approaches a cycle count or CUF 

action limit or if an experienced transient exceeds the design transient definition. In addition, if 

an action limit is reached, corrective actions include fatigue reanalysis, repair, or replacement. 

The enhancement also stated that when a cycle counting action limit is reached, action will be 

taken to ensure that the analytical bases of the HELB locations are maintained. Furthermore, 

reanalysis of a fatigue crack growth analysis must be consistent with or reconciled to the 

originally submitted analysis and receive the same level of regulatory review as the original 

analysis.

The “corrective actions” program element of GALL Report AMP X.M1 states that the program 

provides for corrective actions to prevent the usage factor from exceeding the design code limit 

during the period of extended operation. Furthermore, acceptable corrective actions include 

repair of the component, replacement of the component, and a more rigorous analysis of the 

component to demonstrate that the design code limit will not be exceeded during the period of 

extended operation. 

The staff noted that the applicant proposed to include fatigue crack growth analyses, which 

support the LBB analyses, ASME Code Section XI evaluations, and the HELB break selection 

criterion. Since this portion of the applicant’s enhancement is beyond the recommendations of 

GALL Report AMP X.M1, the staff’s review was performed in accordance with SRP-LR 

Section A.1.2.3.7, “Corrective Actions,” which states that actions to be taken when the 

acceptance criteria are not met should be described in appropriate detail and if corrective 

actions permit analysis without repair or replacement, the analysis should ensure that the 

structure- and component-intended function(s) are maintained consistent with the CLB.

The staff noted that the applicant’s enhancement to the Fatigue Monitoring Program includes 

the specific corrective actions recommended in the GALL Report AMP X.M1, which include 

fatigue reanalysis, repair, or replacement. However, the staff also noted that Appendix B to 

10 CFR Part 50 requires measures to be taken to ensure that the cause of the condition is 

determined and corrective action is taken to preclude repetition. Thus, the corrective actions 

that may be implemented in accordance with the Fatigue Monitoring Program are not limited to 

fatigue reanalysis, repair, or replacement. In addition, since the applicant included an 

enhancement to the “scope of program” program element to include fatigue crack growth 

analyses, which support the LBB analyses, ASME Code Section XI evaluations, and the HELB 
AGING MANAGEMENT REVIEW RESULTS

3-227

break selection criterion in the Fatigue Monitoring Program, the staff finds it appropriate that the 

applicant identified corrective actions associated with these additional types of analyses. 

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP X.M1 and finds it acceptable because when it is implemented the Fatigue 

Monitoring Program will include corrective actions to ensure that the cause of the condition is 

determined and preclude repetition, specifically fatigue reanalysis, repair, or replacement of the 

affected component, which is consistent with the GALL Report. In addition, the staff finds this

enhancement acceptable because, consistent with SRP-LR Section A.1.2.3.7, the applicant 

identified appropriate correctives actions to take in order to maintain the components intended 

function(s) consistent with the CLB for the additional analyses included in the corresponding 

enhancement to the “scope of program” program element.

Enhancement 7. By letter dated April 26, 2013, the applicant revised LRA Section B3.1 to 

include an enhancement to the “parameters monitored or inspected” program element, which

states “[p]rocedures will be enhanced to limit the quantity of the most severe RCP component 

cooling water transient, elevated component cooling water (CCW) inlet temperature transients, 

to 75 percent of its design value, (i.e., limited to 150 transients), in order to accommodate the 

seasonal temperature change transient in the reactor coolant pump (RCP) thermal barrier 

flange fatigue analysis.”

The staff noted that the fatigue TLAA for the RCP thermal barrier flange was dispositioned in 

accordance with 10 CFR 54.21(c)(1)(iii), in that the effects of fatigue will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation. The staff’s 

review of the TLAA for the RCP thermal barrier flange is documented in SER Section 4.3.2.1.2. 

Specifically, the staff addresses the applicant’s ability to ensure that the accumulated fatigue 

usage for the RCP thermal barrier flange will not exceed the design limit without monitoring or 

confirmation that the number of occurrences of the seasonal temperature change transient will 

not exceed the design limit.

The staff noted that the revision to LRA Section B3.1 by letter dated April 26, 2013, was 

administrative in nature to ensure the procedures for the Fatigue Monitoring Program will be 

updated to clearly identify a specific limit for the elevated CCW inlet temperature transients to 

be 75 percent of its design value, (i.e., limited to 150 transients), in order to accommodate the 

seasonal temperature change transient in the RCP thermal barrier flange fatigue analysis. The 

staff’s evaluation of the applicant’s specified limit (of 75 percent of design value) for the elevated 

CCW inlet temperature transients is documented in SER Section 4.3.2.1.2.

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

Fatigue Monitoring Program will monitor for elevated CCW inlet temperature transients, which 

cause cyclic strains and contribute to the fatigue usage factor, and the program will have a 

specified limit for this transient to ensure that the design limit is not exceeded during the period 

of extended operation for the RCP thermal barrier flange fatigue analysis; otherwise, corrective 

actions will be taken.

Enhancement 8. By letter dated April 26, 2013, the applicant revised LRA Section B3.1 to 

include an enhancement to the “corrective actions” program element, which states that 

procedures will be enhanced to include non-NUREG/CR-6260 locations with a Uen greater than 

1.0 for further evaluation using the same methods as those used for NUREG/CR-6260 locations 

to remove conservatisms from the preliminary Uen. 
AGING MANAGEMENT REVIEW RESULTS

3-228

The results of these final analyses will be incorporated into the Fatigue Monitoring program by 

either counting the transients assumed or incorporating the stress intensities into a CBF ability 

of the program. As an alternative, the Fatigue Monitoring Program will implement SBFs of 

certain locations in order to ensure the component does not exceed a Uen of 1.0. Any use of 

SBF will be implemented consistent with RIS 2008-30.

The staff’s evaluation of the methods used for the NUREG/CR-6260 locations to remove 

conservatisms from the preliminary Uen are documented in SER Section 4.3.4.2 and were 

determined to be acceptable and reasonable. The staff noted that these methods are not 

unique to just the NUREG/CR-6260 locations; thus, these methods to refine the Uen values are 

also applicable to non-NUREG/CR-6260 reactor coolant pressure boundary locations 

associated with this enhancement.

The staff noted that after refinement of Uen values are completed, which is consistent with the 

“corrective actions” program element of GALL Report AMP X.M1, these fatigue analyses will be 

incorporated into the Fatigue Monitoring Program as part of this enhancement. The staff finds 

the inclusion of these fatigue analyses into the Fatigue Monitoring Program will ensure they 

remain valid through the period of extended operation by using cycle counting, CBF monitoring,

or SBF monitoring; otherwise, corrective actions will be taken. The staff’s evaluation of these 

monitoring methods is documented in SER Section 3.0.3.2.22. 

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

Fatigue Monitoring Program will prevent the usage factor, including environmental effects of 

reactor water, from exceeding the design code limit during the period of extended operation by 

performing a more rigorous analysis of the component to demonstrate that the design code limit 

will not be exceeded. In addition, the staff finds that the monitoring methods implemented by 

the Fatigue Monitoring Program ensure that the design code limit is not exceeded during the 

period of extended operation; otherwise, corrective actions will be taken.

Enhancement 9. By letter dated April 26, 2013, the applicant revised LRA Section B3.1 to 

include an enhancement to the “corrective actions” program element: “[t]he sentinel location 

analysis, when refined, will be revisited to confirm bounding Reactor Coolant Pressure 

Boundary Environmentally Assisted Fatigue susceptible sentinel locations are updated 

appropriately and remain bounded consistent with the refined analysis.” 

During the staff’s evaluation of the locations selected by the applicant for environmentally 

assisted fatigue monitoring as documented in SER Section 4.3.4.2, the staff noted that the 

refinement of a higher Uen may not ensure the reduction of the Uen for a bounded location, such 

that the conclusion from the common basis stress evaluation remains valid. Thus, the staff 

issued RAI 4.3-24 by letter dated March 26, 2013, requesting the applicant’s justification. In its 

response dated April 26, 2013, the applicant provided this enhancement. The staff’s review of 

the applicant’s response to RAI 4.3-24 is documented in SER Section 4.3.4.2.

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP X.M1 and finds it acceptable because when it is implemented the applicant‘s 

Fatigue Monitoring Program will confirm that, after the refinement of Uen values, the EAF 

locations monitored are appropriate to ensure environmentally assisted fatigue is managed 

through the period of extended operation.

Summary. Based on its audit of the applicant’s Fatigue Monitoring Program and review of the 

applicant’s responses to RAIs B3.1-1 and B3.1-2, the staff finds that program elements one 
AGING MANAGEMENT REVIEW RESULTS

3-229

through six for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP X.M1. In addition, the staff 

reviewed the enhancements associated with the “scope of program,” “preventive actions,” 

“parameters monitored or inspected,” “monitoring and trending,” “acceptance criteria,” and 

“corrective actions” program elements and finds that when implemented they will make the AMP 

adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B3.1 summarizes operating experience related to the 

Fatigue Monitoring Program. The staff noted that the applicant’s Fatigue Monitoring Program 

addressed generic operating experience as discussed below.

The applicant stated that Westinghouse performed a plant-specific evaluation of pressurizer 

surge line to address NRC Bulletin 88-11, “Pressurizer Surge Line Thermal Stratification.” This 

evaluation concluded that thermal stratification does not affect the integrity of the pressurizer 

surge line and, in the applicant’s response to NRC Bulletin 88-11, describes the inspections, 

analyses, and procedural revisions made to ensure that thermal stratification does not affect the 

integrity of the pressurizer surge line. The applicant also addressed NRC RIS 2008-30,

“Fatigue Analysis of Nuclear Power Plant Components,” which informed licensees of an 

analysis methodology used to demonstrate that compliance with the ASME Code fatigue 

acceptance criteria could be nonconservative if not correctly applied. The applicant addressed 

RIS 2008-30 by ensuring that a three-dimensional, six-component stress tensor method 

meeting ASME Code III NB-3200 requirements is used or by benchmarking its chosen method

with ASME Code III NB-3200 requirements. This benchmarking has been performed for the 

normal and alternate charging nozzle to implement SBF at that location. The staff noted that 

the applicant’s Fatigue Monitoring Program also addressed plant-specific operating experience. 

The applicant stated that an error was identified in the SBF transfer function for the normal and 

alternate charging nozzles, which incorrectly included thermal sleeves for the nozzles. The 

applicant confirmed that the extent of this condition is limited only to the normal and alternate 

charging nozzle SBF models, which subsequently have been updated to exclude thermal 

sleeves and benchmarked in accordance with NRC RIS 2008-30. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI, as 

discussed below.

During its audit, the staff reviewed the applicant’s evaluation of plant-specific and generic 

operating experience related to its Fatigue Monitoring Program. The “operating experience” 

program element of GALL Report AMP X.M1 recommends that the program review industry 

experience relevant to fatigue cracking. The staff noted that RIS 2011-14, “Metal Fatigue 

Analysis Performed by Computer Software,” was issued on December 29, 2011. This RIS is 

associated with the implementation of computer software packages used to demonstrate the 

ability of nuclear power plant components to withstand the cyclic loads associated with plant 

transient operations. Documentation of how the applicant addressed this recently issued RIS 

was not available to the staff during its audit; therefore, it is not clear if and how the applicant 

will address the issues discussed in RIS 2011-14.
AGING MANAGEMENT REVIEW RESULTS

3-230

The RIS states that the staff acknowledged that other computer software packages for 

performing ASME Code fatigue calculations may have or will be used by licensees; therefore, 

the staff encouraged licensees to review the documents discussed in the RIS and to consider 

actions, as appropriate, to ensure compliance with the requirements described in 

10 CFR 50.55a and Appendix B to 10 CFR Part 50, respectively. Since the staff’s concerns 

documented in the RIS were generic in nature to fatigue computer software, the staff noted 

during its audit that the applicant uses FatiguePro, which can perform cycle counting, CBF

monitoring, and SBF monitoring to manage cumulative fatigue damage. Thus, it was not clear if 

the data collected by FatiguePro is reviewed and modified before the determination of 

cumulative fatigue usage for a component or of an accrued transient cycle.

By letter dated June 22, 2012, the staff issued RAI B3.1-3 requesting the applicant to describe 

and justify any actions that have been or will be taken to address the concerns described in 

RIS 2011-14, related to the use of computer software to demonstrate the ability of components 

to withstand cyclic loads associated with transients and the documentation of analyst’s 

engineering judgment and intervention. The applicant was also requested to describe the 

activities that are performed to the information and data collected by FatiguePro before 

determining the cumulative fatigue usage for a component or an accrued transient cycle and to 

justify if the concerns described in RIS 2011-14 have been addressed for the current use or will 

be addressed for the future use of computer software for fatigue calculations.

In its response dated July 20, 2012, the applicant stated that Callaway’s CAP evaluated the 

RIS 2011-14 and concluded that it was specific to the WESTEMSTM Fatigue Monitoring Program 

software. The applicant stated that Callaway uses the FatiguePro Software to monitor fatigue 

usage and does not use WESTEMSTM. The applicant clarified that Westinghouse has used 

WESTEMSTM to support fatigue analysis for Callaway. Therefore, subsequent to the issuance of 

RIS 2011-14, Westinghouse issued a letter dated January 16, 2012, in response to 

RIS 2011-14, which determined “Westinghouse is able to demonstrate that the calculations 

generated for the operating plants which use the WESTEMSTM program have not misused 

algebraic summation or the peak and valley options and have met all ASME Code limits.” The 

applicant also stated that the following information was provided in Structural Integrity letter 

dated January 31, 2012, to document the impact of RIS 2011-14 on FatiguePro version 3:

The software installed at ... Callaway ... (FatiguePro version 3) does not use the 

algebraic summation of three orthogonal moment vectors nor does it permit 

modification of stress peaks and valleys (the two issues in the RIS). Thus, 

FatiguePro version 3 installed at (Callaway) is not affected by NRC RIS 2011-14. 

Specifically,

• FatiguePro version 3 does not perform NB-3600 analysis, so the concerns 

about how to calculate moment range in accordance with NB-3600 do not 

apply.

• FatiguePro version 3 does not have a manual stress peak/valley editor.

Therefore, the applicant stated that based on the response provided by Westinghouse and 

Structural Integrity letters, there is no adverse condition that exists for Callaway associated with 

RIS 2011-14. The applicant further stated that the peak and valley times selected by the 

WESTEMSTM algorithm in the Callaway fatigue analysis were reviewed and confirmed to be 

applicable and conservative and that this review is documented in the Westinghouse 

calculations. The staff finds it appropriate that the applicant evaluated the specific concerns 

documented in RIS 2011-14 as part of its CAP to determine its applicability to its plant. In 
AGING MANAGEMENT REVIEW RESULTS

3-231

addition, the staff finds it appropriate that the applicant’s vendors (i.e., Structural Integrity and 

Westinghouse) assessed the impact of RIS 2011-14 to its fatigue software on the applicant’s 

site and determined that the applicant’s site and fatigue calculations were not affected by the 

documented concerns.

The applicant further stated in its response that the only user manipulation that exists in the 

Fatigue Monitoring Program is to ensure that all transients were appropriately counted. The 

applicant described the three locations where the data was altered in some fashion in its 

FP-CALL-304, “Baseline Analysis of Callaway Plant Cycles and Fatigue Usage-Startup through 

1/31/2011.”

The first instance of user manipulation involved the revision to FatiguePro data files from 

May 11, 1995, through January 31, 2011, to expand the instrument list in these files to 

accommodate a software revision to FatiguePro. The applicant explained that this revision to 

the data files was necessary to properly work with the current FatiguePro version. The staff 

finds this user manipulation appropriate because it ensured that compatibility issues between 

revisions of the computer software were corrected and it was confirmed that the fatigue analysis 

was not affected. 

The second instance of user manipulation involved the correction to FatiguePro data files from 

May 11, 1995, through January 31, 2011, to remove instrument test data, drop-out points, and 

other obviously bad instrument data. The applicant stated that all data corrections are 

automatically logged by FatiguePro, which is retained with the supporting files of the baseline 

cycle and usage analysis. The applicant stated that this change was to ensure the accuracy of 

the data and to remove erroneous results that may trigger false positives. The staff finds this 

user manipulation acceptable because changes were made only to ensure accurate reflection of 

transient occurrences, and the Fatigue Monitoring Program currently includes a comparison of 

the actual severity and design severity of transients, as discussed in the applicant’s response to 

RAI B3.1-1.

The third instance of user manipulation involved reclassification of the charging and letdown 

transients. The applicant explained that these transients are sometimes difficult to classify 

accurately using the automatic cycle counting logic and multiple events can be recorded when 

only one event has occurred. Therefore, the recorded charging and letdown transients were 

inspected to determine whether they had been counted accurately and in some cases the 

transients were reclassified based on the thermal effect of the charging and letdown flows on 

the charging nozzle. The applicant confirmed that these reclassifications are documented in the 

baseline cycle and usage analysis to ensure accountability. The staff finds this documentation 

in the analysis appropriate because it provides sufficient details such that a person technically

qualified in the subject area can review and understand the reclassifications to verify the 

adequacy without recourse to the originator. The staff noted that the applicant’s Fatigue 

Monitoring Program currently includes a comparison of the actual severity and design severity 

of transients, as discussed in response to RAI B3.1-1, to properly classify transients and ensure 

that design limits are not exceeded.

The staff finds the applicant’s response to RAI B3.1-3 acceptable because the applicant 

evaluated recently issued industry operating experience and evaluated its impact on its plant. In 

addition, the staff finds the applicant’s response acceptable because the applicant evaluated the 

specific concerns associated with the WESTEMSTM software identified in RIS 2011-14 and the 

generic concerns associated with documentation of user involvement when using fatigue 

computer software. The staff’s concern described in RAI B3.1-3 is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-232

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

RAI B3.1-3, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective action. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP X.M1 was evaluated.

FSAR Supplement. LRA Section A2.1 provides the FSAR supplement for the Fatigue 

Monitoring Program. The staff reviewed this FSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR 

Table 3.0-1 and noted that it generally describes the key aspects of the program when 

implemented for the period of extended operation, which uses three monitoring methods 

(i.e., cycle counting, CBF fatigue monitoring, and SBF monitoring). However, the applicant’s 

FSAR supplement in LRA Section A2.1 did not include a description or discussion of how the 

monitoring methods will manage cumulative fatigue damage during the period of extended 

operation, which are key aspects to the applicant’s Fatigue Monitoring Program.

By letter dated June 22, 2012, the staff issued RAI B3.1-4 requesting the applicant to revise 

LRA Section A2.1 to provide a description of how each monitoring method of the program will 

manage fatigue. Otherwise, the applicant was asked to justify why a revision to LRA 

Section A2.1 to capture these key aspects of the Fatigue Monitoring Program is not needed.

In its response dated July 20, 2012, the applicant stated that LRA Section A2.1 was revised by 

letter dated June 5, 2012, to provide a description of the cycle counting, CBF, and SBF 

monitoring methods of the Fatigue Monitoring Program. The staff reviewed the applicant’s letter 

dated June 5, 2012, and confirmed that LRA Section A2.1 was amended to include a concise 

and accurate summary description of each monitoring method that manages metal fatigue to 

ensure the design limit of 1.0 is not exceeded during the period of extended operation. The 

staff’s review of each monitoring method is discussed above.

The staff finds the applicant’s response to RAI B3.1-4 acceptable because LRA Section A2.1 

was amended to contain a summary description of the three monitoring methods (i.e., cycle 

counting, CBF, and SBF) that the Fatigue Monitoring Program uses for managing metal fatigue 

during the period of extended operation in accordance with 10 CFR 54.21(d). The staff’s 

concern described in RAI B3.1-4 is resolved.

The staff also noted that the applicant committed (Commitment No. 31) to implement 

Enhancements 1 through 6 as captured in the FSAR supplement six months before the period 

of extended operation.

By letter dated October 17, 2013, the applicant amended LRA Section A2.1 to indicate that, in 

addition to considering the effects of the reactor water environment for a set that includes the 

NUREG/CR-6260 sample locations for a newer-vintage Westinghouse Plant and plant-specific 

bounding EAF locations in the reactor coolant pressure boundary, the applicant would include 

reactor vessel internals locations with fatigue usage calculations. The applicant indicated that 

the Fen factors will be determined as described in LRA Section A3.2.3 for reactor coolant 

pressure boundary components and reactor vessel internal locations. The staff noted LRA 

Section A3.2.3 identifies that NUREG/CR-6909 or NUREG/CR-6583 will be used for carbon and 

low alloy steels, NUREG/CR-6909 or NUREG/CR-5704 will be used for austenitic stainless 

steels, and NUREG/CR-6909 will be used for nickel alloys. The staff noted that, regardless of 

whether the components are reactor coolant pressure boundary or reactor vessel internals, they 

are both exposed to the same water environment. Thus, these components are impacted by 

environmentally assisted fatigue and the aforementioned NUREG reports are acceptable for use 
AGING MANAGEMENT REVIEW RESULTS

3-233

to address this aging effect. The staff finds the revision to LRA Section A2.1 acceptable 

because it clearly identifies the NUREG reports, which are consistent with those identified in the 

GALL Report, that will be used to address environmentally assisted fatigue for reactor coolant 

pressure boundary and reactor vessel internal components.

The staff finds that the information in the FSAR supplement, as amended by letters dated 

July 20, 2012, February 28, 2013, and October 17, 2013, is an adequate summary description 

of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fatigue Monitoring Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed 

that their implementation through Commitment No. 31 six months before the period of extended 

operation will make the AMP adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

FSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.23 Concrete Containment Tendon Prestress

Summary of Technical Information in the Application. LRA Section B3.3 describes the existing

Concrete Containment Tendon Prestress Program as consistent, with enhancements, with 

GALL Report AMP X.S1, “Concrete Containment Tendon Prestress.” The program manages 

the loss of tendon prestress aging effect in the post-tensioning system. The LRA states that the 

Concrete Containment Tendon Prestress Program is in accordance with Section XI 

Subsection IWL of the ASME B&PVC, 2001 Edition through the 2003 Addenda as required by 

10 CFR 50.55a, except where the NRC has authorized an exemption or relief. 

The LRA states that the containment is prestressed concrete, hemispherical dome-on-a-cylinder 

structures with a steel membrane liner and a flat foundation slab. The LRA states that 

ungrouted post-tensioned tendons inserted in ducts filled with anticorrosion petroleum grease 

permit the structures to withstand design basis accident internal pressures. The LRA also 

states that the vertical inverted U tendons are anchored through the bottom of the basemat. 

The LRA states that the program’s acceptance criterion is that measured tendon prestress must 

remain above or within a stated tolerance below the predicted lower limit (PLL) line for the 

vertical and hoop tendon groups and the PLL lines were developed from the loss of prestress 

model and are consistent with the proposed RG 1.35.1, “Determining Prestressing Forces for 

Inspection of Prestress Concrete Containments.” The program also ensures that the average 

tendon prestress and trend lines for the tendon groups remain above the design basis minimum 

required value (MRV) until the next scheduled surveillance. The LRA also states that the trend 

lines are generated with a regression analysis, consistent with IN 99-10, Revision1, 

“Degradation of Prestressing Tendon Systems in Prestressed Concrete Containments,” 

Attachment 3. For both tendon groups, the regression analysis demonstrated that prestress

should remain above the applicable MRVs for at least 60 years of operation; and that all 

tendons should, therefore, maintain their design basis function for the period of extended 

operation without retensioning. The LRA further states that the 5-year tendon surveillance 

required by the Callaway ASME Section XI Subsection IWL Program will continue to confirm 

that this is so for the period of extended operation. 
AGING MANAGEMENT REVIEW RESULTS

3-234

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP X.S1. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” and “monitoring and trending” program elements associated with enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B3.3 states an enhancement to the “scope of program” program 

element. In this enhancement, the applicant stated that “[t]he surveillance program specification 

will be enhanced to include random samples for the 40, 45, 50, and 55 year surveillances.” The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMP X.S1 and finds it acceptable because when it is implemented it will allow the periodic 

5-year surveillance, random sampling, and assessment of the containment tendon prestressing 

force, through plant procedure C-1003(Q), “Specification for Inservice Inspection of the 

Containment Building Post-Tensioning System and Exterior Concrete Shell,” to be continued 

into the period of extended operation. The surveillance, sampling, and assessment will 

contribute in the containment prestress force TLAA evaluation using 10 CFR 54.21(c)(1)(iii). 

Therefore, the inclusion of the enhancement will render the Concrete Containment Tendon 

Prestress Program “scope of program” program element consistent with the corresponding 

GALL Report AMP X.S1 program element.

Enhancement 2. LRA Section B3.3 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that “[t]he surveillance 

program specification will be enhanced to extend the PLL lines for the vertical and hoop tendon 

groups to 60 years.” The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP X.S1 and finds it acceptable because when it is implemented 

procedure C-1003(Q), “Specification for Inservice Inspection of the Containment Building 

Post-Tensioning System and Exterior Concrete Shell,” will be used to calculate the PLL lines 

consistent with RG 1.35.1, “Determining Prestressing Forces for Inspection of Prestress 

Concrete Containments,” for vertical and hoop tendon groups to 60 years. The staff finds that 

calculation of the PLL lines for 60 years is necessary to assess any abnormal degradation in 

actual tendon prestressing force, and the PLL constitutes the acceptance criteria for individual 

tendons. The difference between the PLL and the lift-off force is a measure of the degree of 

tendon relaxation or degradation. Lift-off forces less than the PLL, following 5-year lift-off test 

measurements in accordance with Section XI, Subsection IWL of the ASME B&PVC Code, as 

incorporated by reference in 10 CFR 50.55a, indicate potential abnormal relaxation or 

degradation in tendon prestressing force. Hence the inclusion of the enhancement will render 

the Concrete Containment Tendon Prestress Program, “parameters monitored or inspected” 

program element consistent with the corresponding GALL Report AMP X.S1 AMP program 

element. 

Enhancement 3. LRA Section B3.3 states an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that “[t]he surveillance program 

specification will be enhanced to specifically require the final report for each surveillance interval 

to plot the measured results against time and to include the PLL, MRV, and trend lines. The 

surveillance program specification will be enhanced to require a regression analysis consistent 

with the requirements of NRC IN 99-10 Revision 1, Attachment 3.” The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP X.S1 and finds 

it acceptable because when it is implemented the regression analysis lift-off trend lines 
AGING MANAGEMENT REVIEW RESULTS

3-235

calculated every 5 years through the period of extended operation will demonstrate whether the 

tendon prestressing force will remain above the MRV until the next scheduled surveillance. 

Hence, the inclusion of the enhancement will render the Concrete Containment Tendon 

Prestress Program, “monitoring and trending” program element consistent with the 

corresponding GALL Report AMP X.S1 program element.

Based on its audit and review of the applicant’s Concrete Containment Tendon Prestress 

Program, the staff finds that program elements one through six for which the applicant claimed 

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

GALL Report AMP XI.S4. In addition, the staff reviewed the enhancements associated with the 

“scope of program,” “parameters monitored or inspected,” and “monitoring and trending” 

program elements and finds that when implemented they will make the AMP adequate to 

manage the applicable aging effects.

Operating Experience. LRA Section B3.3 summarizes operating experience related to the 

Concrete Containment Tendon Prestress Program. The LRA states that the Callaway Concrete 

Containment Tendon Prestress Program to date did not identify any adverse trend in 

performance. The LRA states that the 25th year inspection report includes an examination and 

regression analysis incorporating the entire history of tendon prestress surveillance data, 

through the 2010 inspection, in accordance with NRC IN 99-10, Revision 1, “Degradation of 

Prestressing Tendon Systems in Prestressed Concrete Containments,” Attachment 3. The LRA 

also states that the regression analysis extends to 60 years and demonstrates that prestress in 

both the vertical and horizontal (“hoop”) tendon groups remain above the applicable MRVs for at 

least 60 years of operation and that all tendons, therefore, maintain their design basis function 

for the period of extended operation without retensioning. Similarly, no individual-tendon data 

from the “common tendons” (one vertical and one horizontal, whose prestress is measured at 

each surveillance), or from the other sample tendons tested to date, show a loss of prestress 

sufficient to indicate a possible need to retension for at least 60 years. The LRA also states that 

results of tendon surveillance to date indicate that the post- tensioning system will continue to 

meet its design criteria through the period of extended operation. 

The Callaway operating experience as audited demonstrates that it has been able to identify 

aging effects followed by corrective actions taken under the program. Occurrences identified 

under this program and corrective actions taken to prevent recurrence indicate that there is 

confidence that the continued implementation of the program will effectively identify aging 

before loss of intended function. For example, the staff noted during the audit that while in all 

prior surveillances the number of tendons examined followed guidance of RG 1.35 (a minimum 

of three tendons per group to be examined), the 20th-year surveillance for the hoop tendons 

failed to satisfy updated sampling requirements delineated in Table IWL-2521-1, Section XI, 

Subsection IWL of the ASME Code B&PVC and applicable addenda as required by 

10 CFR 50.55a. The surveillance sampled only three hoop tendons instead of the required four. 

Since it was impractical to perform an additional examination within 24 hours of the surveillance, 

per TS 5.5.6, the provisions of SR 3.0.3 were invoked and a risk evaluation was performed. 

The probabilistic risk assessment evaluation report concluded that the large early release 

frequency (LERF), which is the limiting risk metric for this application, would not appreciably 

increase the accumulated risk. Therefore, it was deemed acceptable to defer the examination 

and test to the next scheduled surveillance. The staff also noted that the applicant scheduled to 

implement necessary changes in its own procedures, specifications, and FSAR. The staff 

reviewed the 25th-year surveillance and noted that it sampled the correct number of vertical and 

hoop tendons. 
AGING MANAGEMENT REVIEW RESULTS

3-236

A further review by the staff of the 25th-year inspection report indicated that the applicant in its 

regression analysis initially did not include the 3rd-year tendon surveillance data. The staff noted 

that the applicant subsequently identified the missing data and, through its CAP, corrected the 

report. The predicted value for vertical tendons at 60 years without the 3rd-year data was 

1,405 kips instead of the corrected 1,401 kips. The predicted value for the horizontal tendons at 

60 years without the 3rd-year data was 1,322 kips instead of the corrected 1,317 kips. These 

constitute a variance of 0.3 percent and 0.4 percent, respectively, in the projected data. The 

staff also noted that the applicant reviewed the 90 percent confidence level lower bound for the 

predicted value (discussed in RG 1.35 and Section XI, Subsection IWL of the ASME Code 

B&PVC) and concluded that it remained unaffected. The staff further noted that 25th-year 

tendon surveillance properly initiated an engineering evaluation report through the plant’s CAP 

when samples of an examined tendon wire did not pass the required elongation test at failure. 

The tendon, however, met all of the acceptance criteria, including satisfactory visual 

examinations for anchorage, corrosion, defects, and grease replacement. No further action was 

taken as the maximum design stress of the tested tendon was higher than its ultimate strength. 

Finally the staff noted that the applicant, through a self-assessment performed in 2010, 

identified nonsafety-related improvement in its containment post-tensioning system surveillance 

process and concluded that the plant is in alignment with peer plants on programmatic 

requirements and inspection involved processes.

The staff reviewed the operating experience information in the application and during the audit 

to determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the audit report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective action. In addition, 

the staff finds that the conditions and operating experience at the plant are bounded by those for 

which GALL Report AMP X.S1 was evaluated.

FSAR Supplement. LRA Section A2.3 provides the FSAR supplement for the Containment 

Tendon Prestress Program. The staff reviewed this FSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 32) to enhance 

the Concrete Containment Tendon Prestress Program specification six months before the 

period of extended operation to:

• include random samples for the 40-, 45-, 50-, and 55-year surveillances 

• extend the PLL lines for the vertical and hoop tendon groups to 60 years 

• specifically require the final report for each surveillance interval to plot the measured 

results against time and to include the PLL, MRV, and trend lines

• require a regression analysis consistent with the requirements of NRC IN 99-10 

Revision 1, Attachment 3 
AGING MANAGEMENT REVIEW RESULTS

3-237

These actions will be taken so that the program will adequately manage aging of applicable 

components during the period of extended operation. 

The staff finds that the information in the FSAR supplement, as amended by letter dated 

February 28, 2013, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Concrete Containment 

Tendon Prestress Program, 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. 32 six months 

before the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. The staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the FSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report 

The applicant did not propose any AMPs not consistent with, or not addressed in, the GALL 

Report. 

3.0.3.4 Aging Management Related to Loss of Coating Integrity for Internal Coatings on 

In-Scope Mechanical SSCs

Based on reviews conducted by the staff, the staff identified an issue concerning loss of coating 

integrity of internal coatings of piping, piping components, heat exchangers, and tanks. By 

letters dated October 7, 2013, and March 25, 2014, the staff issued RAI 3.0.3-2 and 

RAI 3.0.3-2a, respectively, to address this loss of coating integrity. In its responses dated 

December 20, 2013, April 23, 2014, May 6, 2014, and June 5, 2014, the applicant revised the 

Fire Water System, Fuel Oil Chemistry, Open-Cycle Cooling Water System, and Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Programs to address loss 

of coating integrity of internal coatings of piping, piping components, heat exchangers, and 

tanks. The staff’s evaluation of this issue and the applicant’s responses are presented here. 

3.0.3.4.1 Staff Evaluation

Managing Loss of Coating Integrity for Internal Coatings of Piping, Piping Components, Heat 

Exchangers, and Tanks. Based on recent staff reviews of several LRAs and of industry OE, the 

staff has determined that additional recommendations beyond those in the GALL Report should 

be considered in regards to managing loss of coating integrity for internal coatings of piping, 

piping components, heat exchangers, and tanks. This section of the SER presents measures 

acceptable to the staff for addressing loss of coating integrity for internal coatings and evaluates 

the applicant’s responses to staff RAIs in this regard. 

The staff has identified the following considerations:

• Periodic visual inspections of coatings to detect blistering, cracking, flaking, peeling, 

delamination, rusting, spalling (for cementitious coatings), and physical damage should 

be conducted. For purposes of license renewal, physical damage would be limited to 

age-related mechanisms such as that occurring downstream of a throttled valve as a 

result of cavitation versus damage caused by inspection activities (e.g., chipping of the 
AGING MANAGEMENT REVIEW RESULTS

3-238

coating due to installation of scaffolding, removal and reinstallation of inspection ports). 

Inspections are conducted for each coating material and environment combination. The 

coating environment includes both the environment inside the component (e.g., raw 

water) and the metal to which the coating is attached. 

• Baseline inspections should be conducted in the 10-year period prior to the period of 

extended operation. Subsequent inspections should be based on the results of these 

and follow-on inspections as follows:

(a) If no peeling, delamination, blisters, or rusting is observed during 

inspections, and cracking, flaking, or spalling (in cementitious coatings) 

has been found acceptable, subsequent inspections should be 

conducted 6 years after the most recent inspection. Peeling, 

delamination, blisters, or rusting can be indicative of loss of adhesion 

that could result in the coating becoming debris or not being able to 

perform a corrosion deterrence function. Cracking, flaking, or spalling, 

although indicators to some degree of coating degradation, are not 

significant enough to require more frequent inspections as long as the 

condition has been found acceptable by qualified personnel. For 

example, despite cracking being found, the base metal could still be 

isolated from the environment and the coating retain sufficient integrity 

so as not to become debris.

(b) If the prior inspection results do not meet (a) above and a coatings 

specialist has determined that no remediation is required, subsequent 

inspections should be conducted 4 years after the most recent 

inspection. More frequent inspections are warranted to confirm the 

coatings specialist’s evaluation. If two sequential subsequent 

inspections demonstrate no change in coating condition, subsequent 

inspections may be conducted at 6-year intervals.

(c) Given that coatings in redundant trains are exposed to the same 

environment, the inspection interval may be extended to 12 years as 

long as: (a) the identical coating material was installed with the same 

installation requirements in redundant trains (e.g., piping segments, 

tanks) with the same operating conditions and at least one of the trains 

is inspected every 6 years and (b) the coating is not in a location subject 

to turbulence that could result in mechanical damage to the coating.

(d) Given that the coatings installed on the internal surfaces of diesel fuel 

oil storage tanks are generally exposed to a static environment, the 

inspection interval may be conducted in accordance with GALL Report 

AMP XI.M30, “Fuel Oil Chemistry,” as long as the inspection results 

meet (a) above.

• The extent of inspections should include all accessible tank and heat exchanger internal 

surfaces. The staff recognizes that, for piping, extensive amounts of coating could be 

installed. GALL Report AMPs such as XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” are based on sampling a portion of the 

population. The staff recommends the use of a sampling-based extent of inspections 

for coatings installed on the internal surfaces of piping. Where documentation exists that 
AGING MANAGEMENT REVIEW RESULTS

3-239

manufacturer recommendations and industry consensus documents (i.e., those 

recommended in RG 1.54, “Service Level I, II, and III Protective Coatings Applied to 

Nuclear Plants” or earlier versions of those standards) were used during installation, the 

extent of piping inspections may be twenty-five 1-foot axial length circumferential 

segments of piping or 20 percent of the total length of each coating material and 

environment combination. This extent of sampling is consistent with several GALL 

Report AMPs. However, where documentation does not exist that manufacturer 

recommendations and industry consensus documents were used during installation, the 

staff recommends that a larger extent of inspection be considered, for example, a 

sample consisting of seventy-three 1-foot axial length circumferential segments of piping 

or 50 percent of the total length of each coating material and environment combination. 

Regardless of the extent of inspections, the inspection surface should include the entire 

inside surface of the 1-foot sample. If geometric limitations impede movement of remote 

or robotic inspection tools, the number of inspection segments should be increased in 

order to cover an equivalent length.

• The staff recommends that, where loss of coating integrity cannot result in downstream 

effects such as reduction in flow, drop in pressure, or reduction in heat transfer for 

in-scope components, a representative sample of external wall thickness measurements 

could be used to confirm the acceptability of the corrosion rate of the base metal in lieu 

of visual inspections of the coating. The wall thickness measurements are an 

appropriate method to manage loss of coating integrity in this case because base metal 

corrosion is the only effect of loss of coating integrity.

• RG 1.54 provides one method acceptable to the staff for training and qualification of 

individuals involved in coating inspections and evaluating degraded conditions.

• A preinspection review of the previous two inspections should be conducted, including 

reviewing the results of inspections and any subsequent repair activities. A coatings 

specialist should prepare the post-inspection report to include: a list and location of all 

areas evidencing deterioration, a prioritization of the repair areas into areas that must be 

repaired before returning the system to service and areas where repair can be 

postponed to the next refueling outage, and where possible, photographic 

documentation indexed to inspection locations. When corrosion of the base material is 

the only issue related to coating degradation of the component and external wall 

thickness measurements are used in lieu of internal visual inspections of the coating, the 

corrosion rate of the base metal should be trended. These recommendations are 

consistent with ASTM D7167-05, “Standard Guide for Establishing Procedures to 

Monitor the Performance of Safety-Related Coating Service Level III Lining Systems in 

an Operating Nuclear Power Plant,” which is referenced in RG 1.54.

• Based on the staff’s review of industry documents (e.g., ASTM, EPRI) the staff has 

concluded that, with the exception of Service Level I qualification testing, there are no 

acceptance criteria in recognized industry consensus documents for degraded coatings. 

Acceptance of degraded coatings is typically established by the coatings specialist. RG 

1.54 states that for Service Level I coatings: (a) peeling and delamination shall not be 

permitted, (b) cracking is not considered a failure unless it is accompanied by 

delamination or loss of adhesion, and (c) blisters shall be limited to intact blisters that are 

completely surrounded by sound coating bonded to the surface. The staff recommends 

the following acceptance criteria for loss of coating integrity based on the guidance in 

RG 1.54. 
AGING MANAGEMENT REVIEW RESULTS

3-240

(a) Indications of peeling and delamination are not acceptable and the coating is 

repaired or replaced. 

(b) Blisters can be evaluated by a coatings specialist qualified in accordance with an 

ASTM International standard endorsed in RG 1.54 including staff guidance 

associated with use of a particular standard. Blisters should be limited to a few 

intact small blisters which are completely surrounded by sound coating bonded to 

the substrate. If the blister is not repaired, physical testing (e.g., lightly tapping 

the coating, adhesion testing) should be conducted to ensure that the blister is 

completely surrounded by sound coating bonded to the surface. Acceptance of a 

blister to remain in-service should be based both on the potential effects of flow 

blockage and degradation of the base material beneath the blister.

(c) If coatings are credited for corrosion prevention (e.g., corrosion allowance in 

design calculations is zero, the “preventive actions” program element credited the 

coating) and the base metal has been exposed or it is beneath a blister, the 

component’s base material in the vicinity of the degraded coating should be 

examined to determine if the minimum wall thickness is met and will be met until 

the next inspection.

(d) Indications such as cracking, flaking, and rusting are to be evaluated by a 

coatings specialist qualified in accordance with an ASTM International standard 

endorsed in RG 1.54 including staff guidance associated with use of a particular 

standard.

(e) Minor cracking and spalling of cementitious coating is acceptable provided there 

is no evidence that the coating is debonding from the base material.

(f) As applicable, wall thickness measurements meet design minimum wall 

requirements.

(g) Adhesion testing results, when conducted, meet or exceed the degree of 

adhesion recommended in engineering documents specific to the coating and 

substrate.

• Coatings that do not meet acceptance criteria should be repaired or replaced. Testing or 

examination should be conducted to ensure that the extent of repaired or replaced 

coatings encompasses sound coating material. These recommendations are consistent 

with ASTM D7167-05, “Standard Guide for Establishing Procedures to Monitor the 

Performance of Safety-Related Coating Service Level III Lining Systems in an Operating 

Nuclear Power Plant,” which is referenced in RG 1.54.

By letter dated October 7, 2013, the staff issued RAI 3.0.3-2 requesting that, if coatings have 

been installed on the internal surfaces of in-scope components (i.e., piping, piping 

subcomponents, heat exchangers, and tanks), the applicant state the inspection method, when 

inspections will commence and the frequency of subsequent inspections, the extent of 

inspections, the training and qualification of individuals involved in coating inspections, how 

trending of coating degradation will be conducted, acceptance criteria, and corrective actions for 

coatings that do not meet acceptance criteria.

The applicant responded to RAI 3.0.3-2 by letter dated December 20, 2013. The following 

sections address the aspects of that response and the staff’s evaluation. 
AGING MANAGEMENT REVIEW RESULTS

3-241

Visual Inspections. The applicant stated that visual inspections will be conducted to detect 

blistering, cracking, peeling, or delamination.

The staff finds this portion of the RAI response acceptable because visual inspections are an 

effective means to detect these types of potential coating degradation.

Baseline Inspections. The applicant stated that baseline inspections will be conducted during 

the 10-year period prior to the period of extended operation. Subsequent inspections will be as 

follows: (a) if no peeling, delamination, blisters, or rusting is observed, and any cracking or 

flaking has been found to be acceptable based on an evaluation by the coatings specialist, 

inspections will occur once every 6 years; (b) if no indications are found during the inspection of 

one train, the redundant train will not be inspected; (c) if the inspection results do not meet the 

conditions described in (a) and a coatings specialist determines that no remediation is required, 

inspections will occur every other refueling outage; and (d) repaired, replaced, or newly installed 

coatings will be inspected in each of the following two refueling outages. In its response to 

RAI 3.0.3-2a Request (2), the applicant supported this approach for fuel oil storage tanks by 

stating that these tanks do not experience turbulent flow conditions.

The staff noted that, if no indications are found during inspection of one train, the redundant 

train would not need to be inspected as long as components within the redundant trains are not 

subject to turbulent conditions. By letter dated March 25, 2014, the staff issued RAI 3.0.3-2a 

Request (1) requesting that the applicant state the basis for why turbulent conditions sufficient 

to degrade internal coatings on the in-scope heat exchangers, air conditioners, and strainers 

described in the RAI response cannot occur.

In its response dated April 23, 2014, the applicant did not fully respond to RAI 3.0.3-2a Request 

(1); however, as amended by letter dated May 6, 2014, the applicant stated that the baseline 

inspection results will be used to determine if loss of coating integrity has occurred as a result of 

turbulent flow conditions. If there is evidence of turbulent conditions causing loss of coating 

integrity, the redundant train will be inspected, and the alternating train inspection frequencies 

will not be utilized. By letter dated June 5, 2014, the applicant amended the Open-Cycle 

Cooling Water System and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Programs (LRA Section B2.1.10 and B2.1.23) and Commitment No. 6 to state that 

the provision to conduct inspections every 6 years on an alternating train basis is based on no 

observed degradation or cracking and flaking that has been evaluated as acceptable, and the 

component is not subject to turbulent flow.

The staff finds the applicant’s response acceptable because: (a) baseline inspections will be 

conducted prior to entering the period of extended operation in order to provide insight into the 

condition of coatings after many years of service; (b) subsequent inspection intervals will be 

based on the results of prior inspections such that where degraded coatings are noted, more 

frequent inspections will occur; (c) the maximum inspection intervals are consistent with staff 

recommendations for managing loss of coating integrity; (d) conducting alternating inspections 

of redundant trains when no indications are detected in prior inspections and turbulent flow 

conditions do not exist is consistent with staff recommendations for managing loss of coating 

integrity; (e) given that there will have been at least 30 years of service, the applicant will be 

able to determine whether turbulent flow conditions sufficient to cause coating degradation is 

occurring; and (f) it is reasonable to assume that turbulent flow conditions would not exist in the 

fuel oil storage tanks due to their large volume. The staff’s concern regarding this portion of 

RAI 3.0.3-2 (inspection intervals) and RAI 3.0.3-2a Request (1) is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-242

Coating Inspections. The applicant stated that coating inspection activities will be included in 

the following programs:

Aging Management Program Components

Fire Water System Fire water storage tanks

Fuel Oil Chemistry Fuel oil storage tanks

Open-Cycle Cooling Water System

Component cooling water heat exchangers, electrical 

equipment air conditioners, control room air conditioners, 

essential service water self-cleaning strainers

Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components

Service water pump strainers

The staff’s evaluation of the aging management approach for each of the above components 

follows.

Fire Water Storage Tanks. The applicant stated that the interior surfaces of the fire water 

storage tanks will be inspected every other refueling outage interval. The staff noted that, as 

documented in SER Section 3.0.3.2.7, Enhancement No. 12, the applicant has revised the Fire 

Water System Program to include the augmented inspections in NFPA 25, “Inspection Testing 

and Maintenance of Water-Based Fire Protection Systems,” Section 9.2.7 whenever pitting, 

corrosion, or coating failure is detected during internal visual inspections of the fire water 

storage tanks. The staff finds the Fire Water System Program acceptable to manage loss of 

coating integrity for the fire water storage tanks because the frequency of inspections are 

consistent with staff recommendations for managing loss of coating integrity and the augmented 

inspections of NFPA 25 Section 9.2.7 (e.g., adhesion testing, wet-sponge testing, dry film 

thickness readings) are sufficient to determine the condition of the coatings.

Fuel Oil Storage Tanks. LRA Section B2.1.16 states that, at least once every 10 years, each 

diesel fuel tank is drained and cleaned, and the internal surfaces are visually inspected. The 

staff has concluded that coating inspections for diesel fuel oil storage tanks may be conducted 

at the frequency stated in the Fuel Oil Chemistry Program (i.e., 10 years) as long as: (a) no 

peeling, delamination, blisters, or rusting are observed during inspections; and (b) any cracking 

and flaking has been found acceptable by a coatings specialist. If this is not the case, 

inspections should be conducted more frequently. The staff noted that the Fuel Oil Chemistry 

Program was not revised to include activities associated with coatings inspections 

(e.g., acceptance criteria, inspector qualifications). By letter dated March 25, 2014, the staff 

issued RAI 3.0.3-2a Request (2) requesting that the applicant: (a) state the periodicity of 

inspections, and basis for the periodicity of inspections if the prior inspection detected peeling, 

delamination, blisters, rusting, or unacceptable cracking and flaking; and (b) state how activities 

associated with coatings inspections (e.g., acceptance criteria, inspector qualifications) will be 

managed given that they are not included in the Fuel Oil Chemistry Program.

In its response dated April 23, 2014, the applicant revised LRA Section B2.1.16 to state: 

(a) visual inspections are performed on all accessible internal surface coatings of the diesel fuel 

oil storage tanks and day tanks; (b) baseline inspections will be conducted in the 10-year period 

prior to the period of extended operation; (c) coatings are inspected every 6 years on an 
AGING MANAGEMENT REVIEW RESULTS

3-243

alternating train basis; (d) coatings with blisters, peeling, delaminations, or rusting that have 

been determined not to require remediation are inspected on a 4-year frequency; (e) when 

peeling, delaminations and blisters are determined to not meet the acceptance criteria and that 

the degraded coating will not be repaired or replaced, physical testing (i.e., destructive or 

nondestructive adhesion testing using ASTM International Standards endorsed in RG 1.54, is 

performed where physically possible (i.e., sufficient room to conduct testing); (f) monitoring and 

trending of coatings is based on a review of the previous two inspections results (including 

repairs) with the current inspection results; and (g) the training and qualification of individuals 

involved in coating inspections are conducted in accordance with ASTM International Standards 

endorsed in RG 1.54 including guidance from the staff associated with a particular standard. 

Acceptance criteria includes: (a) indications of peeling and delamination are not acceptable, 

and the coatings are repaired or replaced; (b) blisters are evaluated by a coatings specialist 

qualified in accordance with an ASTM International standard endorsed in RG 1.54, including 

staff guidance associated with use of a particular standard; (c) indications such as cracking, 

flaking, and rusting are to be evaluated by a coatings specialist qualified in accordance with an 

ASTM International standard endorsed in RG 1.54, including staff guidance associated with use 

of a particular standard; and (d) adhesion testing results meet or exceed the degree of adhesion

recommended in engineering documents specific to the coating and substrate. Inspection 

results not meeting the acceptance criteria will be evaluated by a qualified coatings evaluator 

and corrective actions will be determined using the Corrective Action Program.

The staff finds the applicant’s response and proposal to use the Fuel Oil Chemistry Program to 

manage loss of coating integrity for the fuel oil storage tanks acceptable because the inspection 

frequencies and activities associated with coatings inspections are consistent with staff 

recommendations for managing loss of coating integrity. The staff’s concern described in RAI 

3.0.3-2a Request (2) is resolved.

Heat Exchangers, Air Conditioners, and Strainers. The applicant stated that 100 percent of the 

accessible interior surfaces of these components will be inspected. LRA Sections A1.10, A1.23, 

B2.1.10, and B2.1.23 were revised to include managing loss of coating integrity. However, the 

staff noted that the FSAR supplements and programs did not include all of the key aspects of 

the program associated with coating degradation. By letter dated March 25, 2014, the staff 

issued RAI 3.0.3-2a Request (5) and Request (6) requesting that the applicant state why LRA 

Sections A1.10 and A1.23 do not include a summary description of the followup testing that will 

be conducted when degradation is determined not to meet acceptance criteria, and state the 

basis for the training and qualification of individuals involved in coating inspections. The staff 

also requested that the applicant justify why LRA Sections B2.1.10 and B2.1.23 do not include: 

(a) when baseline inspections will be conducted; (b) the inspection interval for subsequent

inspections; (c) the extent of inspections; (d) qualifications for individuals performing activities 

associated with coating inspections; (e) a summary description of how monitoring and trending 

of the coatings will be conducted; (f) acceptance criteria; and (g) a summary description of 

corrective actions when coating degradation is detected.

In its response dated April 23, 2014, the applicant revised LRA Sections B2.1.10 and B2.1.23 to 

include the same level of detail as described above for the Fuel Oil Chemistry Program. In 

addition, LRA Section B2.1.23 was revised to state that, for the service water piping from the 

circulating and service water pump house to the ESW system connection, 

seventy-three 1-foot axial length circumferential segments of piping will be inspected in each 

inspection interval. The applicant also revised LRA Sections A1.10 and A1.23 to include a 

summary description of the followup testing that will be conducted when degradation is 
AGING MANAGEMENT REVIEW RESULTS

3-244

determined not to meet acceptance criteria and the basis for the training and qualification of 

individuals involved in coating inspections.

The staff finds the applicant’s response and proposal to use the Open-Cycle Cooling Water 

System and Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Programs to manage loss of coating integrity for the component cooling water heat exchangers, 

electrical equipment air conditioners, control room air conditioners, essential service water 

self-cleaning strainers, and service water pump strainers acceptable because the activities 

associated with coatings inspections are consistent with staff recommendations for managing 

loss of coating integrity. The staff’s concerns described in RAI 3.0.3-2a Request (5) and 

Request (6) are resolved.

Training and Qualification of Personnel. Regarding the training and qualification of personnel 

performing the inspections, the applicant stated that coating inspections will be performed by 

individuals qualified to ANSI N45.2.6, “Qualification of Inspections, Examinations, and Testing 

Personnel for Nuclear Power Plants.” Inspection reports will be provided to the site coatings 

coordinator for evaluation. The site coatings coordinator will be qualified consistent with 

ASTM D7108-5, “Standard Guide for Establishing Qualifications for a Nuclear Coating 

Specialist.”

The staff noted that qualifications meeting the recommendations in Regulatory Guide (RG) 1.54, 

“Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear 

Power Plants,” are consistent with staff recommendations for managing loss of coating integrity. 

The staff finds this portion of the response to RAI 3.0.3-2 (training and qualification) acceptable 

because the use of D7108-5 is endorsed by RG 1.54 and ANSI N45.2.6 certification is an 

acceptable basis for qualifying coatings inspectors based on RG 1.54, June 1973, Section C.1, 

which endorses conformance to the ANSI N45.2 quality assurance standards. 

Monitoring and Trending of Results. The applicant also stated that monitoring and trending will 

include the review of previous inspection results prior to performing the inspections and 

inspection results will be compared to previous inspection results.

The staff noted that the program does not state who will prepare the post-inspection report nor 

the details that will be included in the report. By letter dated March 25, 2014, the staff issued 

RAI 3.0.3-2a Request (7), requesting that the applicant state who will prepare and approve 

post-inspection reports and the key information that will be included in the report.

In its response dated April 23, 2014, the applicant stated that a coatings specialist prepares and 

approves the post-inspection report. The response also states that the report includes a list and 

location of all areas evidencing deterioration, a prioritization of the repair areas into areas that 

must be repaired before returning the system to service and areas where repair can be 

postponed to the next refueling outage, and where possible, photographic documentation 

indexed to inspection locations.

The staff finds the applicant’s response and proposal to trend coating degradation acceptable 

because they are consistent with staff recommendations for managing loss of coating integrity. 

The staff’s concern described in RAI 3.0.3-2a Request (7) is resolved.

Acceptance Criteria. The applicant stated that acceptance criteria would be as follows: 

(a) peeling and delaminations are not permitted; (b) cracking is not permitted if accompanied by 

delamination or loss of adhesion; (c) blisters are limited to intact blisters with testing being 

performed to confirm that the blister is surrounded by coating that is bonded to the base 
AGING MANAGEMENT REVIEW RESULTS

3-245

material; and (d) localized areas of coating degradation without subsequent loss of material of 

the base metal are considered acceptable if the area is completely surrounded by sound coating 

bonded to the surface.

The staff lacked sufficient information to conclude that the proposed followup testing would be 

sufficient to provide reasonable assurance that a component would be able to perform its 

current licensing basis intended function(s). By letter dated March 25, 2014, the staff issued 

RAI 3.0.3-2a Request (3), requesting that the applicant state what testing will be performed 

when peeling, delamination or blisters are detected during inspections and the coating is not 

repaired or replaced, and how it will be determined that a repair or replacement of a coating is 

extended to sound coating material.

In its response dated April 23, 2014, the applicant stated the following:

For peeling, delaminations and blisters determined to not meet acceptance 

criteria and that will not be repaired or replaced, physical testing is performed 

where physically possible (i.e., sufficient room to conduct testing). Testing 

consists of destructive or nondestructive adhesion testing using ASTM 

International Standards endorsed in RG 1.54, “Service Level I, II, and III 

Protective Coatings Applied to Nuclear Plants.” For repaired or replaced coating, 

a minimum of three sample points adjacent to the defective area are tested to 

verify sound coating material.

The staff noted that the applicant did not revise its programs to state that three sample points 

would be tested to verify sound coating material. However, the staff noted that testing three 

points is the industry standard (e.g., ASTM D4541, “Standard Test Method for Pull-Off Strength 

of Coatings Using Portable Adhesion Testers,” ASTM D7234 “Standard Test Method for Pull-Off 

Adhesion Strength of Coatings on Concrete Using Portable Pull-Off Adhesion Testers”). The 

staff finds the applicant’s response acceptable because it is consistent with staff 

recommendations for managing loss of coating integrity. The staff’s concern described in RAI 

3.0.3-2a Request (3) is resolved.

Crediting Coatings for Corrosion Prevention. The staff recommends that if coatings are credited 

for corrosion prevention and the component’s base material has been exposed or is beneath a 

blister, the base metal should be examined to determine if minimum wall thickness is met and 

will be met until the next inspection. By letter dated March 25, 2014, the staff issued RAI 

3.0.3-2a Request (4) requesting that the applicant state: (a) whether a component’s base 

material will be inspected if its coatings have been credited for corrosion prevention and the 

base metal has been exposed or is beneath a blister, and (b) the inspection method and 

acceptance criteria. The staff also requested that, if inspections will not be conducted, the 

applicant state the basis for why there is reasonable assurance that the current licensing basis 

intended function of the component will be met.

In its response dated April 23, 2014, the applicant stated, “[n]one of the internally coated 

components within the scope of license renewal have credited the coatings for corrosion 

prevention either in a documented corrosion allowance in a design analysis or as a preventative 

action in an aging management program.” The applicant also stated that, if the base metal is 

exposed due to coating degradation, the applicable inspection requirements for management of 

loss of material in the component will apply and blisters will be evaluated by a qualified coatings

specialist to determine extent of coating degradation and exposure of the base metal.
AGING MANAGEMENT REVIEW RESULTS

3-246

The staff noted that: (a) the coatings have not been credited for corrosion prevention in the 

in-scope component’s design analyses; (b) if the base metal is exposed, followup inspections 

will occur; and (c) qualified personnel will evaluate the condition of the blisters. The staff finds 

the applicant’s response acceptable because the potential for through-wall corrosion is minimal 

because the coatings were not credited in the design of the component and the followup 

examinations of the base metal and blister are capable of detecting the extent of base metal 

degradation. The staff’s concern described in RAI 3.0.3-2a Request (4) is resolved.

The staff noted that the applicant addressed rusting in its response to RAI 3.0.3-2a Request (1) 

which stated that, “[c]oatings with blisters, peeling, delaminations or rusting that has been 

determined not to require remediation are inspected on a four year frequency,” and Request (2), 

included the term in each of the applicable programs. The staff finds this portion of the 

response to RAI 3.0.3-2 (acceptance criteria) acceptable because it is consistent with staff 

recommendations for managing loss of coating integrity.

Corrective Actions. In regard to corrective actions, the applicant stated that inspection results 

that do not meet acceptance criteria will be evaluated by the site coatings coordinator. The 

applicant also stated that corrective actions may include repair, replacement, or continued 

monitoring.

The staff finds this portion of the response to RAI 3.0.3-2 (corrective actions) acceptable 

because it is consistent with staff recommendations for managing loss of coating integrity. 

During its review of the response to RAI 3.0.3-2, the staff noted that the applicant cited loss of 

material as the applicable aging effect for new AMR items associated with internal coatings in 

LRA Tables 3.3.2-4, 3.3.2-5, 3.3.2-7, 3.3.2-11, 3.3.2-20, and 3.3.2-21. By letter dated 

March 25, 2014, the staff issued RAI 3.0.3-2a Request (8) requesting that the applicant state 

why the term “loss of material” as an aging effect for coatings is sufficient to convey the 

consequential concepts of unanticipated or accelerated corrosion and debris generation, or 

revise the aging effect to loss of coating integrity in the cited AMR tables.

In its response dated April 23, 2014, the applicant revised 3.3.2-4, 3.3.2-5, 3.3.2-7, 3.3.2-11, 

3.3.2-20, and 3.3.2-21 to identify loss of coating integrity as the applicable aging effect. The 

applicant also stated that loss of coating integrity is only applicable to the service water supply 

piping that connects to the essential service water system supply piping. Loss of coating 

integrity is not applicable to the service water and circulating water system return piping 

downstream of in-scope essential service water components because degraded coatings 

cannot result in downstream effects (e.g., reduction in flow, drop in pressure, reduction in heat 

transfer) for in-scope components. Also, the internal coating for the service water and 

circulating water return line is not credited for corrosion prevention.

The staff finds the applicant’s response acceptable because the appropriate aging effect has 

been identified in the AMR tables, and for the service water and circulating water system return 

piping downstream of in-scope essential service water components, the staff agrees that loss of 

coating integrity is not an applicable aging effect because degraded coatings in these portions 

of the systems would not result in downstream effects and, in regard to loss of base material, 

the coatings were not credited for corrosion prevention. The staff’s concern described in 

RAI 3.0.3-2a Request (8) is resolved.

Summary. In summary, the staff finds the applicant’s responses to RAI 3.0.3-2 and 

RAI 3.0.3-2a acceptable as documented in the staff’s evaluation of each portion of the RAI 

responses above.
AGING MANAGEMENT REVIEW RESULTS

3-247

3.0.3.4.2 Conclusion

On the basis of its technical review of the applicant’s changes to the Open-Cycle Cooling Water 

System, Fire Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Programs to address loss of coating integrity, 

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 FSAR supplement for these AMPs and concludes that they provide an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

3.0.4.1 Summary of Technical Information in the Application

In LRA Appendix A, Section A1, “Summary Description of Aging Management Programs,” and 

Appendix B, Section B.1.3, “Quality Assurance Program and Administrative Controls,” the 

applicant described the elements of corrective action, confirmation process, and administrative 

controls that are applied to the AMPs for both safety-related and nonsafety-related components.

LRA Appendix A, Section A1 states: 

Three elements common to all aging management programs discussed in 

Sections A1 and A2 are corrective actions, confirmation process, and 

administrative controls. These elements are included in the Callaway Plant QA 

Program, which implements the requirements of 10 CFR Part 50, Appendix B. 

The Callaway Plant QA Program is applicable to safety-related systems, 

structures and components that are subject to aging management review 

activities for license renewal. These three elements will also be applied to the 

nonsafety-related systems, structures, and components subject to aging 

management activities after enhancement to existing Callaway procedures.

LRA Appendix B, Section B.1.3 states: 

The corrective action, confirmation process, and administrative controls, of the 

Callaway (10 CFR Part 50, Appendix B) Quality Assurance Program are 

applicable to all systems, structures, and components (SSCs) subject to aging 

management programs and activities required during the period of extended 

operation. 

Procedures will be enhanced apply the elements of corrective actions, 

confirmation process, and administrative controls of the Callaway Plant Quality 

Assurance program to those nonsafety-related SSCs requiring aging 

management. 

3.0.4.2 Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects 

of aging on SCs subject to an AMR will be adequately managed so that their intended functions 

will be maintained consistent with the CLB for the period of extended operation. The SRP-LR, 

Branch Technical Position RLSB-1, “Aging Management Review - Generic,” describes 

10 attributes of an acceptable AMP. Three of these 10 attributes are associated with the 
AGING MANAGEMENT REVIEW RESULTS

3-248

QA activities of corrective action, confirmation process, and administrative controls. 

Table A.1-1, “Elements of an Aging Management Program for License Renewal,” of Branch 

Technical Position RLSB-1 provides the following description of these quality attributes:

• Attribute No. 7 - Corrective Actions, including root cause determination and prevention of 

recurrence, should be timely

• Attribute No. 8 - Confirmation Process, should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective

• Attribute No. 9 - Administrative Controls, 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 SSCs are subject to the 

QA requirements of 10 CFR Part 50, Appendix B. Additionally, for nonsafety-related SCs 

subject to an AMR, the applicant's existing 10 CFR Part 50, Appendix B, QA Program may be 

used to address the elements of corrective action, confirmation process, and administrative 

control. Branch Technical Position IQMB-1 gives 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 Appendix A, Section A1, and Appendix B, Section B.1.3, of the LRA, which 

describe how the existing Callaway QA Program includes the QA-related elements (corrective 

action, confirmation process, and administrative controls) for AMPs consistent with the staff’s 

guidance described in Branch Technical Position IQMB-1. The staff also reviewed a sample of 

AMP program basis documents and confirmed that the AMPs implement the CAP, confirmation 

processes, and administrative controls as described in the LRA. Based on its review, the staff 

determined that the quality attributes presented in the AMP program basis documents and the 

associated AMPs are consistent with the staff’s position on QA for aging management.

3.0.4.3 Conclusion 

On the basis of the staff’s evaluation of Appendix A, Section A1 and Appendix B, Section B.1.3 

of the LRA, and the AMP program basis documents, the staff concludes that the QA attributes 

(corrective action, confirmation process, and administrative control) of the applicant's AMPs are 

consistent with SRP-LR, Branch Technical Position RLSB-1.

3.0.5 Operating Experience for Aging Management Programs

3.0.5.1 Summary of Technical Information in Application

LRA Section B1.4, “Operating Experience,” describes how the applicant considered operating 

experience in the preparation of the application. The LRA states that the applicant reviewed 
AGING MANAGEMENT REVIEW RESULTS

3-249

both plant-specific and industry operating experience. The applicant obtained plant-specific 

operating experience from CAP records generated from January 1999 to June 2011. Industry 

operating experience was obtained from NRC generic letters, generic safety issues, information 

circulars, inspection and enforcement bulletins, INs, and RISs. The LRA also states that the 

operating experience review also included input from plant staff. The AMP descriptions in LRA 

Appendix B summarize the results of the applicant’s operating experience review.

LRA Section B1.4 also describes how future plant-specific and industry operating experience 

will be reviewed by the applicant. The LRA states that Ameren Missouri will review industry 

operating experience from such sources as NRC generic communications, reports made in 

accordance with 10 CFR Part 21, “Reporting of Defects and Noncompliance,” licensee event 

reports, and nonconformance reports. The applicant’s review of plant-specific operating 

experience will include sources such as event investigations, trending reports, lessons learned, 

self-assessments, and the 10 CFR Part 50, Appendix B, corrective action process. The LRA 

further states that, upon receipt of the renewed operating license, Ameren Missouri will use 

these reviews to confirm the effectiveness of the AMPs, determine the need for AMP 

enhancements, and indicate the need to develop new AMPs. 

3.0.5.2 Staff Evaluation

3.0.5.2.1 Overview

In accordance with 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects 

of aging on SCs subject to an AMR will be adequately managed so that their intended functions 

will be maintained consistent with the CLB for the period of extended operation. SRP-LR 

Appendix A describes 10 program elements of an acceptable AMP, and program element 10, 

“operating experience,” is described in SRP-LR Section A.1.2.3.10. On March 16, 2012, the 

staff issued Final LR-ISG-2011-05, “Ongoing Review of Operating Experience.” This LR-ISG 

includes interim revisions to the SRP-LR that clarify the staff’s acceptance criteria and review 

procedures with respect to operating experience review activities conducted under a renewed 

license. Specifically, LR-ISG-2011-05 revises the operating experience criteria in SRP-LR 

Section A.1.2.3.10 to state the following:

(1) Consideration of future plant-specific and industry operating experience 

relating to AMPs should be discussed. The ongoing review of operating 

experience may identify areas where AMPs should be enhanced or new 

AMPs developed. As such, an applicant should ensure that it has adequate 

processes to monitor and evaluate plant-specific and industry operating 

experience related to aging management to ensure that the AMPs are 

effective in managing the aging effects for which they are credited. The 

AMPs are informed by this review of operating experience on an ongoing 

basis, regardless of the AMP’s implementation schedule. The ongoing 

review of operating experience information should provide objective evidence 

to support the conclusion that the effects of aging are managed adequately 

so that the [SC] intended function(s) will be maintained during the period of 

extended operation.

(2) Currently available operating experience with existing programs should be 

discussed. The operating experience of existing programs, including past 

corrective actions resulting in program enhancements or additional programs, 

should be considered. A past failure would not necessarily invalidate an AMP 

because the feedback from operating experience should have resulted in 
AGING MANAGEMENT REVIEW RESULTS

3-250

appropriate program enhancements or new programs. This information can 

show where an existing program has succeeded and where it has not been 

fully effective in intercepting aging degradation in a timely manner. This 

information should provide objective evidence to support the conclusion that 

the effects of aging will be managed adequately so that the [SC] intended 

function(s) will be maintained during the period of extended operation.

(3) Currently available operating experience applicable to new programs also 

should be discussed. For new AMPs that have yet to be implemented at an 

applicant’s facility, the programs have not yet generated any operating 

experience. However, there may be other relevant plant-specific or generic 

industry operating experience that is relevant to the program elements, even 

though the operating experience was not identified through implementation of 

the new program. Thus, when developing the elements for new programs, an 

applicant should consider the impact of relevant operating experience from 

implementation of its existing AMPs and from generic industry operating 

experience.

SER Section 3.0.3 discusses the staff’s review of the second and third criteria, which concern 

currently available operating experience associated with existing and new programs, 

respectively. The following evaluation covers the staff’s review of the first criterion, which 

concerns the consideration of future operating experience and applies to both existing and new 

AMPs.

3.0.5.2.2 Consideration of Future Operating Experience

LR-ISG-2011-05 Appendix A establishes a new SRP-LR Section A.4. This section provides a 

framework for ongoing activities acceptable to address operating experience concerning 

age-related degradation and aging management during the term of a renewed operating license 

to ensure that the effects of aging are managed adequately. The staff evaluated the applicant’s 

operating experience review activities, as described in LRA Section B1.4, against the staff 

position in SRP-LR Section A.4.2. 

Based on its evaluation, the staff determined that the applicant intends to use the existing CAP 

and Operating Experience Program to evaluate operating experience and ensure the 

effectiveness of the aging management activities. However, the staff determined that the LRA 

does not provide sufficient details to describe how these existing processes will be used on an 

ongoing basis to capture and evaluate operating experience relative to the applicant’s bases for 

managing age-related degradation. By letter dated August 6, 2012, the staff issued RAI B1.4-1 

requesting the applicant to describe in detail the programmatic activities that it will use to 

continually identify aging issues, evaluate them, and, as necessary, enhance the program 

elements of applicable AMPs or develop new AMPs. The staff also requested the applicant to 

state if the activities are consistent with the guidance in LR-ISG-2011-05. Otherwise, the staff 

requested the applicant to provide a basis for concluding that its programmatic activities will 

ensure that operating experience will be reviewed on an ongoing basis during the term of the 

renewed license for its impact on the aging management bases.

In its response dated September 6, 2012, the applicant provided additional information to 

describe how it will address plant-specific and industry operating experience under its CAP and 

Operating Experience Program. The applicant also described how the activities conducted 

under these programs align with the guidance in LR-ISG-2011-05. To be consistent with this 
AGING MANAGEMENT REVIEW RESULTS

3-251

guidance, the applicant identified several enhancements to its existing operating experience 

review practices.

The staff reviewed the applicant’s response to RAI B1.4-1 and determined that the response 

does not clearly establish if the applicant’s ongoing programmatic activities for reviewing 

operating experience are considered to be consistent with the further review areas in SRP-LR 

Section A.4.2, as established in LR-ISG-2011-05. Therefore, by letter dated December 7, 2012, 

the staff issued RAI B1.4-1a requesting the applicant to clarify if the operating experience 

activities are consistent with SRP-LR Section A.4.2. The staff specifically requested the 

applicant to provide clarification on the following aspects of its operating experience review

activities: (a) how operating experience from industry guidance documents and standards 

would be captured, (b) identification and evaluation of adverse age-related trends, 

(c) consideration of activities, criteria, and evaluations integral to the elements of the AMPs in 

the operating experience evaluations, (d) documentation of AMR-related information in the 

operating experience evaluations, (e) review of satisfactory and unsatisfactory AMP results for 

appropriate adjustments to the aging management inspection activities, (f) training requirements 

for certain personnel that have key responsibilities for processing operating experience, and 

(g) time when the aging management coordinator, who will be primarily responsible for 

implementing the aging management activities, will begin processing age-related operating 

experience. The staff requested the applicant to identify and justify any areas of inconsistency 

with the guidance in SRP-LR Section A.4.2.

In its response dated December 19, 2012, the applicant provided additional information to 

address aspects of the operating experience review activities raised by the staff in RAI B1.4-1a. 

The applicant provided this information as a supplement to its response to RAI B1.4-1. In 

summary, the response indicates that the operating experience review activities are consistent 

with the guidance in SRP-LR Section A.4.2. 

The staff evaluated the applicant’s description of the ongoing operating experience review 

activities as provided in response to RAIs B1.4-1 and B1.4-1a. The staff evaluated the 

consistency of these activities with the guidance in SRP-LR Section A.4.2 on “Acceptable Use 

of Existing Programs” and “Areas of Further Review.” The staff’s evaluations with respect to 

these two sections of guidance follow in SER Sections 3.0.5.2.3 and 3.0.5.2.4, respectively.

3.0.5.2.3 Acceptability of Existing Programs

SRP-LR Section A.4.2 describes existing programs generally acceptable to the staff for the 

capture, processing, and evaluation of operating experience concerning age-related 

degradation and aging management during the term of a renewed operating license. The 

acceptable programs are those relied upon to meet the requirements of 10 CFR Part 50, 

Appendix B, and Item I.C.5, “Procedures for Feedback of Operating Experience to Plant Staff,” 

of NUREG-0737, “Clarification of TMI Action Plan Requirements,” dated November 1980. 

SRP-LR Section A.4.2 also states that, as part of meeting the requirements of NUREG-0737, 

Item I.C.5, the applicant’s operating experience program should rely on active participation in 

the Institute of Nuclear Power Operations (INPO) operating experience program (formerly the 

INPO Significant Event Evaluation and Information Network (SEE-IN) program endorsed in NRC 

GL 82-04, “Use of INPO SEE-IN Program”).

In its supplemental response to RAI B1.4-1 dated December 19, 2012, the applicant stated that 

it will use its existing CAP and Operating Experience Program to ensure that the AMPs will 

continue to be effective in managing the effects of aging. The applicant also stated that it will 

use these programs to enhance the AMPs or develop new AMPs when the review of operating 
AGING MANAGEMENT REVIEW RESULTS

3-252

experience indicates that the AMPs may not be fully effective. The applicant stated that its 

Operating Experience Program is an established program that has evolved over time and has 

its roots in the INPO SEE-IN program. The applicant further stated that the CAP is used with 

the Operating Experience Program to evaluate and address degraded conditions, including 

plant-specific and industry operating experience. LRA Section B1.3 states that the applicant 

implements its CAP in accordance with the requirements of 10 CFR Part 50, Appendix B. 

Based on this information, the staff determined that the applicant’s use of the existing CAP and 

Operating Experience Program is consistent with the programs described in SRP-LR 

Section A.4.2 and, therefore, generally acceptable for the capture, processing, and evaluation of 

age-related operating experience.

3.0.5.2.4 Areas of Further Review

Notwithstanding the general acceptability of existing programs, certain areas of the applicant’s 

operating experience review activities are subject to further staff review as described in SRP-LR 

Section A.4.2. The staff’s reviews of these areas follow.

Application of Existing Programs and Procedures to the Processing of Operating Experience 

Related to Aging. SRP-LR Section A.4.2 states that the programs and procedures relied upon 

to meet the requirements of 10 CFR Part 50, Appendix B, and NUREG-0737, Item I.C.5, should 

not preclude the consideration of operating experience on age-related degradation and aging 

management. In response to RAI B1.4-1, as supplemented by letter dated December 19, 2012, 

the applicant stated that it currently uses its existing CAP and Operating Experience Program to 

consider and address operating experience related to aging. However, to ensure that the 

consideration of age-related operating experience is not precluded, the applicant stated that it 

will enhance these programs to provide specific direction to identify, evaluate, and communicate 

operating experience related to aging. In an amendment to the LRA submitted by letter dated 

December 19, 2012, the applicant stated that it had completed this enhancement. The staff 

reviewed the applicant’s response and determined that the CAP and Operating Experience 

Program will not preclude the capture and evaluation of operating experience related to aging 

because the applicant has enhanced these programs to clarify that they will specifically be used 

for these purposes. The applicant’s use of these programs for processing operating experience 

is, therefore, consistent with the guidance in SRP-LR Section A.4.2.

SRP-LR Section A.4.2 also states that the applicant should use the option described in SRP-LR 

Appendix A.2 to expand the scope of the 10 CFR Part 50, Appendix B, program to include 

nonsafety-related structures and components. As discussed in SER Section 3.0.4, the staff 

determined that the applicant’s inclusion of nonsafety-related structures and components within 

the scope of its 10 CFR Part 50, Appendix B, program is consistent with the guidance in 

SRP-LR Appendix A.2 and, therefore, also consistent with the guidance in SRP-LR 

Section A.4.2.

Consideration of Industry Guidance Documents as Operating Experience. SRP-LR 

Section A.4.2 states that NRC and industry guidance documents and standards applicable to 

aging management, including revisions to the GALL Report, should be considered as sources of 

industry operating experience and evaluated accordingly.

In its December 19, 2012, response to RAI B1.4-1a the applicant stated that its processes 

include review of industry operating experience sources based on the categories in INPO’s 

“Guidelines for Use of Operating Experience” document. These sources primarily include INPO 

event reports, NRC generic communications (i.e., bulletins, GLs, INs, and RISs), topical reports, 

and vendor correspondence, including reports made in accordance with 10 CFR Part 21, 
AGING MANAGEMENT REVIEW RESULTS

3-253

“Reporting of Defects and Noncompliance.” As an enhancement, the applicant stated that it will 

add LR-ISG documents as an additional source of industry operating experience to be reviewed 

under the Operating Experience Program. In an amendment to the LRA submitted by letter 

dated December 19, 2012, the applicant stated that it had completed this enhancement. In its 

response to RAI B1.4-1a the applicant further stated that, because industry operating 

experience can be derived from many sources, the CAP requires documentation and further 

evaluation when it identifies other sources of industry operating experience applicable to 

Callaway. The staff reviewed the applicant’s response and finds the sources of industry 

operating experience prescribed for review under the Operating Experience Program 

acceptable. These sources are acceptable because the staff considers them to be the primary 

sources of industry operating experience and because they are consistent with those sources 

outlined in the INPO guidelines, which the staff has endorsed by Generic Letter 82-04. The staff 

also finds the addition of LR-ISG documents acceptable because these NRC-generated 

documents can contain insights applicable to aging management.

To illustrate when other sources of industry operating experience applicable to Callaway will be 

documented in the CAP for further evaluation, the applicant stated in its response to 

RAI B1.4-1a that it would consider a guidance document or standard referenced in one of the 

sources covered by the INPO document categories. However, from this one example, the staff 

determined that it is not clear if the applicant only identifies industry operating experience 

applicable to Callaway from INPO-communicated sources, or if the applicant also will rely on 

other activities to identify sources of industry operating experience for evaluation. By letter 

dated January 30, 2013, the staff issued RAI B1.4-1b requesting the applicant to describe the 

activities used to identify other industry- and NRC-generated guidance documents and 

standards applicable to Callaway and to justify the adequacy of these activities for identifying 

guidance documents and standards on age-related degradation and aging management.

In its response dated February 14, 2013, the applicant stated that its procedures allow for the 

consideration of additional sources of industry operating experience (i.e., sources outside of the 

ones prescribed for review under the Operating Experience Program), and plant personnel may 

enter such sources into the CAP for review. The applicant stated that it will use its 

self-assessment and benchmarking processes as a primary means to identify these additional 

sources. These processes include activities such as participation in industry working groups 

and benchmarking of AMPs at other nuclear power plants. The applicant also stated that, 

through these activities, it will maintain awareness of new industry operating experience 

concerning age-related degradation and aging management. The applicant’s response further 

stated that certain plant personnel will receive training on age-related degradation and aging 

management topics, and the applicant expects these personnel to identify (e.g., through 

participation in a self-assessment or benchmarking activity) lessons learned and available 

guidance documents and standards and determine if this new information warrants review for 

Callaway. The staff reviewed the applicant’s response and finds it acceptable because, 

although the applicant’s Operating Experience Program prescribes review of a primary set of 

industry operating experience sources, the applicant does not limit its reviews to only these 

sources. The staff finds that the activities described by the applicant, namely self-assessments, 

benchmarking its AMPs against AMPs at other nuclear power plants, and participation in 

industry working groups, in combination with the training on age-related topics for personnel 

involved with these activities, are suitable to identify these other sources of industry operating 

experience. The staff’s concern described in RAI B1.4-1b regarding the identification of other 

sources of industry operating experience is resolved.
AGING MANAGEMENT REVIEW RESULTS

3-254

On considering revisions of the GALL Report as a source of operating experience, in its 

response to RAI B1.4-1a the applicant stated that it will not explicitly review periodic updates to 

the GALL Report unless the NRC communicates these updates to licensees by an 

accompanying generic communication. The staff reviewed the sources of industry operating 

experience considered by the applicant and determined that one source is topical reports. Per 

its abstract, the GALL Report should be treated as an approved topical report; therefore, the 

staff determined that it is not clear why the applicant’s operating experience review processes 

capture some topical reports, but possibly omit others that are specifically related to aging 

management, such as GALL Report revisions. Therefore, in RAI B1.4-1b the staff also 

requested the applicant to justify why an update to the GALL Report would not be captured and 

reviewed as a topical report under the Operating Experience Program. The staff also requested 

the applicant to state if the program will exclude the capture and review of other topical reports 

on age-related degradation and aging management.

In its response dated February 14, 2013, the applicant clarified that the Operating Experience 

Program requires review of topical reports and does not exclude any topical reports on 

age-related degradation and aging management. The applicant also stated that, in accordance 

with the Operating Experience Program, it evaluates all NRC generic communications for 

applicability to Callaway. As such, the applicant explained that the Operating Experience 

Program will ensure review of a GALL Report revision if the NRC communicates it in this form. 

The applicant also stated that, if the NRC does not use a generic communication, the applicant 

will nonetheless identify issuance of a GALL Report revision through self-assessment and 

benchmarking activities. The applicant further stated that it expects the plant aging 

management coordinator and other personnel to identify lessons learned concerning 

age-related degradation and aging management and to determine if any new information 

warrants review under the Operating Experience Program. In addition, the applicant stated that 

a GALL Report revision would likely be publicized in some form of NRC communication, which 

the aging management coordinator would then use to identify the revision as an additional 

source of operating experience that needs review. 

Through its updates of the GALL Report and issuance of LR-ISGs, the staff has emphasized 

that these documents contain new information and important lessons learned that are relevant 

to maintaining the effectiveness of the AMPs and activities. The staff finds the applicant’s 

response acceptable because the applicant acknowledges the importance of evaluating the 

content of GALL Report revisions to determine impacts to its AMPs. Given the importance of 

reviewing this information, the applicant described several processes that it will use to make 

sure a GALL Report revision is entered into the Operating Experience Program and evaluated. 

As such, the staff finds that the processes described by the applicant are adequate for 

identifying and evaluating future GALL Report revisions. The staff’s concern described in 

RAI B1.4-1b regarding review of GALL Report revisions as a source of industry operating 

experience is resolved.

The staff determined that the applicant will implement appropriate processes to consider the 

impacts of industry operating experience on its AMPs and activities because the applicant’s 

processes will capture NRC and industry guidance documents and standards applicable to 

aging management, including revisions to the GALL Report. The applicant’s consideration of 

industry guidance documents as operating experience is, therefore, consistent with the 

guidance in SRP-LR Section A.4.2.

Screening of Incoming Operating Experience. SRP-LR Section A.4.2 states that all incoming 

plant-specific and industry operating experience should be screened to determine if it involves 
AGING MANAGEMENT REVIEW RESULTS

3-255

age-related degradation or impacts to aging management activities. The applicant’s responses 

to RAIs B1.4-1 and B1.4-1a describe several enhancements to ensure that the applicant will 

effectively screen and evaluate age-related operating experience. In its response to RAI B1.4-1 

as supplemented by letter dated December 19, 2012, the applicant stated that it will enhance 

both the CAP and Operating Experience Program to provide specific direction to identify and 

evaluate age-related operating experience. In LRA amendments submitted by letters dated 

December 19, 2012, and February 14, 2013, the applicant stated that it had completed these 

enhancements. In addition, in its response to RAIs B1.4-1 and B1.4-1a dated 

December 19, 2012, the applicant described enhanced training for certain key individuals 

involved with the operating experience screening and evaluation process. Specifically, the 

applicant stated that it will enhance the Operating Experience Program coordinator training to 

ensure the proper review, dissemination, and evaluation of plant-specific and industry operating 

experience involving age-related degradation. The applicant also explained that plant subject 

matter experts assist Operating Experience Program coordinators in the screening of external 

operating experience and participate in operating experience review, evaluation, and 

documentation. The applicant will require these individuals to participate in initial and continuing 

training on operating experience and aging concepts. The plant aging management coordinator 

also will review plant-specific and industry operating experience for lessons learned, and this 

individual will receive training on license renewal concepts for proficiency in screening and 

evaluating age-related operating experience. In an amendment to the LRA submitted by letter 

dated April 26, 2013, the applicant stated that it had completed the training-related 

enhancements. The staff reviewed these responses and determined that the applicant’s 

operating experience review processes are acceptable because they include screening of 

operating experience by trained individuals so that items with potential impact to aging 

management can receive appropriate evaluation. The applicant’s screening of plant-specific 

and industry operating experience is, therefore, consistent with the guidance in SRP-LR 

Section A.4.2.

Identification of Operating Experience Related to Aging. SRP-LR Section A.4.2 states that 

coding should be used within the CAP to identify operating experience concerning age-related 

degradation applicable to the plant, and the associated entries should be periodically reviewed 

and any adverse trends evaluated. In response to RAI B1.4-1a dated December 19, 2012, the 

applicant stated that, as an enhancement, it established specific codes within its CAP to assist 

in the identification and trending of age-related degradation so that it can assess and trend the 

adequacy of AMPs and make adjustments when necessary. The applicant also stated that, per 

existing processes, it analyzes CAP records at least semiannually using identification codes and 

other available data. In addition, the applicant stated that its CAP requires documentation and 

further evaluation of trends in performance or frequency of occurrence that indicate 

performance adverse to an expected or established standard. The staff reviewed the response 

and finds these activities acceptable because the applicant has established means at a 

programmatic level to identify, trend, and evaluate operating experience that involves 

age-related degradation. The applicant’s identification of age-related operating experience 

applicant to the plant is, therefore, consistent with the guidance in SRP-LR Section A.4.2.

Information Considered in Operating Experience Evaluations. SRP-LR Section A.4.2 states that 

operating experience identified as involving aging should receive further evaluation that takes 

into account information fundamental to an AMR, such as the affected SSCs, materials, 

environments, aging effects, aging mechanisms, and AMPs. In its response to RAI B1.4-1a 

dated December 19, 2012, the applicant stated that its evaluations of operating experience 

related to aging management will consider and document the following: (a) SSCs that are 

similar or identical to those involved with the identified operating experience issue; (b) materials 
AGING MANAGEMENT REVIEW RESULTS

3-256

of construction, operating environments, and aging effects associated with the identified aging 

issue so that lessons learned can be applied to susceptible SSCs within the scope of license 

renewal; and (c) aging mechanisms associated with the operating experience to confirm that 

appropriate programs are in place to manage aging that could be caused by these mechanisms. 

Additionally, the applicant stated that it will consider and document evaluation of the AMPs 

associated with the operating experience so that, if the AMPs have been shown to be 

ineffective, similar AMPs can be evaluated to determine if changes are appropriate or if a new 

AMP is needed. These AMP evaluations also include consideration of the activities, criteria, 

and evaluations integral to the elements of the AMPs. The staff reviewed the response and 

determined that the applicant’s evaluations of age-related operating experience will include 

assessment of potential impacts to the aging management activities through the consideration 

of information fundamental to an AMR.

SRP-LR Section A.4.2 also states that actions should be initiated within the CAP to either 

enhance the AMPs or develop and implement new AMPs if it is found through an operating 

experience evaluation that the effects of aging may not be adequately managed. In its 

response to RAI B1.4-1a dated December 19, 2012, the applicant stated that it uses the CAP to 

address all degraded conditions, which include degraded conditions identified from evaluation of 

plant-specific operating experience under the CAP and from evaluation of industry operating 

experience under the Operating Experience Program. In its response the applicant also stated 

that it will use the processes under the CAP and Operating Experience Program to enhance the 

AMPs or develop new AMPs when the review of operating experience indicates that the AMPs 

may not be fully effective. The staff reviewed the response and determined that the applicant 

will uses its CAP to implement changes necessary to manage the effects of aging, as 

determined through the evaluation of operating experience.

Therefore, the staff finds that the information considered in the applicant’s operating experience 

evaluations and use of the CAP to ensure that the effects of aging are adequately managed is 

consistent with the guidance in SRP-LR Section A.4.2.

Evaluation of AMP Implementation Results. SRP-LR Section A.4.2 states that the results of 

implementing the AMPs, such as data from inspections, tests, and analyses, should be 

evaluated regardless of whether the acceptance criteria of the particular AMP have been met. 

SRP-LR Section A.4.2 states that this information should be used to determine if it is necessary

to adjust the frequency of future inspections, establish new inspections, and adjust or expand 

the inspection scope. In addition, SRP-LR Section A.4.2 states that actions should be initiated 

within the CAP to either enhance the AMPs or develop and implement new AMPs if these 

evaluations indicate that the effects of aging may not be adequately managed. In its response 

to RAI B1.4-1a dated December 19, 2012, the applicant stated that it documents the results of 

AMP inspections, tests, analyses, etc. in its plant work management system. The applicant 

stated that, if the results do not meet acceptance criteria, it enters the results into the CAP for 

further review and action, which includes correcting the specific condition and evaluating the 

adequacy of the AMPs. The applicant also stated that it will periodically monitor and trend AMP 

performance. This monitoring will include review of satisfactory and unsatisfactory examination 

and testing results to ensure that aspects of the AMPs are effective, such as the inspection 

frequency and scope, and if new inspections are needed. In addition, the applicant stated that it 

will periodically assess AMP performance and effectiveness based on available monitoring and 

trending data, benchmarking, status of industry initiatives, and operating experience. If it 

identifies a deficient condition related to aging through these activities, the applicant stated that 

it will use the CAP to determine if the AMPs should be modified or if new AMPs should be 

created. The staff reviewed this response and finds the applicant’s treatment of AMP 
AGING MANAGEMENT REVIEW RESULTS

3-257

implementation results as operating experience acceptable because the applicant will evaluate 

these results and use the information to determine whether to adjust the aging management 

inspection activities. The applicant’s activities for the evaluation of the AMP implementation 

results are, therefore, consistent with the guidance in SRP-LR Section A.4.2.

Training. SRP-LR Section A.4.2 states that training on age-related degradation and aging 

management should be provided to those personnel responsible for implementing the AMPs 

and those personnel that may submit, screen, assign, evaluate, or otherwise process 

plant-specific and industry operating experience. SRP-LR Section A.4.2 also states that the 

training should occur on a periodic basis and include provisions to accommodate the turnover of 

plant personnel.

In its response to RAI B1.4-1a dated December 19, 2012, the applicant described its training 

activities for key personnel involved with the processing and evaluation of operating experience. 

The applicant stated that its Operating Experience Program coordinators are the central input 

for all operating experience at the plant. As an enhancement, the applicant stated that it will 

update their training to ensure the proper review and dissemination of plant-specific and 

industry operating experience concerning age-related degradation. The applicant also stated 

that the Operating Experience Program coordinators rely on various subject-matter experts to 

assist with operating experience screening, evaluation, and documentation. For these 

individuals, the applicant provides initial training on operating experience and aging concepts. 

The applicant also will include specific modules on aging concepts, identification of aging 

mechanisms, and review of operating experience in its continuing training. In addition, the 

applicant stated that it will assign an aging management coordinator before or upon receipt of 

the renewed operating license to oversee implementation of the license renewal activities. This 

coordinator will review operating experience to identify applicable lessons learned and 

plant-specific operating experience related to aging that will be shared with the industry. The 

applicant stated that the aging management coordinator will receive training on license renewal 

concepts for proficiency in screening and evaluating age-related operating experience. The 

aging management coordinator also will attend the same initial and continuing training on aging 

topics as required of the subject-matter experts. The applicant further stated that the AMP 

owners have received classroom training on component aging. As an enhancement, the 

applicant stated that it will require the AMP owners to take periodic training on relevant 

operating experience and aging concepts. New AMP owners will be required to take the same 

training, and the applicant will ensure the effective turnover of responsibilities through 

procedures for program and personnel transitions. In an amendment to the LRA submitted by 

letter dated April 26, 2013, the applicant stated that it had completed the training-related 

enhancements. 

The staff reviewed the applicant’s response and finds the training activities acceptable because 

the applicant will require initial and periodic training on age-related degradation and aging 

management topics for the personnel responsible for implementing the AMPs and for the key 

personnel responsible for processing and evaluating operating experience related to aging. The 

staff also finds that the applicant’s training approach will address personnel turnover because 

the applicant will require training on a position-specific basis, and individuals new to the 

positions will receive initial training on age-related concepts. The applicant’s training activities 

are, therefore, consistent with the guidance in SRP-LR Section A.4.2.

Reporting Operating Experience to the Industry. SRP-LR Section A.4.2 states that guidelines 

should be established for reporting plant-specific operating experience on age-related 

degradation and aging management to the industry. In its response to RAI B1.4-1 as 
AGING MANAGEMENT REVIEW RESULTS

3-258

supplemented by letter dated December 19, 2012, the applicant stated that it will enhance the 

Operating Experience Program to include direction and criteria for reporting plant-specific 

operating experience concerning age-related degradation to other licensees. In an amendment 

to the LRA submitted by letter dated December 19, 2012, the applicant stated that it had 

completed this enhancement. The applicant’s reporting criteria include observation of 

age-related degradation significantly beyond that expected, aging effects or mechanisms not 

previously discovered by or managed by the applicant’s AMPs, and significant changes to the 

applicant’s AMPs that would be of interest to other licensees. The staff reviewed the response 

and finds the applicant’s reporting guidelines acceptable because they specifically cover 

circumstances in which noteworthy plant-specific operating experience related to aging 

management and age-related degradation will be reported to the industry. The applicant’s 

establishment of these reporting guidelines is, therefore, consistent with the guidance in 

SRP-LR Section A.4.2.

Schedule for Implementing the Operating Experience Review Activities. SRP-LR Section A.4.2 

states that any enhancements to the existing operating experience review activities should be 

put in place no later than the date when the renewed operating license is issued. In 

RAIs B1.4-1a and B1.4-1b, issued by letters dated December 7, 2012, and January 30, 2013, 

respectively, the staff requested the applicant to identify any such enhancements and to provide 

a schedule for their implementation, including a justification if the implementation date is later 

than the date when the renewed operating license is scheduled to be issued, if approved. In its 

response to RAI B1.4-1, as revised in response to B1.4-1a dated December 19, 2012, the 

applicant identified several enhancements to the CAP and Operating Experience Program. In 

its response to RAI B1.4-1b dated February 14, 2013, the applicant identified no additional 

enhancements. Subsequently, in amendment to the LRA submitted by letter dated 

April 26, 2013, the applicant stated that it completed all of the enhancements. The staff 

reviewed the responses and finds the applicant’s schedule for implementing these 

programmatic enhancements acceptable because the applicant completed implementation 

before issuance of the renewed license, which is consistent with the guidance in SRP-LR 

Section A.4.2.

SRP-LR Section A.4.2 also states that the operating experience review activities should be 

implemented on an ongoing basis throughout the term of the renewed license. By letter dated 

September 6, 2012, as revised by letters dated December 19, 2012, February 14, 2013, and 

April 26, 2013, the applicant amended the FSAR supplement in LRA Appendix A to include a 

summary description of the ongoing operating experience review activities. As discussed below 

in SER Section 3.0.5.3, the staff finds that this summary description is sufficiently 

comprehensive to describe the applicant’s programmatic activities for evaluating operating 

experience. On issuance of the renewed license in accordance with 10 CFR 54.3(c), this 

summary description will be incorporated into the plant’s CLB and, at that time, the applicant will 

be obligated to conduct its operating experience review activities accordingly. The staff finds 

the implementation schedule acceptable because the applicant will implement the enhanced 

operating experience review activities on an ongoing basis throughout the term of the renewed 

operating license. This ongoing implementation is, therefore, consistent with the guidance in 

SRP-LR Section A.4.2.

3.0.5.2.5 Summary

Based on its review of the LRA and the applicant’s responses to RAIs B1.4-1, B1.4-1a, and 

B1.4-1b, the staff determined that the applicant’s programmatic activities for the ongoing review 

of operating experience are consistent with the guidance in SRP-LR Section A.4.2 as 
AGING MANAGEMENT REVIEW RESULTS

3-259

established in LR-ISG-2011-05. These activities are, therefore, acceptable for (a) the 

systematic review of plant-specific and industry operating experience to ensure that the license

renewal AMPs are and will continue to be effective in managing the aging effects for which they 

are credited, and (b) the enhancement of AMPs or development of new AMPs when it is 

determined through the evaluation of operating experience that the effects of aging may not be 

adequately managed. The staff’s concerns described in RAIs B1.4-1, B1.4-1a, and B1.4-1b are 

resolved.

3.0.5.3 FSAR Supplement

SRP-LR Section A.4.2 states that the programmatic activities for the ongoing review of 

plant-specific and industry operating experience concerning age-related degradation and aging 

management should be described in the FSAR supplement. The staff reviewed the applicant’s 

FSAR supplement provided in LRA Appendix A. The staff found that Commitment No. 2 in LRA 

Table A4-1 is associated with the ongoing operating experience review activities; however, the 

staff determined that the applicant did not provide a complete summary description of these 

activities. By letter dated August 6, 2012, the staff issued RAI B1.4-1 which requested in part 

that the applicant provide a full summary description to address the requirements of 

10 CFR 54.21(d).

In its response dated September 6, 2012, the applicant amended LRA Section A1 to include a 

summary description of its programmatic activities for the ongoing review of operating 

experience. The applicant also revised Commitment No. 2 to identify license renewal 

enhancements to its existing operating experience review activities. The applicant subsequently 

revised this commitment based on its response to RAI B1.4-1a dated December 19, 2012. In 

response to RAI B1.4-1b dated February 14, 2013, the applicant further revised Commitment 

No. 2 to remove a statement that qualified that its processes only include review of certain 

industry guidance documents, such as GALL Report revision, if communicated in an NRC 

generic communication. In an amendment to the LRA submitted by letter dated April 26, 2013, 

the applicant also revised the commitment to indicate that all of the enhancements were 

completed.

LR-ISG-2011-05 revises SRP-LR Table 3.0-1 by including an example summary description for 

the programmatic activities for the ongoing review of operating experience. The staff reviewed 

the content of the applicant’s summary description, as provided by letter dated 

September 6, 2012, and revised by letters dated December 19, 2012, February 14, 2013, and 

April 26, 2013, against the content in the example from SRP-LR Table 3.0-1. The staff 

determined that the content of the applicant’s summary description is consistent with this 

example and also sufficiently comprehensive to describe the applicant’s programmatic operating 

experience review activities for license renewal. Therefore, the staff’s concern described in 

RAI B1.4-1 is resolved and the staff finds the applicant’s FSAR supplement summary 

description acceptable.

3.0.5.4 Conclusion

Based on its review of the applicant’s programmatic activities for the ongoing review of 

operating experience, as described in the LRA and in response to RAIs B1.4-1, B1.4-1a, and 

B1.4-1b, the staff concludes that the applicant has demonstrated that operating experience will 

be reviewed to ensure that the effects of aging will be adequately managed so that the intended 

functions will remain consistent with the CLB for the period of extended operation, as required 

by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for these activities and 

concludes that it provides an adequate summary description, as required by 10 CFR 54.21(d).
AGING MANAGEMENT REVIEW RESULTS

3-260

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant System

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

reactor vessel, RVIs, and RCS components and component groups of the following:

• reactor vessel

• RVIs

• RCS

• pressurizer

• steam generators

3.1.1 Summary of Technical Information in the Application

LRA Section 3.1 provides AMR results for the reactor vessel, RVIs, RCS components and 

components groups. LRA Table 3.1-1, “Summary of Aging Management Programs in Chapter 

IV of NUREG-1801 for Reactor Vessel, Internals, and Reactor Coolant System,” is a summary 

comparison of the applicant’s AMRs with those evaluated in the GALL Report for the reactor 

vessel, RVIs, and RCS components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

issue reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine if the applicant provided sufficient information 

to demonstrate that the effects of aging for the reactor vessel, RVIs, and RCS components 

within the scope of license renewal and subject to an AMR will be adequately managed so that 

the intended function(s) will remain 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 the applicant’s 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 confirm 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 confirm that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. Details of the 

staff’s evaluation are discussed in SER Sections 3.1.2.1.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff’s evaluations are 

documented in SER Section 3.1.2.2.
AGING MANAGEMENT REVIEW RESULTS

3-261

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 3.1.2.3.

For components that the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR items and the plant’s operating experience to confirm 

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.

The staff’s review of the reactor vessel, RVIs, and 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 reactor 

vessel, RVIs, and RCS components is documented in SER Section 3.0.3.

Table 3.1-1 Staff Evaluation for Reactor Vessel, RVIs, RCS Components in the GALL 

Report

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

High strength, 

low-alloy steel top 

head closure stud 

assembly exposed 

to air with potential 

for reactor coolant 

leakage (3.1.1-1)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with

the GALL Report 

(see SER 

Section 3.1.2.2.1)

Nickel alloy tubes 

and sleeves 

exposed to reactor 

coolant and 

secondary feedwater 

or steam (3.1.1-2)

Cumulative 

fatigue damage 

caused by 

fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with 

the GALL Report 

(see SER 

Section 3.1.2.2.1)
AGING MANAGEMENT REVIEW RESULTS

3-262

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy RVI 

components 

exposed to reactor

coolant and neutron 

flux (3.1.1-3)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with 

the GALL Report 

(see SER 

Section 3.1.2.2.1)

Steel pressure 

vessel support skirt 

and attachment 

welds (3.1.1-4)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.2.1) 

Steel, stainless 

steel, or steel (with 

stainless steel or 

nickel alloy cladding) 

steam generator 

components, 

pressurizer relief 

tank components or 

piping components 

or bolting (3.1.1-5)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with

the GALL Report 

(see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

coolant pressure 

boundary 

components: piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-6)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.2.1)
AGING MANAGEMENT REVIEW RESULTS

3-263

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

vessel components: 

flanges; nozzles; 

penetrations; safe 

ends; thermal 

sleeves; vessel 

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-7)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed (see 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy steam 

generator 

components 

exposed to reactor 

coolant (3.1.1-8)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed (see 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

RCPB piping; 

flanges; nozzles & 

safe ends; 

pressurizer shell 

heads & welds; 

heater sheaths & 

sleeves; 

penetrations; 

thermal sleeves 

exposed to reactor 

coolant (3.1.1-9)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed (see 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with 

GALL Report 

(see SER 

Section 3.1.2.2.1)
AGING MANAGEMENT REVIEW RESULTS

3-264

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

reactor vessel 

flanges; nozzles; 

penetrations; 

pressure housings; 

safe ends; thermal 

sleeves; vessel 

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-10)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed (see 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1)

Steel or stainless 

steel pump and 

valve closure bolting 

exposed to high 

temperatures and 

thermal cycles 

(3.1.1-11)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a TLAA 

evaluated for the

period of extended 

operation; check 

ASME Code limits 

for allowable cycles 

(less than 7,000 

cycles) of thermal 

stress range (see 

SRP Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes, TLAA Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.1.1)

Steel steam 

generator 

components: upper 

and lower shells, 

transition cone; new 

transition cone 

closure weld 

exposed to 

secondary feedwater 

or steam (3.1.1-12)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,” 

and, for 

Westinghouse Model 

44 and 51 S/G, if 

corrosion of the shell 

is found, additional 

inspection 

procedures are 

developed

Yes ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD and Water 

Chemistry

Consistent with the 

GALL Report 

(see SER 

Sections 3.1.2.2.2(1) 

and 3.1.2.2.2(2))
AGING MANAGEMENT REVIEW RESULTS

3-265

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with or without 

stainless steel 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds 

exposed to reactor 

coolant and neutron 

flux (3.1.1-13)

Loss of fracture 

toughness 

caused by 

neutron 

irradiation 

embrittlement

TLAA is to be 

evaluated in 

accordance with 

Appendix G of 

10 CFR Part 50 and 

Regulatory Guide 

(RG) 1.99. The 

applicant may 

choose to 

demonstrate that the 

materials of the 

nozzles are not 

controlling for the 

TLAA evaluations

Yes, TLAA TLAA Consistent with the 

GALL Report (see 

SER 

Section 3.1.2.2.3(1))

Steel (with or without 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds; 

safety injection 

nozzles (3.1.1-14)

Loss of fracture 

toughness 

caused by 

neutron 

irradiation 

embrittlement

Chapter XI.M31, 

“Reactor Vessel 

Surveillance”

Yes Reactor Vessel 

Surveillance

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.3(2))

Stainless steel and 

nickel alloy RVI 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-15)

Reduction in 

ductility and 

fracture 

toughness 

caused by 

neutron 

irradiation

Ductility - Reduction 

in Fracture 

Toughness is a 

TLAA to be 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.7, “Other 

Plant-Specific 

TLAAs,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1))

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.3(3))

Stainless steel and 

nickel alloy top head 

enclosure vessel 

flange leak detection 

line (3.1.1-16)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

A plant-specific AMP 

is to be evaluated 

because existing 

programs may not 

be capable of 

mitigating or 

detecting crack 

initiation and growth 

caused by SCC in 

the vessel flange 

leak detection line

Yes, 

plant-specific

Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.2.4(1))

Stainless steel 

isolation condenser 

components 

exposed to reactor 

coolant (3.1.1-17)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

for BWR water, and 

a plant-specific 

verification program

Yes Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.2.4(2))
AGING MANAGEMENT REVIEW RESULTS

3-266

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Reactor vessel shell 

fabricated of 

SA508-Cl 2 forgings 

clad with stainless 

steel using a 

high-heat-input 

welding process 

exposed to reactor 

coolant (3.1.1-18)

Crack growth 

caused by cyclic 

loading

Growth of 

intergranular 

separations is a 

TLAA evaluated for 

the period of 

extended operation 

(see SRP, 

Section 4.7, “Other 

Plant-Specific 

TLAAs,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c))

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.5)

Stainless steel 

reactor vessel 

closure head flange 

leak-detection line 

and bottom-mounted 

instrument guide 

tubes (external to 

reactor vessel) 

(3.1.1-19)

Cracking 

caused by 

stress corrosion 

cracking

A plant-specific AMP 

is to be evaluated

Yes, 

plant-specific

ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD and Water 

Chemistry 

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.6(1))

Cast austenitic 

stainless steel 

Class 1 piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-20)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry” 

and, for CASS 

components that do 

not meet the 

NUREG-0313 

guidelines, a plant 

specific AMP

Yes ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD and Water 

Chemistry

Consistent with the 

GALL Report 

(see SER

Section 3.1.2.2.6(2))

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-21)

Cracking 

caused by cyclic 

loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components. 

The ISI program is to 

be augmented by a 

plant-specific 

verification program

Yes Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.2.7)

Steel steam 

generator feedwater 

impingement plate 

and support exposed 

to secondary 

feedwater (3.1.1-22)

Loss of material 

caused by 

erosion

A plant-specific AMP 

is to be evaluated

Yes, 

plant-specific

Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.2.8)

Stainless steel or 

nickel alloy PWR 

RVI components 

(inaccessible 

locations) exposed 

to reactor coolant 

and neutron flux 

(3.1.1-23)

Cracking 

caused by 

stress corrosion 

cracking and 

irradiation-assist

ed stress 

corrosion 

cracking

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

Yes PWR Vessel 

Internals

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.9)
AGING MANAGEMENT REVIEW RESULTS

3-267

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy PWR 

RVI components 

(inaccessible 

locations) exposed 

to reactor coolant 

and neutron flux 

(3.1.1-24)

Loss of fracture 

toughness 

caused by 

neutron 

irradiation 

embrittlement; 

or changes in 

dimension 

caused by void 

swelling; or loss 

of preload 

caused by 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

Yes PWR Vessel 

Internals

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.10)

Steel (with 

nickel-alloy cladding) 

or nickel alloy steam 

generator primary 

side components: 

divider plate and 

tube-to-tube sheet 

welds exposed to 

reactor coolant 

(3.1.1-25)

Cracking 

caused by 

primary water 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

Yes, 

plant-specific

Commitments to 

confirm integrity 

of the welds

Consistent with the 

GALL Report 

(see SER 

Sections 3.1.2.2.11(1

) and 3.1.2.2.11(2))

Stainless steel 

combustion 

engineering core 

support barrel 

assembly: lower 

flange weld exposed 

to reactor coolant 

and neutron flux. 

upper internals 

assembly: fuel 

alignment plate 

(applicable to plants 

with core shrouds 

assembled with full 

height shroud plates) 

exposed to reactor 

coolant and neutron 

flux. lower support 

structure: core 

support plate 

(applicable to plants 

with a core support 

plate) exposed to 

reactor coolant and 

neutron flux 

(3.1.1-26)

Cracking 

caused by 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry,” if 

fatigue life cannot be 

confirmed by TLAA

Yes Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.2.12)
AGING MANAGEMENT REVIEW RESULTS

3-268

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Nickel alloy 

Westinghouse 

control rod guide 

tube assemblies, 

guide tube support 

pins exposed to 

reactor coolant and 

neutron flux 

(3.1.1-27)

Cracking 

caused by 

stress corrosion 

cracking and 

fatigue

A plant-specific AMP 

is to be evaluated

Yes, 

plant-specific 

Not applicable Not applicable to 

Callaway

(see SER 

Section 3.1.2.2.13)

Nickel alloy 

Westinghouse 

control rod guide 

tube assemblies, 

guide tube support 

pins, and Zircaloy-4 

Combustion 

Engineering incore 

instrumentation 

thimble tubes 

exposed to reactor 

coolant and neutron 

flux (3.1.1-28)

Loss of material 

caused by wear

A plant-specific AMP 

is to be evaluated

Yes, 

plant-specific

Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.2.14)

Nickel alloy core 

shroud and core 

plate access hole 

cover (welded 

covers) exposed to 

reactor coolant 

(3.1.1-29)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assist

ed stress 

corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,” 

and for BWRs with a 

crevice in the access 

hole covers, 

augmented 

inspection using UT 

or other acceptable 

techniques

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

penetration: drain 

line exposed to 

reactor coolant 

(3.1.1-30)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.1.1)

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-31)

Loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-269

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel, 

nickel alloy, or CASS 

RVIs, core support 

structure, exposed to 

reactor coolant and 

neutron flux 

(3.1.1-32)

Cracking, or 

loss of material 

caused by wear

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD

Consistent with the

GALL Report (See 

SER Section 

3.1.2.1.3)

Stainless steel, steel 

with stainless steel 

cladding Class 1 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-33)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry” 

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD and Water 

Chemistry

Consistent with the 

GALL Report

Stainless steel, steel 

with stainless steel 

cladding pressurizer 

relief tank (tank shell 

and heads, flanges, 

nozzles) exposed to 

treated borated 

water >60 °C 

(>140 °F) (3.1.1-34)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry” 

No NA Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Stainless steel, steel 

with stainless steel 

cladding RCS cold 

leg, hot leg, surge 

line, and spray line 

piping and fittings 

exposed to reactor 

coolant (3.1.1-35)

Cracking 

caused by cyclic 

loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No, ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD

Consistent with the 

GALL Report

Steel, stainless steel 

pressurizer integral 

support exposed to 

air with metal 

temperature up to 

288 °C (550 °F) 

(3.1.1-36)

Cracking 

caused by cyclic

loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD

Consistent with the 

GALL Report

Steel reactor vessel 

flange (3.1.1-37)

Loss of material 

caused by wear

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-270

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Cast austenitic 

stainless steel 

Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant >250° C 

(>482° F) (3.1.1-38)

Loss of fracture 

toughness 

caused by 

thermal aging 

embrittlement

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components. 

For pump casings 

and valve bodies, 

screening for 

susceptibility to 

thermal aging is not 

necessary.

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD

Consistent with the 

GALL Report

Steel, stainless 

steel, or steel with 

stainless steel 

cladding Class 1 

piping, fittings and 

branch connections 

<NPS 4 exposed to 

reactor coolant 

(3.1.1-39)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking (for 

stainless steel 

only), and 

thermal, 

mechanical, and 

vibratory loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

Chapter XI.M2, 

“Water Chemistry,” 

and XI.M35, 

“One-Time 

Inspection of ASME 

Code Class 1 

Small-bore Piping”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD, Water 

Chemistry, and 

One-Time 

Inspection of 

ASME Code 

Class 1 Small 

bore Piping

Consistent with the 

GALL Report

Steel with stainless 

steel or nickel alloy 

cladding; or stainless 

steel pressurizer 

components 

exposed to reactor 

coolant (3.1.1-40)

Cracking 

caused by cyclic 

loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD and Water 

Chemistry

Consistent with the 

GALL Report

Nickel alloy core 

support pads; core 

guide lugs exposed 

to reactor coolant 

(3.1.1-40a)

Cracking 

caused by 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD and Water 

Chemistry

Consistent with the 

GALL Report

Nickel alloy core 

shroud and core 

plate access hole 

cover (mechanical 

covers) exposed to 

reactor coolant 

(3.1.1-41)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assist

ed stress 

corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-271

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel with stainless 

steel or nickel alloy 

cladding or stainless 

steel primary side 

components; steam 

generator upper and 

lower heads, and 

tube sheet weld; or 

pressurizer 

components 

exposed to reactor 

coolant (3.1.1-42)

Cracking 

caused by 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC, and 

IWD and Water 

Chemistry

Consistent with the 

GALL Report

Stainless steel and 

nickel-alloy RVIs 

exposed to reactor 

coolant (3.1.1-43)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Steel steam 

generator secondary 

manways and 

handholds (cover 

only) exposed to air 

with leaking 

secondary-side 

water and/or steam 

(3.1.1-44)

Loss of material 

caused by 

erosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 2 components

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Nickel alloy and 

steel with 

nickel-alloy cladding 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-45)

Cracking 

caused by 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking 

of Nickel-Alloy 

Components and 

Loss of Material due 

to Boric 

Acid-induced 

Corrosion in RCPB 

Components (PWRs 

Only)”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC and 

IWD, Water 

Chemistry, and 

Cracking of 

Nickel-Alloy 

Components 

and Loss of 

Material due to 

Boric Acid 

induced 

Corrosion in 

RCPB 

Components

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-272

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel, 

nickel-alloy, 

nickel-alloy welds 

and/or buttering 

control rod drive 

head penetration 

pressure housing or 

nozzles safe ends 

and welds (inlet, 

outlet, safety 

injection) exposed to 

reactor coolant 

(3.1.1-46)

Cracking 

caused by 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking 

of Nickel-Alloy 

Components and 

Loss of Material due 

to Boric 

Acid-induced 

corrosion in RCPB 

Components (PWRs 

Only)”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections IW

B, IWC and 

IWD, Water 

Chemistry, and 

Cracking of 

Nickel-Alloy 

Components 

and Loss of 

Material due to 

Boric Acid 

induced 

Corrosion in 

RCPB 

Components

Consistent with the 

GALL Report

Stainless steel, 

nickel-alloy control 

rod drive head 

penetration pressure 

housing exposed to 

reactor coolant 

(3.1.1-47)

Cracking 

caused by 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections

IWB, IWC and 

IWD and Water 

Chemistry

Consistent with the 

GALL Report

Steel external 

surfaces: reactor 

vessel top head, 

reactor vessel 

bottom head, reactor 

coolant pressure 

boundary piping or 

components 

adjacent to dissimilar 

metal (Alloy 82/182) 

welds exposed to air 

with borated water 

leakage (3.1.1-48)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion,” and 

Chapter XI.M11B, 

“Cracking of 

Nickel-Alloy 

Components and 

Loss of Material due 

to Boric 

Acid-Induced 

Corrosion in RCPB 

Components (PWRs 

Only)”

No Boric Acid 

Corrosion, and 

Cracking of 

Nickel-Alloy 

Components 

and Loss of 

Material due to 

Boric 

Acid-Induced 

Corrosion in 

RCPB 

Components

Consistent with the 

GALL Report

Steel reactor coolant 

pressure boundary 

external surfaces or 

closure bolting 

exposed to air with 

borated water 

leakage (3.1.1-49)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Boric Acid 

Corrosion

Consistent with the 

GALL Report

Cast austenitic 

stainless steel 

Class 1 piping, 

piping component, 

and piping elements 

and control rod drive 

pressure housings 

exposed to reactor 

coolant >250° C 

(>482° F) (3.1.1-50)

Loss of fracture 

toughness 

caused by 

thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-273

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel or

nickel-alloy Babcock 

& Wilcox reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-51)

Cracking 

caused by 

stress corrosion 

cracking, 

irradiation-assist

ed stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy 

Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52)

Cracking 

caused by 

stress corrosion 

cracking, 

irradiation-assist

ed stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy 

Westinghouse 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-53)

Cracking 

caused by 

stress corrosion 

cracking, 

irradiation-assist

ed stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No PWR Vessel 

Internals and 

Water 

Chemistry

Consistent with the 

GALL Report (see 

SER 

Section 3.1.2.1.3)

Stainless steel 

bottom mounted 

instrument system 

flux thimble tubes 

(with or without 

chrome plating) 

exposed to reactor 

coolant and neutron 

flux (3.1.1-54)

Loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M37, 

“Flux Thimble Tube 

Inspection”

No PWR Vessel 

Internals and 

Flux Thimble 

Tube Inspection

Consistent with the 

GALL Report

Stainless steel 

thermal shield 

assembly, thermal 

shield flexures 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55)

Cracking 

caused by 

fatigue; loss of 

material caused 

by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-274

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel or 

nickel-alloy 

Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56)

Loss of fracture 

toughness 

caused by 

neutron 

irradiation 

embrittlement; 

or changes in 

dimension 

caused by void 

swelling; or loss 

of preload 

caused by 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy Babcock 

& Wilcox reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-58)

Loss of fracture 

toughness 

caused by 

neutron 

irradiation 

embrittlement; 

or changes in 

dimension 

caused by void 

swelling; or loss 

of preload 

caused by 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy 

Westinghouse 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59)

Loss of fracture 

toughness 

caused by 

neutron 

irradiation 

embrittlement; 

or changes in 

dimension 

caused by void 

swelling; or loss 

of preload 

caused by 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

caused by wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No PWR Vessel 

Internals

Consistent with the 

GALL Report (see 

SER 

Section 3.1.2.1.3)
AGING MANAGEMENT REVIEW RESULTS

3-275

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant (3.1.1-60)

Wall thinning 

caused by 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.1.1)

Steel steam 

generator steam 

nozzle and safe end, 

feedwater nozzle 

and safe end, AFW 

nozzles and safe 

ends exposed to 

secondary 

feedwater/steam 

(3.1.1-61)

Wall thinning 

caused by 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No FlowAccelerated 

Corrosion

Consistent with the 

GALL Report

High-strength, low 

alloy steel, or 

stainless steel 

closure bolting; 

stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-62)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel or stainless 

steel closure bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-63)

Loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion or 

wear

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.1.1)

Steel closure bolting 

exposed to air –

indoor uncontrolled 

(3.1.1-64)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-65)

Loss of material 

caused by wear

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-276

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

High-strength, low 

alloy steel, or 

stainless steel 

closure bolting; 

stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-66)

Loss of preload 

caused by 

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel or stainless 

steel closure bolting 

exposed to air –

indoor with potential 

for reactor coolant 

leakage (3.1.1-67)

Loss of preload 

caused by 

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Nickel alloy steam 

generator tubes 

exposed to 

secondary feedwater 

or steam (3.1.1-68)

Changes in 

dimension 

(“denting”) 

caused by 

corrosion of 

carbon steel 

tube support 

plate

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

or steam (3.1.1-69)

Cracking 

caused by outer 

diameter stress 

corrosion 

cracking and 

intergranular 

attack

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Steam 

Generators and 

Water 

Chemistry

Consistent with the 

GALL Report

Nickel alloy steam 

generator tubes, 

repair sleeves, and 

tube plugs exposed 

to reactor coolant 

(3.1.1-70)

Cracking 

caused by 

primary water 

stress corrosion 

cracking

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Steam 

Generators and 

Water 

Chemistry

Consistent with the 

GALL Report

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including 

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-71)

Cracking 

caused by 

stress corrosion 

cracking or 

other 

mechanism(s); 

loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Steam 

Generators and 

Water 

Chemistry

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-277

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel steam 

generator tube 

support plate, tube 

bundle wrapper, 

supports, and 

mounting hardware 

exposed to 

secondary feedwater 

or steam (3.1.1-72)

Loss of material 

caused by 

erosion, 

general, pitting, 

and crevice 

corrosion, 

ligament 

cracking caused 

by corrosion

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Steam 

Generators and 

Water 

Chemistry

Consistent with the 

GALL Report

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

phosphate chemistry 

in secondary 

feedwater or steam 

(3.1.1-73)

Loss of material 

caused by 

wastage and 

pitting corrosion

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Steel steam 

generator upper 

assembly and 

separators including 

feedwater inlet ring 

and support exposed 

to secondary 

feedwater or steam 

(3.1.1-74)

Wall thinning 

caused by 

flow-accelerated 

corrosion

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Steam 

Generators and 

Water 

Chemistry

Consistent with the 

GALL Report

Steel steam 

generator tube 

support lattice bars 

exposed to 

secondary feedwater 

or steam (3.1.1-75)

Wall thinning 

caused by 

flow-accelerated 

corrosion and 

general 

corrosion

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including 

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-76)

Loss of material 

caused by 

fretting

Chapter XI.M19, 

“Steam Generators”

No Steam 

Generators

Consistent with the 

GALL Report

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

or steam (3.1.1-77)

Loss of material 

caused by wear 

and fretting

Chapter XI.M19, 

“Steam Generators”

No Steam 

Generators

Consistent with the 

GALL Report

Nickel alloy steam 

generator 

components such as 

secondary side 

nozzles (vent, drain, 

and instrumentation) 

exposed to 

secondary feedwater 

or steam (3.1.1-78)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection,” or 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD.” 

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-278

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and 

nickel-alloy reactor 

coolant pressure 

boundary 

components 

exposed to reactor 

coolant (3.1.1-79)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.1.2.1.1)

Stainless steel or 

steel with stainless 

steel cladding 

pressurizer relief 

tank: tank shell and 

heads, flanges, 

nozzles 

(none-ASME 

Section XI 

components) 

exposed to treated 

borated water 

>60 °C (>140 °F) 

(3.1.1-80)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-81)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Nickel alloy 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-82)

Cracking 

caused by 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Steel steam 

generator shell 

assembly exposed 

to secondary 

feedwater or steam 

(3.1.1-83)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Steel top head 

enclosure (without 

cladding) top head 

nozzles (vent, top 

head spray or RCIC, 

and spare) exposed 

to reactor coolant 

(3.1.1-84)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-279

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel, 

nickel-alloy, and 

steel with 

nickel-alloy or 

stainless steel 

cladding reactor 

vessel flanges, 

nozzles, 

penetrations, safe 

ends, vessel shells, 

heads and welds 

exposed to reactor 

coolant (3.1.1-85)

Loss of material

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Stainless steel 

steam generator 

primary side divider 

plate exposed to

reactor coolant 

(3.1.1-86)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy PWR 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-87)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry” 

No Water 

Chemistry

Consistent with the 

GALL Report (see 

SER 

Section 3.1.2.1.4)

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and 

nickel-alloy reactor 

coolant pressure 

boundary 

components 

exposed to reactor 

coolant (3.1.1-88)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Water 

Chemistry

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-89)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-90)

Loss of material 

caused by 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems 

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-280

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-91)

Cracking 

caused by 

stress corrosion 

cracking; loss of 

material caused 

by general, 

pitting, and 

crevice 

corrosion, or 

wear (BWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-92)

Cracking 

caused by 

stress corrosion 

cracking; loss of 

material caused 

by general, 

pitting, and 

crevice 

corrosion, or 

wear (PWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting”

No Reactor Head 

Closure Stud 

Bolting

Consistent with the 

GALL Report

Copper-alloy >15% 

Zn or > 8% Al piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-93)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching “

No Not applicable Not applicable to 

Callaway

(see SER 

Section 3.1.2.1.1)

Stainless steel and 

nickel alloy vessel 

shell attachment 

welds exposed to 

reactor coolant 

(3.1.1-94)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular

stress corrosion 

cracking

Chapter XI.M4, 

“BWR Vessel ID 

Attachment Welds,” 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Steel (with or without 

stainless steel 

cladding) feedwater 

nozzles exposed to 

reactor coolant 

(3.1.1-95)

Cracking 

caused by cyclic 

loading

Chapter XI.M5, 

“BWR Feedwater 

Nozzle”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Steel (with or without 

stainless steel 

cladding) control rod 

drive return line 

nozzles exposed to 

reactor coolant 

(3.1.1-96)

Cracking 

caused by cyclic 

loading

Chapter XI.M6, 

“BWR Control Rod 

Drive Return Line 

Nozzle”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-281

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel and 

nickel alloy piping, 

piping components, 

and piping elements 

greater than or equal 

to 4 NPS; nozzle 

safe ends and 

associated welds 

(3.1.1-97)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,” 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

penetrations: 

instrumentation and 

standby liquid 

control exposed to 

reactor coolant 

(3.1.1-98)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M8, 

“BWR Penetrations,” 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Cast austenitic 

stainless steel; PH 

martensitic stainless 

steel; martensitic 

stainless steel; 

X-750 alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-99)

Loss of fracture 

toughness 

caused by 

thermal aging 

and neutron 

irradiation 

embrittlement

Chapter XI.M9, 

“BWR Vessel 

Internals”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Stainless steel RVIs 

components (jet 

pump wedge 

surface) exposed to 

reactor coolant 

(3.1.1-100)

Loss of material 

caused by wear

Chapter XI.M9, 

“BWR Vessel 

Internals”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Stainless steel 

steam dryers 

exposed to reactor 

coolant (3.1.1-101)

Cracking 

caused by 

flow-induced 

vibration

Chapter XI.M9, 

“BWR Vessel 

Internals” for steam 

dryer

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Stainless steel fuel 

supports and control 

rod drive assemblies 

control rod drive 

housing exposed to 

reactor coolant 

(3.1.1-102)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Stainless steel and 

nickel alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-103)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assist

ed stress 

corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-282

Component Group

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

X-750 alloy RVI 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-104)

Cracking 

caused by 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals” for core 

plate, and Chapter 

XI.M2, “Water 

Chemistry”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.1.2.1.1)

Steel piping, piping 

components, and 

piping element 

exposed to concrete 

(3.1.1-105)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 2) plant OE 

indicates no 

degradation of the 

concrete

No, if 

conditions 

are met.

Not applicable Not applicable to 

Callaway (see SER 

Section 3.1.2.1.1)

Nickel alloy piping, 

piping components, 

and piping element 

exposed to air –

indoor, uncontrolled, 

or air with borated 

water leakage 

(3.1.1-106)

None None NA None Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping element 

exposed to gas, 

concrete, air with 

borated water 

leakage, air –

indoors, uncontrolled 

(3.1.1-107)

None None NA None Consistent with the 

GALL Report

(Not used)

(3.1.1-108)

(Not used) (Not used) (Not used) (Not used) (Not used)

(Not used)

(3.1.1-109)

(Not used) (Not used) (Not used) (Not used) (Not used)

Any material piping, 

piping components 

and piping elements 

exposed to reactor 

coolant (3.1.1-110)

Wall thinning 

due to erosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.1.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-283

3.1.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the reactor vessel, RVIs, and RCS components:

• ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

• Bolting Integrity

• Boric Acid Corrosion 

• Closed Treated Water Systems

• Cracking of Nickel-Alloy Components and Loss of Material due to Boric Acid-Induced 

Corrosion in Reactor Coolant Pressure Boundary Components

• External Surfaces Monitoring of Mechanical Components

• Flow-Accelerated Corrosion

• Flux Thimble Tube Inspection

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Lubricating Oil Analysis

• One-Time Inspection

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping

• PWR Vessel Internals

• Reactor Head Closure Stud Bolting

• Reactor Vessel Surveillance

• Steam Generator

• Water Chemistry

LRA Tables 3.1.2-1 through 3.1.2-4 summarize the results of AMRs for the reactor vessel, RVIs, 

and RCS 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 if the plant-specific components in these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR item describing how the information in the tables 

aligns with the information in the GALL Report. The staff reviewed those AMRs with notes A–E, 

which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these AMR items to confirm consistency with the GALL Report and the 

validity of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 
AGING MANAGEMENT REVIEW RESULTS

3-284

identified in the GALL Report. The staff reviewed these AMR items to confirm consistency with 

the GALL Report and ensure that the applicant reviewed and accepted the identified exceptions 

to the GALL Report AMPs. The staff also determined whether the AMP identified by the 

applicant was consistent with the AMP identified in the GALL Report and whether the AMR was 

valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

AMR items to confirm consistency with the GALL Report. The staff also determined whether the 

AMR item of the different component applied to the component under review and whether the 

AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, 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 AMR 

items to confirm consistency with the GALL Report. The staff confirmed whether the AMR item 

of the different component was applicable to the component under review and whether the 

exceptions to the GALL Report AMPs 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 item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff reviewed these items 

to confirm consistency with the GALL Report and determined whether the identified AMP would 

manage the aging effect consistent with the AMP identified in the GALL Report and whether the 

AMR was valid for the site-specific conditions.

The staff 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 confirm that the material presented in 

the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. 

The staff’s evaluation is discussed below.

3.1.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.1-1, items 3.1.1-11, 3.1.1-29, 3.1.1-41, 3.1.1-43, 3.1.1-79, 3.1.1-84, 3.1.1-85, 

3.1.1-91, 3.1.1-94 through 3.1.1-104, and 3.1.1-110, the applicant claimed that the 

corresponding AMR items in the GALL Report are not applicable because the associated items 

are only applicable to BWRs. The staff reviewed the SRP-LR, confirmed these items only apply 

to BWRs, and finds that these items are not applicable to Callaway, which is a PWR.

For LRA Table 3.1-1, items 3.1.1-34, 3.1.1-44, 3.1.1-51, 3.1.1-52, 3.1.1-55, 3.1.1-56, 3.1.1-58, 

3.1.1-68, 3.1.1-73, 3.1.1-75, 3.1.1-82, 3.1.1-86, and 3.1.1-93, the applicant claimed that the 

corresponding items in the GALL Report are not applicable because the component, material, 

and environment combination described in the SRP-LR does not exist for in-scope SCs at 

Callaway. The staff reviewed the LRA and FSAR and confirmed that the applicant’s LRA does 

not have any AMR results applicable for these items.
AGING MANAGEMENT REVIEW RESULTS

3-285

For LRA Table 3.1-1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable; however, the staff non-applicability verification of 

these items required the review of sources beyond the LRA and FSAR, and/or the issuance of 

RAIs.

LRA Table 3.1-1, item 3.1.1-50 addresses CASS Class 1 piping, piping component, and piping 

elements and control rod drive pressure housings exposed to reactor coolant greater than 

250 °C (482 °F). SRP-LR Table 3.1-1, item 3.1.1-50 recommends GALL AMP XI.M12, “Thermal 

Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)” to manage loss of fracture 

toughness due to thermal aging embrittlement of these components. For LRA item 3.1.1-50, the 

applicant stated that portions of the Callaway reactor coolant loops are constructed of CASS 

and that the straight piping pieces were centrifugally cast and the fittings were statically cast. 

The applicant also stated that thermal aging of Callaway CASS reactor coolant piping 

components and fittings is not a concern because the molybdenum and ferrite values for these 

piping pieces and fittings are below the thermal aging significance threshold.

In its review, the staff noted that Callaway FSAR Table 5.2-2 indicates that the reactor coolant 

pipe is made of centrifugal-cast SA-351, Grade CF8A and the reactor coolant fittings and 

branch nozzles are made of SA-351, Grade CF8A (cast stainless steel) and SA-182 (Code 

Case 1423-2), Grade 316N (non-cast stainless steel). The material information regarding CASS 

RCS components in the LRA and FSAR is summarized as follows.

• reactor coolant pipe: centrifugal-cast low-molybdenum CASS (SA-351, Grade CF8A)

• reactor coolant fittings: static-cast low-molybdenum CASS (SA-351, Grade CF8A)

• reactor coolant branch nozzles: low-molybdenum CASS (SA-351, Grade CF8A)

In comparison, GALL Report AMP XI.M12 states that for low-molybdenum content steels 

(SA-351 Grades CF3, CF3A, CF8, CF8A or other steels with molybdenum not exceeding 

0.5 weight percent), only static-cast steels with ferrite greater than 20 percent are potentially 

susceptible to thermal aging embrittlement. GALL Report AMP XI.M12 also indicates that in the 

susceptibility screening method, ferrite content is calculated by using the Hull’s equivalent factor 

(described in NUREG/CR-4513, Revision 1, “Estimation of Fracture Toughness of Cast 

Stainless Steels During Thermal Aging in LWR Systems,” issued May 1994), or a staff-approved 

method for calculating delta ferrite in CASS materials.

In its review, the staff finds that the reactor coolant piping, which is fabricated from 

low-molybdenum centrifugal-cast stainless steel, is not susceptible to thermal aging 

embrittlement, as described in the GALL Report. However, the staff needed to confirm that the 

applicant appropriately screened the susceptibility of other CASS components, consistent with 

the GALL Report, because the LRA does not clearly indicate that the applicant’s screening 

methodology is consistent with NUREG/CR-4513, Revision 1, as referenced in the GALL Report 

AMP XI.M12. In addition, the LRA does not clearly indicate whether the reactor coolant branch 

nozzles are made of static-cast material or centrifugal-cast material. Furthermore, the LRA 

does not provide the ferrite contents of the CASS fittings and branch nozzles. 

By letter dated August 16, 2012, the staff issued RAI 3.1.1.50-1 requesting that the applicant 

clarify whether the reactor coolant branch nozzles are made of static-cast CF8A material or 

centrifugal-cast CF8A material. The staff also requested that the applicant provide the 

bounding-case chemical composition of the reactor coolant fittings and branch nozzles that was 

used to estimate the highest ferrite content of these CASS components. In addition, the staff 

requested that the applicant provide the calculated ferrite content in order to confirm that these 
AGING MANAGEMENT REVIEW RESULTS

3-286

CASS components are not susceptible to thermal aging embrittlement. The staff further 

requested that as part of the response, the applicant clarify whether the applicant’s screening 

methodology is consistent with the guidance of NUREG/CR-4513, Revision 1, which uses the 

Hull’s equivalent factor as referenced in the GALL Report.

In its response dated September 20, 2012, the applicant stated that the CASS reactor coolant 

branch nozzles are made of static-cast CF8A material. The applicant provided the 

bounding-case chemical compositions that estimate the highest ferrite contents of the reactor 

coolant fittings and branch nozzles. The applicant also stated that the calculated ferrite 

contents are 19.65 percent and 18.69 percent for heat Nos. 3-3325 and 3-3447, respectively 

and that these values are below the 20 percent threshold value for static-cast CF8A material. 

The applicant further stated that the above ferrite content values were calculated using Hull’s 

equivalent factors in NUREG/CR-4513, Revision 1.

In its review of the applicant’s response, the staff confirmed that the bounding-case ferrite 

contents in terms of Hull’s equivalent factors are 19.65 percent and 18.70 percent for the fittings 

and branch nozzles, respectively. These ferrite contents do not exceed the susceptibility 

threshold of 20 percent for static-cast low-molybdenum CASS materials, consistent with the 

applicant’s determination. The staff finds the applicant’s response acceptable because the 

applicant confirmed that its calculations for the ferrite contents, using the alloy compositions are 

consistent with the guidance of CR/NUREG-4513, Revision 1, which is referenced in the GALL 

Report. Furthermore, the estimated ferrite contents indicate that the CASS materials for Class 1 

piping fittings and branch nozzles are not susceptible to thermal aging embrittlement. The 

staff’s concern described in RAI 3.1.1.50-1 is resolved.

In its review, the staff noted that Callaway FSAR, Table 5.2-2 indicates that the control rod drive 

latch housings are made of SA-182, Grade F304 (non-cast stainless steel) or SA-351, Grade 

CF8 (cast stainless steel). Given the information regarding the control rod drive latch housing 

materials in the FSAR, the staff needed to confirm whether SA-351, Grade CF8 (cast stainless 

steel) has been used for the control rod drive latch housings. If the CASS material has been 

used for the CRD latch housings, additional information would be necessary regarding the 

applicant's material screening method for thermal aging embrittlement of the CASS material.

By letter dated September 12, 2012, the staff issued RAI 3.1.1.50-2 requesting that the 

applicant clarify whether SA-351, Grade CF8, or SA-182, Grade F304, has been used for the 

control rod drive latch housings. In its response dated October 15, 2012, the applicant stated 

that the control rod drive latch housings and travel housings are made of forged Type 304 

stainless steel (non-cast stainless steel). The staff finds that the applicant’s response 

acceptable because these housings are made of non-cast Type 304 stainless steel so that they 

are not susceptible to thermal aging embrittlement. The staff’s concern described in RAI 

3.1.1.50-2 is resolved 

LRA Table 3.1.1, item 3.1.1-50 addresses CASS Class 1 piping, piping component, and piping 

elements and control rod drive pressure housings exposed to reactor coolant greater than 

250 °C (482 °F). The GALL Report recommends GALL AMP XI.M12, “Thermal Aging 

Embrittlement of Cast Austenitic Stainless Steel (CASS)” to manage loss of fracture toughness 

due to thermal aging embrittlement for this component group. The applicant stated that this 

item is not applicable because molybdenum and ferrite values for these piping components and 

fittings are below the thermal aging significance threshold. As described above, the staff 

evaluated the applicant’s claim and RAI responses and finds it acceptable because the casting 
AGING MANAGEMENT REVIEW RESULTS

3-287

methods and molybdenum and ferrite contents of the CASS components confirm that these 

components are not susceptible to thermal aging embrittlement, consistent with the GALL 

Report.

LRA Table 3.1-1, item 3.1.1-63 addresses steel or stainless steel closure bolting exposed to air 

with reactor coolant leakage. The GALL Report recommends GALL Report AMP XI.M18, 

“Bolting Integrity” to manage loss of material caused by general (steel only), pitting, and crevice 

corrosion or wear for this component group. The applicant stated that this item is not applicable 

because the item applies only to BWR plants. The staff lacks sufficient information to evaluate 

the applicant’s claim because although the SRP-LR states that item 3.1.1-63 is applicable to 

BWRs, the applicant has in-scope steel or stainless steel closure bolting exposed to borated 

water leakage. The staff noted that the applicant is managing these items for loss of preload 

and cracking, but not loss of material. The staff also noted that the applicant has in-scope steel 

and stainless steel closure bolting exposed to plant indoor air and atmosphere or weather 

environments that are being managed for loss of material. By letter dated August 16, 2012, the 

staff issued RAI 3.1.1.063-1 requesting that the applicant state the basis for why loss of material 

caused by general (steel only), pitting, and crevice corrosion or wear is not applicable to 

in-scope steel and stainless steel closure bolting exposed to air with reactor coolant leakage. 

In its response dated September 20, 2012, the applicant stated that the GALL Report for 

stainless steel closure bolting exposed to air with borated water leakage or air with PWR reactor 

coolant leakage identifies only cracking caused by SCC and loss of preload as applicable aging 

effects. However, the applicant also stated that to account for the loss of material aging effect

for those components, items have been added to LRA Tables 3.1.2-2, 3.2.2-1, 3.2.2-5, 3.3.2-2, 

3.3.2-10, and 3.3.2-28 for stainless steel closure bolting with an environment of plant indoor air 

and an aging effect of loss of material in systems which previously included stainless steel 

closure bolting in an environment of borated water leakage. 

The staff finds the applicant’s response acceptable because the applicant will manage the 

stainless steel closure bolting for loss of material. The staff notes that although the applicant 

has not identified loss of material as an aging effect for stainless steel closure bolting exposed 

to air with reactor coolant leakage, the applicant has still accounted for the loss of material aging 

effect by adding additional items for the stainless steel closure bolting components. The staff’s 

concern described in RAI 3.1.1.063-1 is resolved.

LRA Table 3.1-1, item 3.1.1-64 addresses steel closure bolting exposed to an air-indoor 

uncontrolled environment. The GALL Report recommends GALL Report AMP XI.M18, “Bolting 

Integrity” to manage loss of material caused by general, pitting, and crevice corrosion for this 

component group. The applicant stated that this item is not applicable because the steel 

closure bolting in the RCS is evaluated with the environment of air with borated water leakage. 

The staff evaluated the applicant’s claim and finds it acceptable because (1) the component 

group is managed for the loss of material aging effect through SPR-LR Table 3.1-1, 

item 3.1.1-49, which recommends that steel RCPB external surfaces or closure bolting exposed 

to air with borated water leakage be managed by the Boric Acid Corrosion Program and (2) the 

air with borated water leakage environment is a more aggressive environment than air-indoor 

uncontrolled, and is therefore a more conservative environment to identify for aging 

management.

LRA Table 3.1-1, item 3.1.1-65 addresses stainless steel control rod drive head penetration 

flange bolting exposed to air with reactor coolant leakage. The GALL Report recommends 

GALL Report AMP XI.M18, “Bolting Integrity” to manage loss of material caused by wear for this 
AGING MANAGEMENT REVIEW RESULTS

3-288

component group. The applicant stated that this item is not applicable because Callaway has 

stainless steel control rod drive head penetration flanges that are seal welded instead of bolted. 

The staff evaluated the applicant’s claim and finds it acceptable because the staff reviewed the 

LRA and FSAR and confirmed that the applicant does not have any in-scope components that 

are applicable for this item. 

3.1.2.1.2 Management of Aging Effects for PWR Vessel Internals – AMR Items in the Callaway 

LRA Not Tied to SRP-LR Further Evaluation Recommendations for PWR RVI 

Components 

LRA Table 3.1-1 includes AMR items that are based on SRP-LR, Table 3.1-1 AMR item that are 

applicable to Westinghouse-designed RVI component commodity groups. These AMR items 

include the following LRA Table 3.1-1 AMR items that are based on the staff’s further evaluation 

“acceptance criteria” recommendations for PWR RVI components in SRP-LR Section 3.1.2.2:

• item 3.1.1-3 on evaluation of cumulative fatigue damage in the RVI components that are 

defined as core support structure components, which is based on a comparison to the 

staff’s recommended further evaluation “acceptance criteria” recommendations in 

SRP-LR Section 3.1.2.2.1 and the AMR criteria in SRP-LR Table 3.1-1, item No. 3

• item 3.1.1-23 on evaluation of cracking in inaccessible areas of the RVI components, 

which is based on a comparison to the staff’s recommended further evaluation 

“acceptance criteria” recommendations in SRP-LR Section 3.1.2.2.9 and the AMR 

criteria in SRP-LR Table 3.1-1, item No. 23

• item 3.1.1-24 on evaluation of loss of material caused by wear, loss of fracture 

toughness, changes in dimension, loss of preload in inaccessible areas of the RVI 

components, which is based on a comparison to the staff’s recommended further 

evaluation “acceptance criteria” recommendations in SRP-LR Section 3.1.2.2.10 and the 

AMR criteria in SRP-LR Table 3.1-1, item No. 24 

• item 3.1.1-26 on management of cracking caused by fatigue, which is based on a 

comparison to the staff’s recommended further evaluation “acceptance criteria” 

recommendations in SRP-LR Section 3.1.2.2.12 and the AMR criteria in SRP-LR 

Table 3.1-1, item No. 26

• item 3.1.1-27 on management of cracking caused by SCC and fatigue of CRGT pins, 

which is based on a comparison to the staff’s recommended further evaluation 

“acceptance criteria” recommendations in SRP-LR Section 3.1.2.2.13 and the AMR 

criteria in SRP-LR Table 3.1-1, item No. 27

• AMR item 3.1.1-28 on management of loss of material caused by wear in CRGT pins, 

which is based on a comparison to the staff’s recommended further evaluation 

“acceptance criteria” recommendations in SRP-LR Section 3.1.2.2.14 and the AMR 

criteria in SRP-LR Table 3.1-1, item No. 28

The staff evaluates these AMR items in SER Sections 3.1.2.2.1, 3.1.2.2.9, 3.1.2.2.10, 

3.1.2.2.12, 3.1.2.2.13, and 3.1.2.2.14, respectively.

The remaining AMR items for the PWR RVI component commodity groups in LRA Table 3.1-1 

include LRA items 3.1.1-32, 3.1.1-53, 3.1.1-59, and 3.1.1-87, each of which invokes specific 

Table 2 AMR items for PWR RVI components in LRA Table 3.1.2-1. The staff evaluates these 

Table 1 AMR items in the following SER Sections: (a) SER Section 3.1.2.1.3 for items 3.1.1-32, 

3.1.1-53, and 3.1.1-59, as related to the assessment of cracking caused by SCC, 
AGING MANAGEMENT REVIEW RESULTS

3-289

irradiated-assisted stress corrosion cracking (IASCC), or fatigue; loss of material caused by 

wear; loss of fracture toughness caused by neutron irradiation embrittlement, void swelling, or 

thermal aging; changes in dimension caused by distortion or void swelling; and loss of preload 

caused by stress relaxation or irradiation-assisted stress relaxation or creep in PWR RVI 

components; and (b) SER Section 3.1.2.1.4 for item 3.1.1-87, as related to the assessment of 

loss of material induced by a pitting or crevice corrosion mechanism. 

The following clarifications need to be made for those RVI components listed in LRA 

Table 3.1.2-1 that will be managed using the applicant’s PWR Vessel Internals Program and 

whose Table 2 AMR items are referenced to by either LRA Table 1 AMR items 3.1.1-53 or 

3.1.1-59. The applicant’s PWR Vessel Internals Program is identified and defined as a new 

program that is consistent with the program element criteria in GALL Report AMP XI.M16A, 

“PWR Vessel Internals.” GALL Report AMP XI.M16A recommends management of cracking 

because of SCC, IASCC, or fatigue; loss of fracture toughness caused by neutron irradiation 

embrittlement, void swelling or thermal aging; changes in dimension caused by distortion or void 

swelling; loss of material caused by wear; or for RVI mechanical connections (such as bolted, 

spring loaded, pinned, keyed, or other types of fastened connections), loss of preload caused by 

stress relaxation or irradiation-assisted creep using the sampling-based condition monitoring 

basis that is defined in the EPRI Report No. 1022863, “Materials Reliability Program: 

Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227-A).” The 

MRP-227-A report was approved in the staff’s revised safety evaluation (SE, Revision 1) on the 

report’s methodology dated December 16, 2011. Thus, the applicant’s PWR Vessel Internals 

Program is a sampling-based condition monitoring program that is based on the 

sampling-based augmented inspection methodology in the MRP-227-A report and is in 

conformance with the staff’s criteria for sampling-based condition monitoring programs in 

Appendix A.1, “Aging Management Review – Generic (Branch Technical Position RLSB-1),” of 

the SRP-LR. In the MRP-227-A report, the EPRI MRP established and implemented specific 

“Failure Modes, Effects, and Criticality Analyses [FMECAs]” and “Functionality Analyses” for all 

of RVI components that could be included within the scope of a Westinghouse-defined nuclear 

power plant facility and used these analyses to break down the population of RVI components 

into the following categories of components (i.e., the component samples):

(a) “Existing Program” – RVI components that would be subject to condition monitoring 

(inspection) because they were within specific existing inspection programs at the 

facilities. Examples are the ASME Section XI Inservice Inspection, Subsection IWB, 

IWC, and IWD Program for RVI components defined as ASME Section XI, Examination 

Category B-N-3 RVI core support structure components, or for RVI flux thimble tubes, a 

Westinghouse-design applicant’s NRC Bulletin 88-09-based Flux Thimble Tube 

Inspection Program.

(b) “Primary Category” – RVI components that would be inspected using the EPRI MRP’s 

recommended augmented inspection bases in the MRP-227-A report. For 

Westinghouse-designed RVI components, the EPRI MRP’s augmented inspection bases 

for “Primary Category” components are given in Table 4-3 of the MRP-227-A report and 

the acceptance criteria for the augmented inspections of these components are given in 

Table 5-3 of the MRP-227-A report.

(c) “Expansion Category” – RVI components that are linked to specific “Primary Category” 

components and for whom the augmented inspections would be expanded to if relevant 

evidence of aging was detected in the “Primary Category” RVI component for a specific 

“Primary Category” component – “Expansion Category” component pair combination. 
AGING MANAGEMENT REVIEW RESULTS

3-290

(d) “No Additional Measures” – components, which constitute the remaining components in 

RVI component population. Under the EPRI MRP defined methodology, these 

components would not be inspected because either there weren’t any aging effect 

mechanisms that were applicable to the components or, if there were applicable aging 

effects and mechanisms, there would not be any consequence from a failure of the RVI 

component by the aging effect or effects that were applicable to the component. 

However, the EPRI MRP clarifies that, even though a “No Additional Measures” 

component is not inspected in accordance with MRP-227-A methodology basis, the 

component will need to be inspected under the applicant’s ASME Section XI Inservice 

Inspection Program if the RVI component is defined in the CLB as an ASME Code 

Section XI, Examination Category B-N-3 core support structure component.

In the NRC’s SE, Revision 1 on the MRP-227-A methodology, the staff identified a number of 

license renewal aging management areas that would need to be addressed on a plant-specific 

assessment by Westinghouse-design PWR license renewal applicants. The staff identified 

these topical areas as applicable A/LAIs on use of the MRP-227-A methodology. In the SE, 

Revision 1 on the MRP-227-A report, the staff stated that PWR license renewal applicants 

should provide in their LRAs responses to both the generic A/LAIs on the MRP-227-A 

methodology and the NSSS-specific A/LAIs that were applicable to the design of their facilities. 

The staff has reflected this need in RIS 2011-07, “License Renewal Submittal Information for 

Pressurized Water Reactor Internals Aging Management,” dated July 21, 2011. These A/LAI 

responses are important because the A/LAI responses will be used as part of the applicant’s 

integrated plant assessment for determining whether the applicant would need to establish and 

implement any plant-specific enhancements of its RVI Management program beyond the 

generic aspects of the program that would be implemented in accordance with the MRP-227-A 

methodology. 

The staff noted that the LRA, when submitted to the staff for review, did not include any of the 

applicant’s responses to the A/LAIs on MRP-227-A methodology. Therefore, by letter dated 

September 25, 2012, the staff issued RAI B2.1.6-4 requesting that the applicant provide its 

basis for omitting responses to the applicable A/LAIs on MRP-227-A methodology that are 

determined to be applicable to Westinghouse-designed RVI components at the Callaway Plant. 

Alternatively, the staff informed the applicant that it could amend its LRA to include the 

appropriate responses to those A/LAIs that have been issued on the MRP-227-A report and are 

applicable to the design of the Westinghouse-designed RVI components at the Callaway Plant. 

Consistent with the “scope of program” element in GALL Report AMP XI.M16A, “PWR Vessel 

Internals,” the applicant’s response bases to the A/LAIs on MRP-227-A report are 

recommended to be included in the “scope of program” element of the applicant PWR Vessel 

Internals Program. The applicant responded to RAI B2.1.6-4 in a letter dated October 24, 2012. 

The staff’s evaluation of the applicant’s response to RAI B2.1.6-4 is documented in SER 

Section 3.0.3.1.5, which is the SER section that provides the staff’s evaluation of the applicant’s 

PWR Vessel Internals Program and the responses to these A/LAIs.

The staff also noted that the Table 2 AMR item component nomenclatures in LRA Table 3.1.2-1 

for a number of Callaway RVI components did not entirely match the generic nomenclatures for 

these components in either Table IV.B2 of the GALL Report or in the EPRI MRP’s 

recommended generic methodology for Westinghouse-designed RVI components, as given in 

MRP-227-A. Therefore, by letter dated September 12, 2012, the staff issued RAI 3.1.2.1-1 

requesting additional clarifications on the component nomenclatures that were used for various 

RVI components associated AMR items in LRA Table 3.1.2-1. In its response dated 
AGING MANAGEMENT REVIEW RESULTS

3-291

October 15, 2012, the applicant provided the following additional information to address the 

staff’s concerns described in Requests (a) through (k) of RAI 3.1.2.1-1:

RAI 3.1.2.1-1, Part (a): For the two AMR items associated with the RVI baffle-former assembly 

on LRA page 3.1-69, the staff requested the applicant to clarify which specific baffle-former 

assembly components are within the scope of the AMR items. In response to this part of the 

RAI, the applicant clarified that the components in the AMRs for the RVI baffle-former assembly 

include the baffle plates and the former plates. The staff finds that the applicant’s clarification 

demonstrates that components in the AMR items are in conformance with the basis in 

MRP-227-A for inspecting the baffle plates and former plates in Westinghouse-design core 

barrel assemblies and covers management of both loss of material because of pitting and 

crevice corrosion, as recommended in GALL Report AMP IV.B2.RP-270, and changes in 

dimension, as recommended in GALL Report AMR item IV.B2.RP-24. Thus, the staff finds that 

these AMR items are acceptable because they demonstrate consistency the GALL Report AMR 

items IV.B2.RP-24 and IV.B2.RP-270 and with the inspection bases for these components in 

the MRP-227-A report. RAI 3.1.2.1-1, Part (a), is resolved.

RAI 3.1.2.1-1, Part (b): For the four AMRs associated with the RVI baffle-former assembly 

bolting at the bottom of LRA page 3.1-69 and top of page 3.1-70, the staff requested the 

applicant to clarify whether the AMR items are referring to baffle-to-former bolts or to otherwise 

identify which specific bolts are within the scope of the AMR items. In response to this part of 

the RAI, the applicant clarified that these AMR items are referring to the baffle-to-former bolts. 

The staff notes that the applicant’s clarification demonstrates that the components in these AMR 

items are in conformance with the basis in MRP-227-A for inspecting Westinghouse-design 

baffle-to-former bolts as MRP-227-A “Primary Category” components and that the AMR items 

are in conformance with the following AMR items for Westinghouse-design baffle-to-former bolts 

in the GALL Report: (a) AMR item IV.B2.RP-24 for managing loss of material caused by pitting 

and crevice corrosion; (b) AMR item IV.B2.RP-271 for managing cracking; (c) AMR 

item IV.B2.RP-272 for managing loss of fracture toughness, changes in dimension, and loss of 

preload; and (d) AMR item IV.B2.RP-303 for managing cumulative fatigue damage. Thus, the 

staff finds that these LRA AMR items are acceptable because the applicant has demonstrated 

consistency with the AMR item bases for the components in the GALL Report and with the 

inspection bases for these components in the MRP-227-A report. RAI 3.1.2.1-1, Part (b), is 

resolved.

RAI 3.1.2.1-1, Part (c): For the four AMR items associated with the RVI CRGT assembly on 

LRA page 3.1-71, the staff requested the applicant to clarify which of the specific CRGT 

assembly components are within the scope of the AMR items. In response to this part of the 

RAI, the applicant clarified that these AMR items are referring to the lower flange welds and the 

adjacent base metal of the CRGT assemblies. The applicant also clarified that the AMR items 

for the CRGT bolts, guide plates (cards) and support pins (split pins) are evaluated in separate 

AMR items in LRA Table 3.1.2-1. The staff notes that the applicant’s clarification demonstrates 

that the components in these AMR items are in conformance with the basis in MRP-227-A for 

inspecting Westinghouse-design CRGT lower flange welds as MRP-227-A “Primary Category” 

components and with the following AMR items for Westinghouse-design CRGT lower flange 

welds in the GALL Report: (a) AMR item IV.B2.RP-24 for managing loss of material caused by 

pitting and crevice corrosion, (b) AMR item IV.B2.RP-298 for managing cracking, (c) AMR 

item IV.B2.RP-297 for managing loss of fracture toughness, and (d) AMR item IV.B2.RP-303 for 

managing cumulative fatigue damage. Thus, the staff finds that these LRA AMR items are 

acceptable because the applicant has demonstrated consistency with the AMR item bases for 
AGING MANAGEMENT REVIEW RESULTS

3-292

the components in the GALL Report and with the “Primary Category” inspection bases for these 

components in the MRP-227-A report. RAI 3.1.2.1-1, Part (c), is resolved.

RAI 3.1.2.1-1, Part (d): For the two AMR items associated with RVI CRGT bolts listed on LRA 

page 3.1-72, the staff requested the applicant to identify which specific bolts are within the 

scope of the AMR items. In response to this request, the applicant stated that, consistent with 

the basis in FSAR Section 3.9(N).5, the CRGTs are fastened to the top support plate, but are 

not included in the scope of the MRP-227-A report. Therefore, the applicant clarified that the 

aging evaluation and aging management basis for these CRGT bolts is based on consistency 

with GALL Report AMR item IV.B2.RP-24 for managing loss of material in the components 

caused by pitting and crevice corrosion and with GALL Report AMR item IV.B2.RP-382 for 

managing cracking and loss of material caused by wear in the components, as indicated in the 

amended LRA AMR item provided in its response. The staff finds that these LRA AMR items 

are acceptable because the applicant has demonstrated consistency with the AMR item bases 

for the components in the GALL Report and will inspect these components in accordance with 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, even though 

the components are defined the MRP-227-A report as “No Additional Measures” components. 

RAI 3.1.2.1-1, Part (d), is resolved.

RAI 3.1.2.1-1, Part (e): For the three AMR items associated with the RVI core barrel or core 

barrel assembly on LRA page 3.1-73, the staff requested the applicant to identify which of the 

specific core barrel assembly components are within the scope of the AMR items. In response 

to this request, the applicant stated that the core barrel cylinder welds, flange and flange welds, 

and outlet nozzle and nozzle welds are addressed in separate AMR items in LRA Table 3.1.2-1. 

The applicant clarified that the subject AMR items of this RAI request are referring to the 

balance of the core barrel assembly, which is not specifically addressed in MRP-227-A report. 

The applicant also stated that the aging evaluation and aging management basis for the 

balance of the core barrel assembly is based on GALL Report items IV.B2.RP-24 and 

IV.B2.RP-382. The applicant further stated that the AMR item for managing cumulative fatigue 

damage in the core barrel assembly applies to the whole assembly and its subcomponents and 

credits the metal fatigue TLAA as the basis for managing cumulative fatigue damage of these 

components. The staff finds that these LRA AMR items are acceptable because the applicant 

has demonstrated consistency of the AMR items for the remainder of the core barrel assembly 

with the AMR item bases for the core barrel assembly in the GALL Report and will inspect these 

components in accordance with ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program. RAI 3.1.2.1-1, Part (e), is resolved.

RAI 3.1.2.1-1, Part (f): For the three AMR associated with the RVI core barrel assembly former 

bolting on LRA pages 3.1-73 and 3.1-74, the staff requested the applicant to clarify whether the 

AMR items are referring to core barrel-to-former bolts, as defined in MRP-227-A. Otherwise, 

the staff requested the applicant to identify which specific bolts are within the scope of the AMR 

items. In response to this request, the applicant stated that AMR items are presented in the 

LRA as “RVI core barrel assembly-former bolting,” consistent with MRP-227-A, Tables 3-3 and 

4-5, but are referring to core barrel assembly barrel-to-former bolts, as described in GALL 

Report AMR items IV.B2.RP-273 and IV.B2.RP-274. The staff notes that the applicant’s 

clarification demonstrates that the AMR basis for these components is in conformance with the 

basis in MRP-227-A for inspecting Westinghouse-design barrel-to-former bolts as EPRI 

MRP-defined “Expansion Category” components and the following AMR items for 

Westinghouse-design barrel-to-former bolts in the GALL Report: (a) AMR item IV.B2.RP-24 for 

managing loss of material caused by pitting and crevice corrosion; (b) AMR item IV.B2.RP-273 

for managing cracking; and (c) AMR item IV.B2.RP-274 for managing loss of fracture 
AGING MANAGEMENT REVIEW RESULTS

3-293

toughness, loss of preload, and changes in dimension. Thus, the staff finds that these AMR 

items in the LRA are acceptable because the applicant has demonstrated consistency with the 

AMR item bases for the components in the GALL Report and with the inspection bases for 

these components in the MRP-227-A report. RAI 3.1.2.1-1, Part (f), is resolved.

RAI 3.1.2.1-1, Part (g): For the two AMR items associated with the RVI head/vessel alignment 

pins on LRA page 3.1-75, the staff requested the applicant to clarify whether these components 

correspond to the upper core plate alignment pins in MRP-227-A (i.e., alignment and interfacing 

components in MRP-227-A Table 3-3). Otherwise, the staff requested the applicant to clarify 

where the pins are located and which MRP-227-A defined RVI assembly corresponds to the 

location of these pins. The applicant responded that the RVI head/vessel alignment pins are 

shown in FSAR Figure 3.9(N)-3 as item No. 31. The applicant clarified that the upper core plate 

alignment pins referred to in the MRP-227-A report are listed in LRA Table 3.1.2-1 as "RVI 

upper core plate guide pins" (to avoid confusion with fuel alignment pins that are attached to the 

bottom of the upper core plate) and are listed in FSAR Figure 3.9(N)-3 as item No. 19. The 

applicant stated that the RVI head/vessel alignment pins are not included in the scope of 

inspections defined in the MRP-227-A report, as the components were screened as 

Category “A” “No Additional Measures” component in MRP-191, Table 7-2. The applicant also 

stated that the aging evaluation and aging management basis is therefore based on 

conformance with GALL Report AMR items IV.B2.RP-24 and IV.B2.RP-382. The staff finds that 

these LRA AMR items are acceptable because the applicant has demonstrated consistency of 

the AMR items for the RVI head/vessel pins with the AMR item bases for the core barrel 

assembly in the GALL Report and will inspect these components in accordance with ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. RAI 3.1.2.1-1, 

Part (g), is resolved.

RAI 3.1.2.1-1, Part (h): For the two AMR items associated with the RVI incore instrumentation 

(ICI) core support structure bolting on LRA page 3.1-76; the staff requested the applicant to 

clarify where the bolts are located and which MRP-227-A defined RVI assembly corresponds to 

the location of these bolts. The applicant responded that the RVI ICI core support structure 

bolting referred to in the AMR items represent the lower core ICI support BMI column bolts. The 

applicant stated that the lower core BMI column bolts are shown in FSAR Figure 3.9(N)-3 as 

item No. 27. The applicant also stated that these bolts are not included in the scope of the 

MRP-227-A methodology, as they were screened out as Category “A” “No Additional Measures” 

components in MRP-191, Table 7-2 and that the aging evaluation and aging management basis 

is therefore based on conformance with GALL Report AMR items IV.B2.RP-24 and 

IV.B2.RP-382. The staff finds that these LRA AMR items are acceptable because the applicant 

has demonstrated consistency of the AMR items for the lower core ICI support BMI column 

bolts with the corresponding AMR item bases in the GALL Report and will inspect these 

components in accordance with ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program. RAI 3.1.2.1-1, Part (h), is resolved.

RAI 3.1.2.1-1, Part (i): For the three AMR associated with the RVI ICI support structure-BMI 

instrument columns on LRA pages 3.1-76 and 3.1-77, the staff requested the applicant to clarify 

whether the AMR items are referring to BMI column bodies. Otherwise, the staff requested the 

applicant to identify which specific BMI column components are within the scope of the AMR 

items. In its response the applicant confirmed that the AMR items are based on FSAR Figure 

3.9(N)-8 and are referring to BMI column bodies in the BMI system, as described in MRP-227-A, 

Table 4-6. The staff confirmed that, under the MRP-227-A methodology basis, the applicant 

would inspect these components as “Expansion Category” components for the PWR Vessel 

Internals based on the results of the “Primary Category” inspections that would be performed on 
AGING MANAGEMENT REVIEW RESULTS

3-294

the CRGT lower flange under this AMP. The staff also confirmed that the AMR items for the 

BMI column bodies were in conformance with the following GALL Report AMR items: (a) AMR 

item IV.B2.RP-24 for managing loss of material caused by pitting and crevice corrosion; 

(b) GALL Report AMR item IV.B2.RP-292 for managing loss of fracture toughness; and 

(c) GALL Report AMR item IV.B2.RP-293 for managing cracking. Thus, the staff finds that 

these LRA AMR items are acceptable because the applicant has demonstrated consistency with 

the AMR item bases for the components in the GALL Report and with the inspection bases for 

these components in the MRP-227-A report. RAI 3.1.2.1-1, Part (i), is resolved.

RAI 3.1.2.1-1, Part (j): For two AMR items associated with the RVI lower core support-energy 

absorber assembly on LRA page 3.1-81, the staff requested the applicant to identify which 

energy absorber assembly components are within the scope of the AMR items and to clarify 

which MRP-227-A defined assembly corresponds to the location of the components. The 

applicant responded that the function of the energy absorber assembly is described in FSAR 

Section 3.9(N).5, and that assuming a downward vertical displacement, the potential energy of 

the system is absorbed mostly by the strain energy of the energy absorbing devices. The 

applicant stated that the details of the energy absorber assembly are shown in FSAR Figure 

3.9(N)-8, but the components of the energy absorber assembly were not included in the scope 

of MRP-227-A as they were screened as Category “A” “No Additional Measures” components in 

MRP-191, Table 7-2. The staff finds that the applicant’s aging evaluation and aging 

management basis for the energy absorber assembly is therefore based on conformance with 

GALL Report AMR items IV.B2.RP-24 and IV.B2.RP-382. The staff also finds that these LRA 

AMR items are acceptable because the applicant has demonstrated consistency of the AMR 

items for the energy absorber assembly with the corresponding AMR item bases in the GALL 

Report and will inspect these components in accordance with ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program. RAI 3.1.2.1-1, Part (j), is resolved.

RAI 3.1.2.1-1, Part (k): For three AMRs associated with the RVI upper core plate guide pins on 

LRA pages 3.1-82 and 3.1-83, the staff requested the applicant to clarify whether the AMR 

items correspond to the upper core plate alignment pins listed as “Alignment and Interfacing” 

“Existing Program” components in MRP-227-A Table 3-3. Otherwise, the staff requested the 

applicant to clarify where these pins are located and which MRP-227-A defined RVI assembly 

corresponds to the location of the pins. The applicant responded that the AMR items for the 

RVI upper core plate guide pins correspond to the upper core plate alignment pins described in 

MRP-227-A, Tables 3-3 and 4-9 and that they are listed in LRA Table 3.1.2-1 as RVI upper core 

plate guide pins, consistent with the description in FSAR Figure 3.9(N)-8, to avoid confusion 

with fuel alignment pins that are attached to the bottom of the upper core plate. The applicant 

stated that the fuel alignment pins are evaluated as integral parts of the upper core plate. The 

staff confirmed that, under the MRP-227-A methodology basis, the applicant would inspect 

these components as ASME Code Section XI, “Existing Program,” components under the PWR 

Vessel Internals Program. The staff also confirmed that the AMR items for the RVI upper core 

plate guide pins were in conformance with the following GALL Report AMR items for these 

components: (a) AMR item IV.B2.RP-24 for managing loss of material caused by pitting and 

crevice corrosion; (b) GALL Report AMR item IV.B2.RP-292 for managing loss of material due 

to wear; and (c) GALL Report AMR item IV.B2.RP-301 for managing cracking. Thus, the staff 

finds that these LRA AMR items are acceptable because the applicant has demonstrated 

consistency with the AMR item bases for the components in the GALL Report and with the 

inspection bases for these components in the MRP-227-A report. RAI 3.1.2.1-1, Part (k), is 

resolved.
AGING MANAGEMENT REVIEW RESULTS

3-295

Based on its review of the applicant’s responses to RAI 3.1.2.1-1, Parts (a) through (k), as 

discussed above, the staff’s concerns described in RAI 3.1.2.1-1 are 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).

3.1.2.1.3 Cracking due to Stress Corrosion Cracking, Irradiation Assisted Stress Corrosion 

Cracking, or Fatigue; Loss of Material due to Wear; Loss of Fracture Toughness 

due to Neutron Irradiation Embrittlement, Void Swelling, or Thermal Aging; Changes 

in Dimension due to Distortion or Void Swelling; and Loss of Preload due to Stress 

Relaxation or Irradiation-Assisted Stress Relaxation or Creep

In LRA Table 3.1.2-1, the applicant aligns its AMR items on cracking of specific RVI 

components to either the its basis for managing this aging effect in LRA Table 3.1-1, 

item 3.1.1-32 or in LRA Table 3.1-1, item 3.1.1-53. In LRA Table 3.1.2-1, the applicant aligns its 

AMR items on loss of material due to wear of specific RVI components to either the applicant’s 

basis for managing this aging effect in LRA Table 3.1-1, item 3.1.1-32 or in LRA Table 3.1-1, 

item 3.1.1-59.

In LRA Table 3.1.2-1, the applicant aligns its AMR items on loss of fracture toughness due to 

neutron irradiation embrittlement, void swelling, or thermal aging; changes in dimension 

because of distortion or void swelling; and loss of preload caused by stress relaxation or 

irradiation-assisted stress relaxation or creep of specific RVI components to its basis for 

managing these aging effects in LRA Table 3.1-1, item 3.1.1-059.

LRA Table 3.1-1, item 3.1.1-32 addresses the Callaway RVI components made from either 

stainless steel or nickel alloy materials that are exposed to reactor coolant and neutron flux 

environment, which will be managed for the aging effect and mechanism combinations of 

cracking due to SCC, IASCC, or fatigue (cyclical loading) and loss of material caused by wear. 

The staff noted that Section 4.4.3 and Table 4-9 in the MRP-227-A report provide a list of those 

“Existing Program” components that are identified as ASME Code Section XI core support 

structure components. The MRP-227-A states that these components are examined per ASME 

Code Section XI Table IWB-2510, "Examination Category B-N-3 requirements.” During the 

audit, the staff noted that the applicant's program basis documents did not identify which RVI 

components were ASME Code Section XI, Examination Category B-N-3 RVI, components for 

the CLB, or whether the list of ASME Code Section XI, Examination Category B-N-3, 

components at Callaway include RVI core support structure components not accounted in 

Table 4-9 of the MRP-227-A report. The staff also noted that the applicant did not clarify 

whether the method of performing the VT-3 visual examination in accordance with applicable 

ASME Code Section XI examination category requirements would actually achieve coverage of 

those RVI components that were designated as ASME Code Section XI, Examination 

Category B-N-3, components at Callaway.

By letter dated July 18, 2012, the staff issued RAI B2.1.6-3. In Part (a) of the RAI the staff 

asked the applicant to identify all RVI component locations that are designated as ASME Code 

Section XI, Examination Category B-N-3, components at Callaway. In Part (b) of the RAI the 

staff asked the applicant to identify any ASME Code Section XI, Examination Category B-N-3, 

component locations and associated aging effects that are not assumed for and identified in 

Table 4-9 of the generic MRP-227-A methodology. In Part (c) of the RAI the staff asked the 
AGING MANAGEMENT REVIEW RESULTS

3-296

applicant to clarify and justify, based on previous ASME Code Section XI examinations of B-N-3 

component surfaces, whether the implementation of VT-3 examinations of these component 

surfaces would actually achieve coverage of those components locations that were defined as 

ASME Code Section XI, Examination Category B-N-3 component locations at Callaway.

By letter dated August 21, 2012, the applicant provided its response to RAI B2.1.6-3, 

Requests (a), (b), and (c). The staff’s full evaluation of the applicant’s response to 

RAI B2.1.6-3, Requests (a), (b), and (c) is documented in SER Section 3.0.3.1.5. The staff 

noted that the response to RAI B2.1.6-3, Requests (a), (b), and (c) confirms that the applicant 

will be crediting the inspection that will be performed in accordance with ASME Code 

Section XI, Examination Category B-N-3, requirements for all RVI components that are defined 

in the CLB as ASME Code Section XI, Examination Category B-N-3, core support structure 

components. The staff also noted, based on the applicant’s response to RAI B2.1.6-3, 

Requests (a), (b), and (c), that the applicant will implement these requirements either through 

implementation of the PWR Vessel Internals Program’s ASME Code Section Section XI 

“Existing Program” activities or through implementation of the applicable Examination 

Category B-N-3 requirements under its ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program. 

For the AMR items in LRA Table 3.1.2-1 that are linked to LRA Table 3.1-1, item 3.1.1-32 and 

align to GALL Report AMR item IV.B2.RP-382 using the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program as the aging management basis, the applicant 

amended the LRA AMR items by letter dated October 24, 2012, to indicate that the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, will be used to 

manage both cracking and loss of material caused by wear in the components. The scope of 

this aging management basis includes the following RVI components for which the ASME Code 

Section XI, Examination of Category B-N-3 visual VT-3 inspection requirements will be 

performed through implementation the ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program instead of the “Existing Program” bases of the PWR Vessel Internals 

Program:

• CRGT bolting

• core barrel

• core barrel outlet nozzles

• RVI head and vessel alignment pins

• RVI hold-down spring

• RVI ICI structure exit thermocouple

• RVI irradiation specimen basket (i.e., the basket that contains the reactor vessel 

Charpy-impact test specimens that are required by 10 CFR Part 50, Appendix H, 

“Reactor Vessel Material Surveillance Program Requirements”)

• RVI lower core support key, clevis inserts, and clevis insert bolting

• RVI lower core support energy absorber assembly

• top support plate, upper support column, and upper support column bolting in the RVI 

upper support
AGING MANAGEMENT REVIEW RESULTS

3-297

For these components, the applicant credits its ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program instead of the PWR Vessel Internal Program 

because: (a) the components are not inspected as part of MRP-227-A report basis, in that they 

are defined as “No Additional Measures” under the report’s methodology; (b) the components 

are defined as ASME Code Section XI, Examination Category B-N-3 core support structure 

components for the part of the CLB that is used to comply with 10 CFR 50.55a requirements, 

and; (c) the VT-3 visual inspections that are invoked by regulations in 10 CFR 50.55a and by 

the ASME Code Section XI, Examination Category B-N-3 requirements are applicable to the 

components. The staff finds this basis acceptable because it is consistent with the GALL 

Report and because the applicant will be implementing the applicable ASME Code Section XI 

examinations of the components even though the components are defined as “No Additional 

Measures” components under the applicant’s PWR Vessel Internals Program and MRP-227-A 

conformance basis. 

LRA Table 3.1-1, item 3.1.1-53 addresses RVI components made from either stainless steel or 

nickel alloy materials exposed to a reactor coolant and neutron flux environment, which will be 

managed for the aging effect and mechanism combinations of cracking due to SCC, IASCC, or 

fatigue (cyclical loading). LRA Table 3.1-1, item 3.1.1-59 addresses RVI components made 

from either stainless steel or nickel alloy materials exposed to reactor coolant and neutron flux 

environment, which will be managed for the aging effect and mechanism combinations of loss of 

material due to wear; loss of fracture toughness due to neutron irradiation embrittlement, void 

swelling, or thermal aging (applicable only to CASS, martensitic stainless steel materials, or 

precipitation hardened stainless steel materials); changes in dimension due to distortion or void 

swelling; or for fastened or bolted connections, loss of preload due to stress relaxation or 

irradiation-assisted creep. 

For RVI component AMR items in LRA Table 3.1.2-1 that align either the LRA AMR 

item 3.1.1-53 or 3.1.1-59, the applicant credits the PWR Vessel Internals Program to manage 

the stainless steel or nickel alloy RVI components that are exposed to the reactor coolant and 

neutron flux environment and are susceptible to the aging effects. The GALL Report 

recommends GALL Report AMP XI.M16A, “PWR Vessel Internals,” to ensure that these aging 

effects are adequately managed. GALL Report AMP XI.M16A recommends management of 

these aging effects using the sampling-based condition monitoring basis that is defined in the 

MRP-227-A report.

The staff noted that the AMR items on cracking of specific RVI components in LRA 

Table 3.1.2-1 were consistent with AMR item No. 53 in the SRP-LR and that the AMR items on 

loss of material due to wear, loss of fracture toughness, loss of preload, or changes in 

dimension for specific RVI components in LRA Table 3.1.2-1 were consistent with AMR item 

No. 59 in the SRP-LR, with the exception of the AMR items discussed below for which the staff 

needed further clarification.

The staff noted that, in LRA Table 3.1.2-1, the applicant appropriately credited either its PWR 

Vessel Internals Program or the ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program as the basis for managing loss of material in all RVI components that were 

susceptible to a wear-based mechanism, with the exception the CRGT support pins (split pins), 

core barrel flanges, or upper core plate. However, the staff noted that Table 3-3 of the 

MRP-227-A report identifies that loss of material due to wear is an applicable aging effect for 

these components. The staff’s evaluation of the applicant’s basis for managing loss of material 

due to wear in the CRGT split pins is documented in SER Section 3.1.2.2.14. The evaluation in 

SER Section 3.1.2.2.14 includes the staff’s evaluation of the applicant’s response to 
AGING MANAGEMENT REVIEW RESULTS

3-298

RAI 3.1.2.1-4, Part (a), which asked the applicant to provide justification for managing loss of 

material caused by wear in the CRGT split pins using only the Water Chemistry Program. 

With respect to the evaluation of loss of material caused by wear in the upper core plate, the 

staff noted that the applicant had inadvertently identified the applicable non-cracking effect as 

loss of fracture toughness and not loss of material due to wear. In LRA Amendment No. 1, 

provided by letter dated April 25, 2012, the applicant appropriately corrected this oversight by 

amending the applicable AMR item to identify that the applicable non-cracking effect is loss of 

material (by wear) and by crediting the PWR Vessel Internals Program as the basis for 

monitoring and managing loss of material that might initiate in the core plate as a result of wear. 

The applicant also amended the AMR item for the upper core plate to identify that under the 

PWR Vessel Internals Program, the upper core plate is an “expansion category” component for 

the management of loss of material by wear. The PWR Vessel Internals Program would call for 

the upper core plate to be inspected for wear if relevant indications of wear are detected in the 

CRGT lower flange weld (which is the corresponding “primary category” component for the 

upper core plate). The staff found the amended AMR item on loss of material caused by wear 

in the upper core plate to be acceptable because it is in conformance with the staff-endorsed 

methodology in the MRP-227-A report.

For the core barrel flanges, the staff noted that the applicant had only credited the Water 

Chemistry Program to manage loss of material that might occur in the component. In contrast, 

the staff noted that the MRP-227-A report would have the applicant perform ASME Code 

Section XI required VT-3 visual inspections of core barrel flanges for wear because the 

components have been defined in the MRP-227-A report as ASME Code Section XI “Existing 

Program” components.

The staff noted that the Water Chemistry Program would not, by itself, be an acceptable basis 

for managing loss of material caused by wear in these flanges because the mitigative chemical 

control activities of the AMP would not have any impact on alleviating the consequences of 

mechanical-induced aging mechanisms (e.g., wear, fretting or abrasion) that could induce a loss 

of material aging effect. Thus, the staff did not have sufficient information to conclude that wear 

would not be applicable to the core barrel flanges or to establish how the Water Chemistry 

Program would be capable of managing loss of material that might occur in these flange 

components as a result of wear. The staff also noted that, in LRA Amendment No. 1, the 

applicant had amended its AMR item on cracking of the core barrel flanges to credit the PWR 

Vessel Internals Program as the basis for managing cracking in the components instead of the 

ASME Section XI, Subsections IWB, IWC, and IWD Program and by identifying that the AMP 

would inspect these components under the EPRI MRP’s “Expansion Category” component 

bases in the MRP-227-A report. The staff questioned this change in the AMR basis because 

the staff observed that the MRP-227-A report identifies that Westinghouse-designed core barrel 

flanges are ASME Code Section XI, “Existing Program,” core support structure components 

(i.e., ASME Code Section XI, Examination Category B-N-3 components) and not EPRI MRP 

defined “Expansion Category” RVI components. Thus, the staff noted that, if the core barrel 

flanges were ASME Code Section XI, Examination Category B-N-3, components for the CLB, 

the applicant should have either continued to credit its ASME Section XI, Subsections IWB, 

IWC, and IWD Program to manage cracking in the components, or credited the PWR Vessel 

Internals Program for the aging effect by identifying the components as ASME Code Section XI, 

“Existing Program,” components. Therefore, by letter dated September 25, 2012, the staff 

issued RAI 3.1.2.1-4, Part (b), requesting that the applicant provide both a clarification on why 

the AMR item on cracking of the core barrel flange in LRA Amendment No. 1 identified this 

component as an “Expansion Category” component and not as ASME Code Section XI, 
AGING MANAGEMENT REVIEW RESULTS

3-299

“Existing Program,” components. The staff also requested the applicant to provide its basis on 

how the Water Chemistry Program, by itself, would be capable of managing loss of material in 

the core barrel flange that initiates by a wear-induced mechanism (or similar mechanisms such 

are fretting or abrasion). Specifically, the staff requested the applicant to clarify whether the 

core barrel flange is defined in the Callaway CLB as an ASME Code Section XI, Examination 

Category B-N-3 core support structure component. If the core barrel flange is an ASME Code 

Section XI, Examination Category B-N-3 component for the CLB, the staff requested the 

applicant to justify why it had not credited either the PWR Vessel Internals Program’s ASME 

Code Section XI-based “Existing Program” Examination Category protocols or the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, IWD Program as the basis for 

managing both loss of material due to wear and cracking that may occur in the core barrel 

flange. If the core barrel flange was not defined in the CLB as an ASME Code Section XI, 

Examination Category B-N-3 core support structure component, the staff requested the 

applicant to: 

(i) identify the RVI “Primary Category” component or components that will be 

inspected for cracking and loss of material due to wear and will be used to 

determine whether the core barrel flange will need to be inspected for these aging 

effects, 

(ii) identify the inspection methods and frequency that will be applied to both the 

“Primary Category” component links and potentially to the core barrel flange as an 

“Expansion Category” component for those components, and 

(iii) justify the “Expansion Category” bases that will be applied to potential inspections 

of the core barrel flange.

In its response to RAI 3.1.2.1-4, Part (b) dated October 24, 2012, the applicant clarified that the 

core barrel flange is defined as an ASME Code Section XI, Examination Category B-N-3 core 

support structure component for the CLB. As part of its response the applicant amended the 

LRA to change the AMR basis for aging management of the core barrel flange. Specifically, the 

applicant amended the existing AMR item on cracking of the components to credit the ASME 

Code Section XI “Existing Program” basis of its PWR Vessel Internals Program as the bases for 

inspecting and managing cracking of the core barrel flange. The applicant also added a new 

AMR item to manage loss of material that may occur in the core barrel flange as a result of wear 

and crediting the ASME Code Section XI, Examination Category B-N-3 examinations as the 

basis for managing wear in the components. The staff finds the amended AMR bases for the 

core barrel flange to be acceptable because: (a) the applicant will be implementing the 

mandated inspections of the components either through implementation of the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program, or the PWR Vessel Internals 

Program; and (b) these bases are consistent with bases in GALL Report AMR items 

IV.B2.RP-382 and IV.B2.RP-345, which recommend that these ASME Code Section 

examinations be used as the basis for managing loss of material and cracking in these 

components. The staff’s concern described in RAI 3.1.2.1-4, Part (b), is resolved.

The staff noted that, in LRA Amendment No. 1, the applicant provided changes to the AMR 

items for the following RVI components at Callaway: (a) core barrel girth and axial welds, 

(b) core barrel outlet nozzles and welds, (c) core support forging, and (d) upper core plate. The 

staff noted that, in these amended AMR items, the applicant either corrected the aging effect or 

mechanism consistent with those reported for the components in MRP-227-A or proposed aging 

management bases under the PWR Vessel Internals Program that were consistent with the 

recommended aging management bases as proposed in MRP-227-A report and endorsed by 
AGING MANAGEMENT REVIEW RESULTS

3-300

the staff for “Primary Category” or “Expansion Category” RVI components. However, the staff 

has noted that these components could fall into multiple inspection category bases under the 

applicant’s PWR Vessel Internals Program if the components were also defined in the CLB as 

ASME Code Section XI, Examination Category B-N-3 core support structure components. 

By letter dated September 25, 2012, the staff issued RAI 3.1.2.1-5 requesting that the applicant 

provide additional clarifications on whether the core barrel girth welds, core barrel axial welds, 

core barrel outlet nozzles and welds, core support forging, and upper core plate are ASME 

Code Section XI, Examination Category B-N-3 components for the CLB. If so, the staff 

requested the applicant to justify why the ASME Code Section XI, Subsection IWB, IWC, IWD, 

or the ASME Code Section XI “Existing Program” protocols of the PWR Vessel Internals 

Program have not been credited in addition to the appropriate “Primary Category” or “Expansion 

Category” bases that have been identified for the components.

In its response dated October 24, 2012, the applicant stated that core barrel girth welds, core 

barrel axial welds, core barrel outlet nozzles and welds, core support forging, and upper core 

plate are ASME Code Section XI, Examination Category B-N-3 components. The applicant 

stated that, although these components are categorized as either “Primary Category” 

components or “Expansion Category” components, the requirements of ASME Code Section XI, 

Examination Category B-N-3 are still in effect and may only be altered as allowed by 

10 CFR 50.55a (i.e., if a 10 CFR 50.55a relief request is approved for the components). 

The applicant also stated that the guidelines provided in MRP-227-A do not reduce, alter, or 

otherwise affect current ASME Code Section XI or Callaway ISI commitments. The staff finds 

that the applicant’s aging management basis for the core barrel girth welds, core barrel axial 

welds, core barrel outlet nozzles and welds, core support forging, and upper core plate is 

acceptable because it clarifies that: (a) the applicant will be applying the PWR Vessel Internals 

Program and appropriate “Primary Category” or “Expansion Category” inspection basis for the 

components in the MRP-227-A as part of the basis for managing the age-related effects that are 

applicable to the components during the period of extended operation; (b) the applicant will also 

be implementing the ASME Code Section XI, Examination Category B-N-3 inspections of the 

components, as required by 10 CFR 50.55a; and (c) the applicant’s inspection basis for these 

components is consistent with the AMR item bases for these components in the GALL Report 

and with the applicant’s CLB for complying with applicable 10 CFR 50.55a requirements. The 

staff’s concern described in RAI 3.1.2.1-5 is resolved.

LRA Table 3.1.2-1 provides the applicant’s AMR items for managing cracking, loss of fracture 

toughness, and loss of material in the Callaway ICI support structure, upper and lower tie plates. 

In the AMR items, the applicant credits the Water Chemistry Program to manage loss of 

material that may be induced in these components by pitting or crevice corrosion. The applicant 

also credits a combination of the Water Chemistry Program and the PWR Vessel Internals 

program to manage any cracking that may occur in the components. The applicant also credits 

the PWR Vessel Internals Program to manage loss of fracture toughness that might occur in the 

components. In the AMR items for the upper and lower tie plate components, the applicant 

identifies that the upper and lower tie plate components are “Expansion Category” components 

for the PWR Vessel Internals Program.

The staff reviewed the applicant’s basis against the criteria for Westinghouse-designed 

“Expansion Category,” components in the MRP-227-A report. The staff was unable to correlate 

the ICI support structure upper and lower tie plates to any of the components that are listed for 

Westinghouse-designed RVI components in MRP-227-A Table 3-3 or in MRP-227-A Table 4-6, 
AGING MANAGEMENT REVIEW RESULTS

3-301

for Westinghouse “Expansion Category” components. Therefore, the staff was unable to 

determine which of the MRP-227-A “Primary Category” components would potentially provide 

lead indications of aging for the ICI support structure upper and lower tie plates or the types of 

inspection bases (including method and frequency) that would be applied to the tie plates if 

expansion inspections were warranted. 

By letter dated September 12, 2012, the staff issued RAI 3.1.2.1-2. RAI 3.1.2.1-2, Part (a) 

requested the applicant to provide clarification on whether the ICI support structure upper and 

lower tie plates are within the scope of any “Expansion Category” component groupings in 

Table 4-6 of the MRP-227-A report, and if so, to identify which of the “Expansion Category” 

component groupings in the report correlated to the Callaway ICI support structure upper and 

lower tie plates. RAI 3.1.2.1-2, Part (b) requested the applicant to identify which “Primary 

Category” component or components in Table 4-3 of MRP-227-A will be linked to the ICI 

support structure upper and lower tie plates, as “Expansion Category” components if these tie 

plates are not within the scope of any of the “Expansion Category” component groupings in 

Table 4-6 of the MRP-227-A report. The staff also asked the applicant to: 

[c]larify the "Primary Category" inspection acceptance criteria that would kick in 

expansion inspections of the tie plates. Identify the inspection method and 

inspection frequency that would be applied to the tie plates and clarify whether 

the tie plates would be subject to baseline inspections prior to the period of 

extended operation, as well as re-inspection basis during the period of extended 

operation, and define such bases as appropriate. 

In its response dated October 15, 2012, the applicant provided its response to RAI 3.1.2.1-2, 

Requests (a) and (b). In its response the applicant stated that the functions of the ICI support 

structure, including the BMI column bodies and the upper and lower tie plates, are to protect the 

flux thimble tubes and to provide a path for the flux thimble tubes into the core from the bottom 

of the reactor vessel. The applicant stated that the flux thimble tubes are part of the RCPB and 

that the BMI column bodies are included in MRP-227-A Table 3-3 and MRP-227-A Table 4-6 as 

"Expansion Category" components. In response to Part (a) the applicant stated that the upper 

and lower tie plates have the function of supporting the structural integrity of the BMI column 

bodies to maintain the functions of the BMI column bodies. The applicant also stated that since 

the tie plates and the BMI column bodies are located in the same area of the reactor and have 

the same function of protecting the flux thimble tubes, the upper and lower tie plates are 

included in the same group as the BMI column bodies to be within the scope of "Expansion 

Category" components. In response to Part (b) the applicant stated that “Primary Category” 

component link for the ICI support structure upper and lower tie plates are the CRGT lower 

flange components and that it selected CRGT lower flanges as the “Primary Category” 

components because they also serve as the “Primary Category” links for the BMI column 

bodies, which are also “Expansion Category” components for the program.

Based on its review of the applicant’s response, the staff noted that the inclusion of the upper 

and lower tie plates as “Expansion Category” components for the PWR Vessel Internals 

Program is a conservative plant-specific decision by the applicant that goes beyond the 

“Expansion Category” components recommendations for Westinghouse-designed PWR RVI 

components in the MRP-227-A report. The staff also noted that the applicant’s selection of the 

CRGT lower flanges as the “Primary Category” component links for the upper and lower tie 

plates was a logical selection by the applicant based on their purpose of serving as the “Primary 

Category” component links for both the BMI column bodies and lower support column bodies as 

applicable Westinghouse-design “Expansion Category” components. The staff finds this to be 
AGING MANAGEMENT REVIEW RESULTS

3-302

an acceptable aging management basis for the upper and lower tie plates and, therefore, finds 

the applicant response acceptable because: (a) the applicant has conservatively added the ICI 

support structure upper and lower tie plates in as additional plant-specific “Expansion Category” 

components under the PWR Vessel Internals Program; (b) the applicant’s decision to inspect 

the upper and lower tie plates as “Expansion Category” components for the program is 

consistent with the applicant’s basis for inspecting the BMI column bodies and the lower support 

column bodies as “Expansion Category” components for the program; (c) under this program, 

the applicant will implement inspections of the BMI column bodies, lower support column 

bodies, and ICI support structure upper and lower tie plates if evidence of cracking is detected 

in the CRGT lower flanges; (d) the staff has confirmed that AMR items for the upper and lower 

tie plates are consistent with AMR bases in GALL Report AMR items IV.B2.RP-292 and 

IV.B2.RP-293; and (e) this basis represents a conservative decision by the applicant that goes 

beyond the recommendations in MRP-227-A. The staff finds that this basis serves as one 

example of the additional plant-specific and conservative decisions made by the applicant that 

demonstrates the applicant’s conformance with the action request in A/LAI No. 2 on the 

MRP-227-A methodology. The staff’s concerns described in RAI 3.1.2.1-2, Requests (a) and 

(b) are resolved. 

LRA Table 3.1.2-1 provides the AMR items for managing loss of material and changes in 

dimension of the RVI baffle-former assembly. In these AMR items, the applicant credits the 

Water Chemistry Program to manage loss of material in the RVI baffle-former assembly and the 

PWR Vessel Internals Program to manage changes in dimension of the RVI baffle-former 

assembly.

The staff noted that Table 4-3 of the MRP-227-A report includes the EPRI MRP’s recommended 

criteria for performing VT-3 visual inspections of Westinghouse-design baffle-to-former 

assembly components, including the baffle plates and former plates. In addition, in Table 4-3 of 

MRP-227-A, the EPRI MRP identifies that the VT-3 examinations on the applicable RVI 

baffle-former assembly components are used to look for evidence of both changes in dimension 

that initiates by component distortion or void swelling and cracking that initiates by an IASCC 

mechanism. The staff noted that LRA Table 3.1.2-1 did not include any AMR items on 

management of cracking in the plant’s baffle plates or former plates. Therefore, it was not

evident to the staff which components were specifically within the scope of the AMR items for 

the “RVI baffle-former assembly” or why cracking caused by IASCC would not need to be 

identified as an applicable AERM and managed by the applicant “Primary Category” VT-3 

inspection bases for baffle plates and former plates in the baffle-former assembly. 

By letter dated September 25, 2012, the staff issued RAI 3.1.2.1-3, requesting the applicant to 

provide its basis on why LRA Table 3.1.2-1 did not include any AMR items on management of 

cracking of baffle plates and former plates of the baffle-former assembly or why the PWR 

Vessel Internals Program would not need to be credited to manage cracking caused by IASCC 

in the baffle plates and former plates, as “Primary Category” components for inspection. 

In its response dated October 24, 2012, the applicant stated that, as clarified in the response to 

RAI 3.1.2.1-1, Part (a), the RVI baffle-former assembly includes the baffle plates and the former 

plates. The applicant stated that the RVI baffle-to-former assembly components included in 

LRA Table 3.1.2-1 are consistent with the component description of GALL Report AMR 

item IV.B2.RP-270 for aging management of the changes in dimension in the RVI 

baffle-to-former assembly (baffle and former plates). The applicant also stated that the AMR 

items for these components also include an AMR item on management of loss of material in the 

components as a result of crevice and pitting corrosion and that the AMR item is consistent with 
AGING MANAGEMENT REVIEW RESULTS

3-303

GALL Report AMR item IV.B2.RP-24. The applicant further stated that Table 4-3 of MRP-227-A 

report identifies that cracking caused by IASCC is an applicable aging effect to be managed 

within the scope of MRP-227-A basis for the RVI baffle-to-former assembly components. As 

part of its response the applicant also amended LRA Table 3.1.2-1 to include an AMR item on 

management of cracking caused by IASCC in the RVI baffle-former assembly that covers aging 

management of the baffle plates and former plates and that credits the PWR Vessel Internals 

Program and the “Primary Category” inspection basis for the baffle and former plates in 

Table 4.3 of the MRP-227-A report, as the basis for managing cracking of the components 

during the period of extended operation. 

The applicant also provided supplemental information regarding the baffle-edge bolts by letter 

dated April 23, 2014. In this letter, the applicant stated that, according to information provided 

by Westinghouse for the RVI components in this commodity group, the Callaway Unit 1 plant 

design does not include baffle-edge bolts in its core baffle assembly. The applicant amended 

LRA Table 3.1.2-1 to delete the three AMR item entries for baffle edge bolting (as referenced in 

LRA Table 3.1.1, items 3.1.1-53 or 3.1.1-59) from the scope of the LRA table. The staff 

reviewed the plant design documentation and verified that the design of the plant’s core baffle 

assembly does not include baffle-edge bolts. As a result, the staff verified that these 

components are not within the scope of the applicant’s PWR Vessel Internals Program and that 

the “Primary Category” component recommendations for Westinghouse-designed baffle-edge 

bolts in EPRI MRP Technical Report No. MRP-227-A do not apply to Callaway Unit 1. Based 

on this review, the staff reviewed the applicant’s claim and LRA amendment and finds them

acceptable because the staff has verified that the RVI design does not include baffle-edge bolts.

The staff finds that the applicant’s responses are acceptable because: (a) the basis for 

managing loss of material caused by pitting and crevice corrosion and changes in dimension of 

the baffle and former plates is consistent with GALL Report AMR items IV.B2.RP-24 and 

IV.B2.RP-270; and (b) the staff confirmed that the LRA Table 3.1.2-1 AMR, as amended, is 

consistent with the recommended AMR in GALL Report AMR item IV.B2.RP-294. The staff’s 

concern described in RAI 3.1.2.1-3 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).

3.1.2.1.4 Loss of Material due to Pitting and Crevice Corrosion

LRA Table 3.1-1, item 3.1.1-87 addresses the Callaway RVI components made from either 

stainless steel or nickel alloy materials that are exposed to reactor coolant environment, which 

will be managed for loss of material due to pitting or crevice corrosion. The LRA credits the 

Water Chemistry Program to manage this aging effect and mechanism for the stainless steel or 

nickel alloy RVI components that are exposed to the reactor coolant environment. The staff’s 

evaluation of the applicant’s Water Chemistry Program is documented in SER Section 3.0.3.1.2. 

The GALL Report recommends GALL Report AMP XI.M2, “Water Chemistry,” to ensure that 

these aging effects are adequately managed. GALL Report AMP XI.M2 recommends 

management of loss of material caused by pitting and crevice corrosion using water chemistry 

controls that will either prevent initiation of these relevant aging mechanisms or that will mitigate 

the consequence of the relevant aging effect should loss of material be initiated in the 

components as a result of pitting or crevice corrosion aging mechanisms. The staff noted that 

the applicant’s basis for managing loss of material because of pitting and crevice corrosion of 
AGING MANAGEMENT REVIEW RESULTS

3-304

these components is in conformance with the staff’s recommendations in AMR item No. 24 of 

SRP-LR Table 3.1-1 and the Table 2 AMR items in GALL Report Table IV.B2 that are 

referenced to by SRP-LR Table 3.1-1 AMR item No. 24. Therefore, based on this review, the 

staff finds that the applicant’s basis for managing loss of material caused by pitting and crevice 

corrosion in these RVI components to be acceptable because the staff has confirmed that the 

applicant’s basis is in conformance with the staff’s recommended AMR criteria in SRP-LR 

Table 3.1-1 AMR item No. 24. 

The staff concludes that for LRA item 3.1.1-87, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended

In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the RCS components and provides information concerning how it will 

manage the following aging effects:

• cumulative fatigue damage

• loss of material due to general, pitting, and crevice corrosion

• loss of fracture toughness due to neutron irradiation embrittlement

• cracking due to SCC and IGSCC

• crack growth due to cyclic loading

• cracking due to SCC

• cracking due to cyclic loading

• loss of material due to erosion

• cracking due to SCC and IASCC 

• loss of fracture toughness due to neutron irradiation embrittlement; change in dimension 

due to void swelling; loss of preload due to stress relaxation; or loss of material due to 

wear

• cracking due to PWSCC

• cracking due to fatigue

• cracking due to SCC and fatigue

• loss of material due to wear

• QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which the GALL Report recommends further 

evaluation, the staff audited and reviewed the applicant’s evaluations to determine whether it 

adequately addressed the issues further evaluated. In addition, the staff reviewed the 

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.1.2.2. The 

staff’s review of the applicant’s further evaluation follows.
AGING MANAGEMENT REVIEW RESULTS

3-305

3.1.2.2.1 Cumulative Fatigue Damage

LRA Section 3.1.2.2.1 addresses the applicant’s AMR for managing cumulative fatigue damage 

in RPV and internals; reactor coolant pumps, pressurizer; primary side of the steam generators, 

and RCPB piping, valves, and other components; and of those steam generator secondary-side 

components with a fatigue analysis. The applicant stated that fatigue is a TLAA, as defined in 

10 CFR 54.3, and is required to be evaluated in accordance with 10 CFR 54.21(c). Additional 

information for these TLAAs is discussed in LRA Section 4.3.

The applicant identified the following item in LRA Table 3.1-1 that are applicable:

Item 3.1.1-1 - The applicant stated that metal fatigue of RCPB closure bolting (RPV head studs) 

is a TLAA addressed in LRA Section 4.3. 

Item 3.1.1-2 - The applicant stated that metal fatigue and wear analyses of the replacement 

steam generators are TLAAs addressed in LRA Sections 4.3 and 4.7, respectively. 

Item 3.1.1-3 - The applicant stated that metal fatigue of RVI components is a TLAA addressed 

in LRA Section 4.3. 

Item 3.1.1-5 - The applicant stated that metal fatigue of RCPB closure bolting (pump, valve, and 

pressurizer and steam generator manway and port bolting), reactor vessel inlet and outlet 

nozzle supports; pressurizer vessel supports, support skirts and flanges; steam generator 

primary and secondary shells, integral supports, manways, nozzles, and bolting is a TLAA 

addressed in LRA Section 4.3. 

Items 3.1.1-6 and 3.1.1-7 - The staff noted that these AMR items are specifically related to 

components in a BWR design; therefore, the staff finds it appropriate that the applicant did not 

address these items in the LRA. 

Item 3.1.1-8 - The applicant stated that metal fatigue of steam generator primary and 

secondary-side pressure boundaries including the lower head, divider plate, primary and 

secondary manways, nozzles and safe ends is a TLAA addressed in LRA Section 4.3. 

Item 3.1.1-9 - The applicant stated that metal fatigue of RCPB piping, reactor coolant pumps, 

and the pressurizer, postulation of HELB locations, LBB analysis of RCPB piping are TLAAs 

addressed in LRA Sections 4.3 and 4.7. 

Item 3.1.1-10 - The applicant stated that metal fatigue of reactor vessel, ISI corrosion analysis of 

RPV underclad flaws; and fatigue flaw growth analysis for the cold leg elbow-to-safe end weld 

and the pressurizer, are TLAAs addressed in LRA Sections 4.3 and 4.7. 

For LRA Table 3.1-1, item 3.1.1-4, the applicant stated that the AMR item is not applicable 

because it has a Westinghouse reactor vessel with no support skirt. The staff reviewed the LRA 

and FSAR and confirmed that the applicant’s LRA does not have any AMR results that are 

applicable for this item. 

The staff reviewed LRA Section 3.1.2.2.1 against the further evaluation criteria in SRP-LR 

Section 3.1.2.2.1, which states that fatigue is a TLAA as defined in 10 CFR 54.3, and that these 

TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements in 

10 CFR 54.21(c)(1) and consistent with SRP-LR Sections 4.3 and 4.7. The staff also reviewed 
AGING MANAGEMENT REVIEW RESULTS

3-306

the AMR items associated with LRA Section 3.1.2.2.1, and determined that the AMR results are 

consistent with the GALL Report and SRP-LR.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.1.2.2.1 criteria. For those items that apply to LRA Section 3.1.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Sections 4.3 and 4.7 document the staff’s review of 

the applicant’s evaluation of the TLAAs for these components.

3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the following criteria in SRP-LR 

Section 3.1.2.2.2:

(1) LRA Section 3.1.2.2.2.1, associated with LRA Table 3.1-1, item 3.1.1-12, addresses the 

steam generator upper and lower shell and transition cone exposed to secondary 

feedwater and steam. The LRA states that the existing program relies on control of 

water chemistry to mitigate corrosion and ISI to detect loss of material. The LRA also 

states that augmented inspection is recommended for Westinghouse Models 44 and 51 

steam generators, where a high-stress region exists at the shell to transition cone weld, 

if general and pitting corrosion of the shell is known to exist. The LRA further states that 

the applicant’s steam generators have been replaced with Areva Model 73/19T, 

therefore the augmented inspection is not applicable.

The GALL Report states that this aging effect for the component is limited to 

Westinghouse Models 44 and 51 steam generators, where a high-stress region exists at 

the shell to transition cone weld. In its review of components associated with 

item 3.1.1-12, the staff confirmed that the applicant has replaced its steam generators 

with Areva Model 73/19T steam generators and finds that the augmented inspection is 

not applicable to the applicant’s steam generators.

(2) LRA Section 3.1.2.2.2.2, associated with LRA Table 3.1-1, item 3.1.1-12, addresses the 

steam generator upper and lower shell assembly exposed to secondary feedwater and 

steam. The LRA states that further evaluation of the effectiveness of the Water 

Chemistry Program is required for applicants that have replaced only the bottom part of 

their steam generators, generating a cut in the middle of the transition cone, and 

consequently a new transition cone closure weld. The LRA further states that the 

applicant’s replacement steam generators did not require a cut and associated field weld 

in the middle of the steam generator transition cone; therefore, further evaluation is not 

required. 

In its review of components associated with item 3.1.1-12, the staff confirmed that the 

applicant’s replacement steam generators did not require a cut in the transition cones. 

Therefore, there is no field weld in the middle of the applicant’s steam generators 

transition cones. The staff finds that this item is not applicable for further evaluation.

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:
AGING MANAGEMENT REVIEW RESULTS

3-307

(1) LRA Section 3.1.2.2.3.1, associated with LRA Table 3.1-1, item 3.1.1-13, addresses 

RPV steel (with or without stainless steel cladding) reactor vessel beltline shell, nozzles, 

and welds exposed to reactor coolant and neutron flux with an aging effect of loss of 

fracture toughness due to neutron irradiation embrittlement. LRA Section 3.1.2.2.3.1 

states that the evaluation of this TLAA is addressed in LRA Section 4.2. The staff finds 

that this is consistent with SRP-LR Section 3.1.2.2.3, item 1 criteria and is, therefore, 

acceptable. The staff’s evaluation of the TLAA for reactor vessel neutron embrittlement 

is documented in SER Section 4.2.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.1.2.2.3, item 1 criteria. For those items that apply to LRA Section 3.1.2.2.3.1, 

the staff determined that the LRA is consistent with the GALL Report and that the 

applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). SER Section 4.2 documents 

the staff’s review of the applicant’s evaluation of the TLAAs for these components.

(2) LRA Section 3.1.2.2.3.2, associated with LRA Table 3.1-1, item 3.1.1-14, addresses 

RPV steel (with or without cladding) reactor vessel beltline shell, nozzles, and welds as 

well as safety injection nozzles components exposed to reactor coolant, and neutron 

flux, 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 criteria of the SRP-LR by stating that the Reactor Vessel 

Surveillance Program manages loss of fracture toughness caused by neutron irradiation 

embrittlement in the reactor vessel beltline shell, nozzles, and welds exposed to reactor 

coolant and neutron flux.

The staff reviewed LRA Section 3.1.2.2.3.2 against the criteria in SRP-LR 

Section 3.1.2.2.3, item 2, which states that loss of fracture toughness caused by neutron 

irradiation embrittlement could occur for PWR reactor vessel beltline shell, nozzle, and 

welds exposed to reactor coolant and neutron flux. The SRP-LR also states that a 

reactor vessel materials surveillance program monitors neutron irradiation embrittlement 

of the reactor vessel, and that these programs are plant-specific. The SRP-LR further 

states that GALL Report, Chapter XI, Section M31, gives specific recommendations for 

an acceptable AMP.

SER Section 3.0.3.2.10 documents the staff’s evaluation of the applicant’s Reactor 

Vessel Surveillance Program. The staff finds the applicant’s proposal to manage aging 

using the Reactor Vessel Surveillance Program acceptable, because use of this 

program to manage neutron irradiation embrittlement of the reactor vessel beltline 

materials is consistent with the GALL Report and the SRP-LR. In addition the staff finds 

that Reactor Vessel Surveillance Program is consistent with the recommendations of the 

GALL Report AMP XI.M31.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.3, item 2 criteria. For those items associated with LRA 

Section 3.1.2.2.3.2, the staff determined that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(3) LRA Section 3.1.2.2.3.3, associated with LRA Table 3.1-1, item 3.1.1-15, addresses 

reduction in fracture toughness. The applicant stated that reduction in fracture 
AGING MANAGEMENT REVIEW RESULTS

3-308

toughness is a plant-specific TLAA for Babcock and Wilcox (B&W) reactor internals and 

is not applicable to Callaway which has Westinghouse reactor internals. 

SRP-LR Section 3.1.2.2.3, item 3, states that reduction in fracture toughness is a 

plant-specific TLAA for B&W reactor internals to be evaluated for the period of extended 

operation in accordance with the staff’s safety evaluation concerning “Demonstration of 

the Management of Aging Effects for the Reactor Vessel Internals,” Babcock and Wilcox 

Owners Group report number BAW-2248, which is included in BAW-2248A, dated 

March 2000. The staff confirmed that SRP-LR Section 3.1.2.2.3, item 3, is not 

applicable to Callaway because it is a Westinghouse-designed PWR. The staff noted 

that a TLAA associated with the reduction in fracture toughness and ductility does not 

exist for the applicant’s CLB. The staff’s review of the absence of TLAA is documented 

in SER Section 4.3.3.2. The staff also noted that the effect of loss of fracture toughness 

and reduced material ductility are managed for Westinghouse reactor internals with the 

applicant’s PWR Vessel Internal Program. The staff’s evaluation of the PWR Vessel 

Internal Program is documented in SER Section 3.0.3.1.5.

Based on the information above, the staff concludes that the staff’s guidance in SRP-LR 

Section 3.1.2.2.3, item 3, does not apply to Callaway because the TLAA documented in 

BAW-2248A is only applicable to B&W-designed PWRs.

3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking 

The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR 

Section 3.1.2.2.4:

(1) LRA Section 3.1.2.2.4, associated with LRA Table 3.1-1, item 3.1.1-16, addresses 

cracking due to SCC and IGSCC. The applicant stated that this item is applicable to 

BWR plants only. SRP-LR Section 3.1.2.2.4, item 1, states that cracking due to SCC 

and IGSCC may occur in the stainless steel and nickel-alloy BWR top head enclosure 

vessel flange leak detection lines. The staff finds that SRP-LR Section 3.1.2.2.4, item 1, 

is not applicable to Callaway because it is a PWR, and the staff guidance in this SRP-LR 

section is only applicable to BWR-designed reactors.

(2) LRA Section 3.1.2.2.4.2, associated with LRA Table 3.1-1, item 3.1.1-17, addresses 

cracking due to SCC and IGSCC in stainless steel BWR isolation condensers that are 

exposed to a BWR reactor coolant environment. The applicant stated that this item is 

applicable to BWR plants only. SRP-LR Section 3.1.2.2.4, item 2, states that cracking 

caused by SCC and IGSCC could occur in stainless steel BWR isolation condenser 

components exposed to reactor coolant. The staff finds that SRP-LR Section 3.1.2.2.4, 

item 2, is not applicable to Callaway because it is a PWR, and the staff guidance in this 

SRP-LR section is only applicable to BWR-designed reactors.

3.1.2.2.5 Crack Growth Due to Cyclic Loading 

LRA Section 3.1.2.2.5, associated with LRA Table 3.1-1, item 3.1.1-18, addresses intergranular 

separations (underclad cracks) in welds that are used to join cladding to RPV shell or nozzle 

forgings made from SA-508 Class 2 alloy steel materials and are exposed to the reactor coolant 

environment. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that no underclad cracks have been detected or analyzed for the Callaway RPV. By letter dated 

May 3, 2012, the applicant amended LRA Section 3.1.2.2.5 identifying that crack growth due to 

cyclic loading as a TLAA. The applicant stated that its evaluation of the TLAA is addressed 
AGING MANAGEMENT REVIEW RESULTS

3-309

separately in LRA Section 4.7.4. The staff’s evaluation of the TLAA is documented in SER 

Section 4.7.4.2.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.1.2.2.5 criteria. For those items that apply to LRA Section 3.1.2.2.5, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Section 4.7 documents the staff’s review of the 

applicant’s evaluation of the TLAAs for these components.

3.1.2.2.6 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.6 against the following criteria in SRP-LR 

Section 3.1.2.2.6:

(1) LRA Section 3.1.2.2.6.1, associated with LRA Table 3.1-1, item 3.1.1-19, addresses the 

management of cracking due to SCC in PWR reactor vessel flange leakage detection 

lines and reactor vessel BMI guide tubes exposed to a reactor coolant environment. 

The criteria in SRP-LR Section 3.1.2.2.6, item 1, states that cracking due to SCC could 

occur in PWR stainless steel reactor vessel flange leakage detection lines and BMI 

guide tubes that are exposed to a reactor coolant environment. SRP-LR 

Section 3.1.2.2.6, item 1, also states that the GALL Report recommends further 

evaluation to ensure that this aging effect will be adequately managed and that a 

plant-specific AMP be evaluated to ensure that this aging effect is adequately managed 

during the period of extended operation. 

The applicant addressed the further evaluation criteria in SRP-LR Section 3.1.2.2.6, 

item 1, by stating that cracking due to SCC of the BMI guide tubes will be managed 

using a combination of its Water Chemistry Program and ASME Section XI Inservice 

Inspection, Subjections IWB, IWC, and IWD Program. The applicant also identified that 

cracking due to SCC of the reactor vessel flange leakage detection line will be managed 

by the ASME Section XI Inservice Inspection, Subjections IWB, IWC, and IWD Program. 

SER Sections 3.0.3.1.1 and 3.0.3.1.2 document the staff’s evaluation of the applicant’s 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and 

Water Chemistry Program, respectively. 

In its review of components associated with item 3.1.1-19, the staff finds that for the 

stainless steel BMI guide tubes, the applicant has met the further evaluation criteria. 

The LRA states that cracking due to SCC of the BMI guide tubes is managed by the 

Water Chemistry Program and is augmented by the ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program. The staff reviewed LRA 

Section 3.1.2.2.6.1 against the criteria in SRP-LR Section 3.1.2.2.6, item 1. In its review 

of the stainless steel BMI guide tubes associated with LRA Table 3.1-1, item 3.1.1-19, 

the staff finds the applicant’s proposal to manage aging using the Water Chemistry and 

ASME Section XI Inservice Inspection Programs acceptable because: (a) the Water 

Chemistry Program will mitigate the potential development and progress of the aging 

effect, by limiting and controlling contaminants that may contribute to SCC; and (b) the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC and IWD Program will 

confirm the effectiveness of the Water Chemistry Program. The staff confirmed that 

these components fall under examination category B-P, and will require a periodic VT-2 

examination every RFO and during system leakage testing. The extent and frequency of 
AGING MANAGEMENT REVIEW RESULTS

3-310

these examinations provide reasonable assurance that leakage, if present would be 

identified as reactor coolant leakage and corrected during scheduled plant outages. 

In its review of the applicant’s reactor vessel flange leakage detection lines, which are 

also associated with LRA Table 3.1-1, item 3.1.1-19; the staff noted that the applicant 

stated that its reactor vessel flange leak detection line is made of nickel alloy with a 

normal operating environment of air with borated water leakage. In addition, the 

applicant stated that cracking due to SCC of the reactor vessel flange leak detection line 

will be managed by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program. The staff finds the applicant’s proposal to manage aging of the 

reactor vessel flange leakage detection line using the ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program acceptable because, during 

normal operation of the reactor, the environment for the applicant’s reactor vessel flange 

leakage detection line is not expected to be in contact with borated water. Therefore, 

the environment air with borated water leakage would be expected only in the unlikely 

event that leakage is occurring past the applicant’s O-ring seal. Furthermore, the 

applicant’s reactor vessel flange leakage detection line is fabricated from nickel alloy. 

The staff noted that the GALL Report includes entries for nickel alloys exposed to air 

with borated water leakage. These entries indicate that an aging effect requiring 

management is not required for this material-environment combination. Therefore, the 

staff finds that the applicants proposal to use its ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program acceptable because, if leakage is occurring 

past the O-ring in the flange and the flange leak detection line develops through wall 

cracking, the credited ISI would be performed with sufficient frequency to detect the 

leakage and take appropriate corrective actions.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.6, item 1 criteria. For those items associated with LRA 

Section 3.1.2.2.6.1, the staff determined that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) LRA Section 3.1.2.2.6.2, associated with LRA Table 3.1-1, item 3.1.1-20, addresses 

CASS Class 1 piping, piping components, and piping elements exposed to reactor 

coolant, which will be managed for cracking due to SCC. The LRA states that the 

carbon content for RCS fittings and piping pieces do not meet the NUREG-0313 criterion 

of less than 0.035 percent based on review of the CMTRs of the applicant’s CASS 

piping components. The LRA also states that cracking due to SCC for CASS RCS 

piping components exposed to reactor coolant is managed by the Water Chemistry 

Program and is augmented by the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program. In addition the applicant stated that it has 

determined that the molybdenum and ferrite values are below the thermal aging 

embrittlement screening threshold. The applicant further stated that these CASS reactor 

coolant piping components are not susceptible to the aging effect of thermal aging 

embrittlement and it is not required to include flaw evaluation methodology for these 

CASS components. 

In its review of components associated with LRA Table 3.1-1, item 3.1.1-20, the staff 

finds the applicant’s proposal to manage aging using the Water Chemistry and ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Programs acceptable 

because the Water Chemistry Program will mitigate the potential for SCC, while the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will 
AGING MANAGEMENT REVIEW RESULTS

3-311

confirm the effectiveness of the Water Chemistry Program. The staff’s evaluation of the 

applicant’s ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program and Water Chemistry Program is documented in SER Sections 3.0.3.1.1 and 

3.0.3.1.2 respectively. 

Based on the programs identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.6, item 2 criteria. For those items associated with LRA 

Section 3.1.2.2.6.2, the staff determined that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.7 Cracking Due to Cyclic Loading

LRA Section 3.1.2.2.7, associated with LRA Table 3.1-1, item 3.1.1-21, addresses cracking due 

to cyclical loading in steel and stainless steel BWR isolation condensers that are exposed to a 

BWR reactor coolant environment. The applicant stated that this item is not applicable to 

Callaway because the staff’s further evaluation recommendation is only applicable to BWR 

designs. The staff reviewed LRA Sections 2.3.1 and 3.1, and the Callaway FSAR and finds the 

applicant determination acceptable because Callaway is a PWR design that does not include 

any steel or stainless steel isolation condenser components exposed to a reactor coolant 

environment.

3.1.2.2.8 Loss of Material Due to Erosion

LRA Section 3.1.2.2.8, associated with LRA Table 3.1-1, item 3.1.1-22, addresses loss of 

material due to erosion in steel steam generator feedwater impingement plates and supports 

exposed to secondary feedwater. The applicant stated that this item is not applicable for further 

evaluation because Callaway’s steam generators do not have feedwater impingement plates.

In its review of the LRA and FSAR of components associated with LRA Table 3.1-1, item 

3.1.1-22, the staff confirmed that the applicant’s replacement steam generators do not have 

feedwater impingement plates. Therefore staff finds the applicant determination that this item is 

not applicable acceptable. 

3.1.2.2.9 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress Corrosion 

Cracking

LRA Section 3.1.2.2.9, associated with LRA Table 3.1-1, item 3.1.1-23, addresses cracking due 

to SCC and IASCC in stainless steel or nickel alloy PWR RVI components in inaccessible 

locations exposed to reactor coolant and neutron flux. The staff’s evaluation of item 3.1.1-23 is 

documented in SER Section 3.1.2.2.10 below.

3.1.2.2.10 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement Change in 

Dimension Due to Void Swelling, Loss of Preload Due to Stress Relaxation, or Loss 

of Material due to Wear

LRA Section 3.1.2.2.9, associated with LRA Table 3.1-1, item 3.1.1-23, addresses cracking due 

to SCC and IASCC in stainless steel or nickel alloy PWR RVI components in inaccessible 

locations exposed to reactor coolant and neutron flux. The applicant stated that this aging effect 

will be managed by its PWR Vessel Internals Program. The criteria in SRP-LR 

Section 3.1.2.2.9 states that cracking due to SCC and IASCC could potentially occur in the 
AGING MANAGEMENT REVIEW RESULTS

3-312

inaccessible locations for stainless steel and nickel-alloy “Primary Category” and “Expansion 

Category” PWR RVI components. SRP-LR Section 3.1.2.2.9 also states that, if aging effects 

are identified in accessible locations, the GALL Report recommends further evaluation of the 

aging effects in inaccessible locations on a plant-specific basis to ensure that this aging effect is 

adequately managed. 

LRA Section 3.1.2.2.10, associated with LRA Table 3.1-1, item 3.1.1-24, addresses nickel alloy 

and stainless steel PWR RVI components that are exposed to the reactor coolant (including 

impacts of neutron flux) environment, which will be managed for loss of fracture toughness due 

to neutron irradiation embrittlement; changes in dimension due to void swelling; loss of preload 

due to thermal and irradiation enhanced stress relaxation; or loss of material due to wear by the 

applicant’s PWR Vessel Internals Program. The criteria in SRP-LR Section 3.1.2.2.10 states 

that these aging effects and mechanisms could potentially occur in the inaccessible locations for 

stainless steel and nickel-alloy “Primary Category” and “Expansion Category” PWR RVI 

components. SRP-LR Section 3.1.2.2.10 also states that, if aging effects are identified in 

accessible locations, the GALL Report recommends further evaluation of the aging effects in 

inaccessible locations on a plant-specific basis to ensure that this aging effect is adequately 

managed. 

The applicant addressed the further evaluation criteria in SRP-LR Sections 3.1.2.2.9 and 

3.1.2.2.10 by stating that the PWR Vessel Internals Program examines one hundred percent of 

the volume/area of each accessible stainless steel and nickel alloy RVI primary and expansion 

inspection category component that is subject to cracking. The applicant stated that the 

minimum examination coverage for primary and expansion inspection categories is 75 percent 

of the component's total (accessible plus inaccessible) inspection area or volume or, when 

addressing a set of like components (e.g., bolting), that the inspections examine a minimum 

sample size of 75 percent of the total population of like components. The applicant also stated 

that if defects are discovered in the 75 percent sample size, the information will be entered into 

its CAP to evaluate the results of the examination to ensure the intended functions are 

maintained until the next scheduled examination. In LRA Amendment No. 1, dated 

April 25, 2012, the applicant stated that the methodology in non-proprietary WCAP-17096-NP, 

Revision 2, “Reactor Internals Acceptance Criteria Methodology and Data Requirements,” 

(ADAMS Accession No. ML101460156), will be used as the basis for evaluating flaws or 

degraded areas in the RVI components. 

LRA Table 3.1-1, item 3.1.1-23, is based on the AMR criteria in SRP-LR Section 3.1.2.2.9 and 

SRP-LR Table 3.1-1, item No. 23, which references AMR item IV.B2.RP-268 in the GALL 

Report. Similarly, LRA Table 3.1-1, item 3.1.1-24, is based on the AMR criteria in SRP-LR 

Section 3.1.2.2.10 and SRP-LR Table 3.1-1, item No. 24, which references AMR 

item IV.B2.RP-269 in the GALL Report. The staff’s evaluation of the applicant’s PWR Vessel 

Internals Program is documented in SER Section 3.0.3.1.5. The applicant’s PWR Vessel 

Internals Program is based, in part, on conformance with the recommended inspection and flaw 

evaluation criteria in EPRI Report No. 1022863, “Materials Reliability Program: Pressurized 

Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227-A),” which was 

approved in the staff’s revised Safety Evaluation, Revision 1, dated December 16, 2011. In this 

topical report, the EPRI MRP defines “Primary Category” RVI components as PWR RVI 

components that are either highly susceptible to effects of aging caused by any active 

degradation mechanism, or components that have a degree of tolerance for a specific 

degradation mechanism but for which no leading highly susceptible or accessible component 

exists. The EPRI MRP defines “Expansion Category” components as RVI components that are 

moderately or highly susceptible to the effects of aging caused by one or more active 
AGING MANAGEMENT REVIEW RESULTS

3-313

degradation mechanisms but for which the functionality analyses indicated that these 

components have a degree of tolerance to the aging effects associated with these degradation 

mechanisms. The EPRI MRP recommends that “Primary Category” components be periodically 

inspected as part of the RVI management programs. In contrast to this, the EPRI MRP 

recommends that “Expansion Category” components be inspected only if unacceptable 

degradation is identified during inspections of the “Primary Category” components that are 

linked to the “Expansion Category” components.

In its review of LRA AMR items 3.1.1-23 and 3.1.1-24, the staff noted that the criteria in SRP-LR 

Sections 3.1.2.2.9 and 3.1.2.2.10 are based on EPRI MRP’s recommended inspection coverage 

criteria for PWR RVI components, as given in the MRP-227-A report and approved in the 

MRP-227-A report, Safety Evaluation, Revision 1, Section 3.3.1 for “Primary Category” PWR 

RVI components and MRP-227-A report, Safety Evaluation, Revision 1, Section 3.3.2 for 

“Expansion Category” PWR RVI components. The staff also noted that the applicant’s bases in 

LRA Sections 3.1.2.2.9 and 3.1.2.2.10 were consistent and in conformance with the criteria in 

Sections 3.3.1 and 3.3.2 of the Safety Evaluation, Revision 1 on the MRP-227-A report, but did 

not address how the applicant would evaluate relevant aging effects in inaccessible component 

areas or in inaccessible components that are part of a population of redundant RVI components 

(e.g., specific RVI bolting components, some of which are accessible to inspection technologies 

and some that are not accessible to inspection technologies). The staff also noted that the 

methodology in WCAP-17096-NP is currently under staff review pending staff’s acceptance. 

Thus, the staff noted that the applicant was credited a report methodology that had yet to be 

accepted by the staff for use.

By letter dated September 25, 2012, the staff issued RAI 3.1.2.2-1, Parts (a) and (b), to address 

these concerns. In RAI 3.1.2.2-1, Part (a), for those “Primary Category” or “Expansion 

Category” inspections that revealed evidence of aging, the staff requested the applicant to 

clarify whether the evaluations of structural integrity would include an evaluation of the relevant 

aging effects in those areas of an RVI component that are inaccessible to the applicable 

inspection method, or for redundant components like bolting, in those redundant components 

that were inaccessible to inspection. If the applicable evaluations of aging would include an 

assessment of inaccessible areas (or for redundant RVI component like bolts, inaccessible 

components), the staff requested the applicant to clarify how the evaluations of the inaccessible 

areas, or inaccessible redundant components would be performed. In RAI 3.1.2.2-1, Part (b), 

the staff requested the applicant to justify its basis for relying on WCAP-17096-NP as part of the 

monitoring and evaluation bases for the PWR Vessel Internals Program, when the methodology 

in WCAP-17096-NP has yet to be approved by the staff for use. The staff also requested the 

applicant to clarify and justify how it would address any limitations or A/LAIs (or their equivalent) 

that may be issued on the report’s methodology, which might be identified in the staff’s Safety 

Evaluation that will be issued on the report’s methodology. In addition, the staff requested the 

applicant to clarify and justify how the evaluation of flaws or degraded areas would be evaluated 

in the RVI components at Callaway if WCAP-17096-NP is rejected for use by the staff.

By letter dated October 24, 2012, the applicant responded to RAI 3.1.2.2-1, Pars (a) and (b). In 

its response to Part (a), on how the inaccessible areas or components would be evaluated 

under the PWR Vessel Internals Program, the applicant stated the following:

For those “Primary Category” or “Expansion Category” examinations that reveal 

evidence of aging, the corrective action process evaluation would consider the 

applicability of the aging in the inaccessible areas or redundant components. 
AGING MANAGEMENT REVIEW RESULTS

3-314

Examination acceptance criteria and expansion criteria will be consistent with 

MRP-227-A Table 5-3 for Westinghouse plants.

Examination acceptance criteria identify the visual examination relevant 

condition(s), or signal based level or relevance of an indication, that requires 

formal disposition for acceptability. Based on the identified condition, and 

supplemental examinations if required, the disposition process results in an 

evaluation and determination of whether to accept the condition until the next 

examination or repair or replace the item. The evaluation would consider extent 

of the condition in inaccessible areas/components consistent with the associated 

accessible primary component or expansion component evaluation.

Expansion criteria are intended to form the basis for decisions about expanding 

the set of components selected for examination or other aging management 

activity, in order to determine whether the level of degradation represented by the 

detected conditions has extended to other components judged to be less affected 

by the degradation. The expansion criteria of MRP-227-A Table 5-3 would be 

used to determine when the aging detected in the primary component would 

require the additional examinations identified for the expansion component(s). 

Expansion criteria evaluations for accessible primary components will include 

consideration of inaccessible areas/components associated with the primary 

component in the evaluation.

The staff noted that the response demonstrates that the applicant will be evaluating how RVI 

inaccessible areas or inaccessible RVI components would be evaluated under the AMP was 

consistent with basis in Section 5 of the MRP-227-A report and the staff’s recommended 

guidance for assessing these RVI inaccessible areas or components in Sections 3.3.1 and 3.3.2 

of the staff’s revised Safety Evaluation, Revision 1, on the MRP-227-A report methodology. 

Therefore, the staff finds this basis to be acceptable because it is in conformance with the 

MRP-227-A report and with the staff’s bases for achieving appropriate RVI component 

inspection coverages and for evaluating RVI inaccessible areas or inaccessible RVI 

components in the Safety Evaluation, Revision 1, on the MRP-227-A report. The staff’s concern 

described in RAI 3.1.2.2-1, Part (a), is resolved.

In its response to RAI 3.1.2.2-1, Part (b), the applicant stated that, if WCAP-17096-NP is 

approved for use by the staff with any limitations or A/LAIs as identified in the staff’s Safety 

Evaluation, the implementation of the PWR Vessel Internals Program will be supplemented 

consistent with condition or action items in the staff’s Safety Evaluation approving the 

WCAP-17096-NP methodology. The applicant also stated that if WCAP-17096-NP is rejected 

for use by the staff, Callaway engineering evaluations for RVIs will be performed consistent with 

available industry guidance (e.g., EPRI-MRPs, PWR Owners Group Reports, etc.). The staff 

finds this basis acceptable because the applicant will either: (a) use a staff-endorsed version of 

WCAP-17096-NP, as subject to any staff limitations or actions that are issued in the staff’s 

Safety Evaluation on that report’s methodology, to establish the acceptance criteria and 

evaluate the results of inspections performed in accordance with the MRP-227-A methodology; 

or (b) use applicable industry guidance recommendations for this purpose. Therefore, the 

staff’s concern described in RAI 3.1.2.2-1, Part (b). is resolved.

Based on its review, the staff finds that the applicant has met the further evaluation criteria in 

SRP-LR Sections 3.1.2.2.9 and 3.1.2.210 and that the basis in the PWR Vessel Internals 

Program for achieving minimum inspection coverage and evaluating inaccessible areas or 
AGING MANAGEMENT REVIEW RESULTS

3-315

inaccessible redundant components is acceptable because: (a) the staff has confirmed that the 

applicant’s PWR Vessel Internals Program includes inspection coverage scopes that are 

consistent with those approved by the staff for programs based on the criteria of the MRP-227-A 

report, and (b) any evaluations of structural integrity for the RVI components would include 

applicable assessments of aging in the inaccessible areas of the components areas or in those 

inaccessible components that are part of a redundant population of RVI components (such as 

bolting). For those AMR items that apply to LRA Sections 3.1.2.2.9 and 3.1.2.210, the staff 

determines that the LRA is consistent with the GALL Report and that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will remain consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.1.2.2.11 Cracking Due to Primary Water Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.11 against the following criteria in SRP-LR 

Section 3.1.2.2.11:

(1) LRA Section 3.1.2.2.11.1, associated with LRA Table 3.1-1, item 3.1.1-25, addresses 

foreign operating experience in steam generators with a similar design to that of 

Westinghouse Model 51 which has identified extensive cracking due to PWSCC in 

steam generator divider plate assemblies fabricated of Alloy 600 and/or the associated 

Alloy 600 weld materials, even with proper primary water chemistry (EPRI TR-1014982).

The applicant addressed the further evaluation criteria of the SRP-LR through 

Commitment No. 34, stating: (1) the applicant would perform an inspection of each 

steam generator, with an examination technique capable of detecting PWSCC, to 

assess the condition of the divider plate welds; or (2) the applicant stated it would 

perform an analytical evaluation of the steam generator divider plate welds in order to 

establish a technical basis which concludes that the steam generator RCS pressure 

boundary is adequately maintained with the presence of steam generator divider plate 

weld cracking; or (3) If results of industry and NRC studies and operating experience 

document that potential failure of the steam generator RCS pressure boundary caused 

by PWSCC cracking of steam generator divider plate welds is not a credible concern, 

Commitment No. 34 will be revised to reflect that conclusion.

(2) LRA Section 3.1.2.2.11.2, associated with LRA Table 3.1-1, item 3.1.1-25, addresses 

cracking due to PWSCC that could occur in steam generator nickel alloy tube-to-tube 

sheet welds exposed to reactor coolant. The applicant addressed the further evaluation 

criteria of the SRP-LR through Commitment No. 35, which state the following: 

• [Union Electric Company (Ameren Missouri) will] [p]erform a one-time inspection 

of a representative number of tube-to-tubesheet welds in each steam generator 

to determine if PWSCC cracking is present. If weld cracking is identified, the 

condition will be resolved through repair or engineering evaluation to justify 

continued service, as appropriate, and an ongoing monitoring program will be 

established to perform routine tube-to-tubesheet weld inspections for the 

remaining life of the steam generators; or 

• [p]erform an analytical evaluation of the steam generator tube-to-tubesheet welds 

in order to establish a technical basis which concludes that the structural integrity 

of the steam generator tube-to-tubesheet interface is adequately maintained with 

the presence of tube-to-tubesheet weld cracking. Establish a technical basis 
AGING MANAGEMENT REVIEW RESULTS

3-316

which concludes that the steam generator tube-to-tubesheet welds are not 

required to perform a [RCPB] function. 

In its review of Commitment Nos. 34 and 35, the staff noted that it needed additional 

information regarding the applicant’s management of aging effects for the 

tube-to-tubesheet welds and divider plate. By letter dated September 20, 2012, the staff 

issued RAI 3.1.2.2.11-1, Parts (a), (b), and (c). The staff’s discussion of 

RAI 3.1.2.2.11-1, Parts (a), (b), and (c) is documented below.

In RAI 3.1.2.2.11-1, Part (b), the staff requested the applicant to provide the following 

information regarding the divider plate and associated Commitment No. 34: 

• The staff requested the applicant to clarify the configuration of the divider plate 

assembly. In particular, the staff requested the applicant clarify if the divider 

plate assembly (i.e., the stub runner) is welded to the carbon steel tubesheet or 

the tubesheet cladding. The staff also requested the applicant clarify whether the 

divider plate is welded to the stainless steel channel head cladding or the low 

alloy carbon steel shell. In addition, the staff requested the applicant to provide 

the weld material for the welds.

• The staff requested the applicant to discuss plans for clarifying the commitment 

(Commitment No.34) such that the inspection technique used will be qualified to 

detect cracking in the divider plate assembly given that cracks have been 

observed outside the weld region (i.e., in the heat affected zone).

• The staff requested the applicant to clarify the frequency for this inspection, or to 

state if it is a one-time inspection.

• The staff requested the applicant to discuss its plans to remove the last two 

options in the commitment since, if such analyses become available, they could 

be submitted to the NRC for review and if approved, may serve as a basis for 

revising the commitment. The staff noted that if additional analyses become 

available that demonstrate pressure boundary integrity is adequately maintained 

with divider plate weld cracking, or if studies indicate that failure of the pressure 

boundary is not a concern, then the commitment may be revised at that time.

In its response to RAI 3.1.2.2.11-1, Part (b), dated October 24, 2012, the applicant 

stated that based on the steam generator design drawings, there is no stub runner at the 

interface between the divider plate (called partition plate in applicant’s steam generator 

design drawings) and the tubesheet of the steam generators. The applicant also stated 

that there is a small rectangular Alloy 690 closure plate (also known as a filler plate on 

other steam generator designs) installed at the Alloy 690 divider plate to stainless steel 

clad primary head and Alloy 82/182 clad tube sheet junctions. The applicant further 

stated that the most stressed portions of the channel head in contact with the primary 

coolant are welded with Alloy 15 and the most stressed areas are associated with the 

divider plate to primary head and tube sheet junctions. In addition, the applicant stated 

that the steam generator design drawings show the following weld and buttering 

materials:

• divider plate to tubesheet cladding: Alloy 152 weld and buttering materials

• divider plate to closing plate: Alloy 152 weld materials

• divider plate to primary head cladding: Alloy 152 weld material

• closing plate to tubesheet cladding: Alloy 152 weld and buttering materials
AGING MANAGEMENT REVIEW RESULTS

3-317

• closing plate to tubesheet ring: Alloy 152 weld and stainless steel buttering

• closing plate to primary head cladding: Alloy 152 weld materials

Additionally, the applicant revised LRA Table A4-1, Commitment No. 34, to state that: 

(a) the inspection will include the divider plate assembly and associated welds, {b) the 

inspection will be a one-time inspection, and (c) the analytical evaluation of the divider 

plate welds will be submitted to the staff for review and approval.

In RAI 3.1.2.2.11-1, Part (a), the staff requested the applicant to provide the following 

information related regarding the tube-to-tubesheet weld and associated Commitment 

No. 35:

• The staff requested the applicant to discuss its plans to modify Commitment 

No. 35 to indicate that the technical basis for the redefinition of the RCPB will be 

submitted to the staff for review and approval as part of the license amendment 

process prior to redefining the RCPB.

• The staff requested the applicant to discuss whether an analytical evaluation may 

be performed to assess whether the welds are susceptible to PWSC. If it is 

determined that the welds are not susceptible to primary water stress corrosion 

cracking, and the staff agrees with this determination, the staff requested the 

applicant to discuss the plans for using this as the basis for not performing 

inspections of the welds. Additionally, the staff requested the applicant discuss 

plans to modify Commitment No. 35 to reflect the response to the staff’s request.

• The staff requested the applicant to confirm that the inspection technique(s) used 

to inspect the welds will be capable of detecting PWSCC. In addition, the staff 

requested that the applicant discuss its plans to modify Commitment No. 35 to 

reflect that the inspection technique(s) will be capable of detecting PWSCC.

In its response to RAI 3.1.2.2.11-1, Part (a), dated October 24, 2012, the applicant

revised LRA Table A4-1, Commitment No. 35, to state that a redefinition of the RCPB 

will be submitted as part of a license amendment request requiring approval from the 

staff and that the examination technique(s) used by the applicant will be capable of 

detecting PWSCC in the tube-to-tubesheet welds. Additionally, the applicant revised 

Commitment No. 35 to allow for performing an analytical evaluation of the steam 

generator tube-to-tubesheet welds to determine their susceptibility to PWSCC, and to 

submit the analysis for staff review if it is determined that the welds are not susceptible 

to PWSCC and do not require inspection.

In RAI 3.1.2.2.11-1, Part (c), the staff requested information regarding both the divider 

plate and tube-to-tubesheet weld Commitments No. 34 and 35. The staff requested the 

applicant to discuss its plans to include the divider plate and tube-to-tubesheet weld 

commitments in the FSAR supplement. The staff also requested the applicant to 

discuss plans for revising the commitments to specify that an inspection of each steam 

generator, to assess the condition of the divider plate assembly and tube-to-tubesheet 

weld, will be performed during a specific time period (e.g., the inspections will be 

performed no earlier than 3 years before the period of extended operation and no later 

than 2 years after entering the period of extended operation). The staff also requested 

that for the actual timeframe chosen the applicant consider the amount of operating time 

on the steam generator.

In its response to to RAI 3.1.2.2.11-1, Part (c), dated October 24, 2012, the applicant 

revised LRA Section A1.9 and 3.1.2.2.11 to be consistent with the changes to LRA Table 

A4-1 Commitments No. 34 and 35 as noted above. The applicant also revised LRA 
AGING MANAGEMENT REVIEW RESULTS

3-318

Table A4-1, Commitments No. 34 and 35, to reflect implementation schedule between 

fall 2025 and fall 2029, when the replacement steam generators will have been in 

service for more than 20 years.

The staff finds the applicant response to RAI 3.1.2.2.11-1, Parts (a), (b), and (c), 

acceptable because the revisions to Commitment No. 34 and No. 35 will ensure that the 

applicant gets approval from the staff prior to redefining the RCPB and that the 

inspection techniques used to examine the tube-to-tubesheet welds are qualified to 

detect PWSCC. Additionally, the staff finds that the revisions to the LRA and 

Commitments No.34 and 35 are acceptable because they will ensure that the applicant 

gets approval from the staff before discontinuing the inspections for PWSCC in the 

tube-to-tubesheet or divider plate welds should the applicant perform an analytical 

evaluation finding that the welds are not susceptible to PWSCC. The staff finds that this 

will provide adequate time for the the staff to independently review the conclusions of the 

analysis prior to the applicant taking action. The staff also finds that an inspection 

between fall of 2025 and fall 2029 will ensure that the steam generators will have 

sufficient operating time to ensure that any degradation that may occur will have had 

time to take place. Therefore, the staff’s concerns described in RAI 3.1.2.2.11-1, Parts

(a), (b), and (c), are resolved. 

In a supplemental letter dated February 14, 2014, the applicant revised the timeframe of 

submittal for Options 2 or 3 (if chosen) of LRA Table A4-1, Commitment No. 34 and 

Option 2 (if chosen) of Commitment No. 35. The applicant revised the commitment 

implementation schedules for each commitment such that, if an Option 2 or 3 is chosen, 

then the respective results would be submitted for NRC review in the fall, 2023. The 

staff finds the applicant’s supplemental information acceptable because the period the 

applicant provided for completing Commitment Nos. 34 and 35, Option 2 or 3 (if chosen) 

and submitting the respective analysis will allow the staff time to review and disposition 

the analysis prior to the plant entering the period of extended operation. 

The staff’s evaluation of the applicant’s Water Chemistry Program is documented in SER 

Section 3.0.3.1.2. In its review of components associated with LRA Table 1 

item 3.1.1-25, the staff finds that the applicant has met the further evaluation criteria. 

The staff finds that the applicant’s proposal to manage cracking of the divider plate and 

tube-to-tubesheet weld using the Water Chemistry Program and confirming the 

adequacy of this program through inspection is acceptable because proper management 

of water chemistry may mitigate PWSCC in the divider plate and tube-to-tube sheet 

welds. The staff finds that confirming the adequacy of the Water Chemistry Program 

through inspections will detect the presence of PWSCC in the divider plate or 

tube-to-tubesheet welds should it occur and allow for the applicant to take the 

appropriate corrective actions. Alternatively, should the applicant establish a technical 

basis that concludes that the steam generator RCPB is adequately maintained with the 

presence of cracking in the steam generator divider plate or the results of industry and 

staff studies and operating experience document that PWSCC of the steam generator 

divider plate is not a credible concern, then confirming that PWSCC in the divider plate 

does not occur through inspections will no longer be necessary. Similarly, should the 

applicant establish a technical basis that concludes that the steam generator RCPB is 

adequately maintained with the presence of cracking in the steam generator 

tube-to-tubesheet welds, or that the tube-to-tubesheet weld is not susceptible to 

PWSCC, then confirming that PWSCC in the tube-to-tubesheet welds does not occur 

through inspections will no longer be needed. 
AGING MANAGEMENT REVIEW RESULTS

3-319

Based on the program identified, the staff concludes that the applicant’s program meets the 

criteria of SRP-LR Section 3.1.2.2.11. For those AMR items associated with LRA 

Section 3.1.2.2.6, the staff determined that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.12 Cracking Due to Fatigue

LRA Section 3.1.2.2.12, associated with LRA Table 3.1-1, item 3.1.1-26, addresses cracking 

due to fatigue in Combustion Engineering-designed RVI core support barrel assembly lower 

flange welds, upper internals assembly fuel alignment plates, and lower support structure core 

support plates exposed to a reactor coolant environment. The applicant stated that this item is 

not applicable to Callaway because this item is only applicable to Combustion 

Engineering-designed RVI components and because the RVI assemblies at Callaway were 

designed by Westinghouse. However, the applicant stated that the evaluation of cumulative 

fatigue damage due to fatigue for the Westinghouse-designed RVI assemblies and components 

at the Callaway Plant is addressed in LRA Section 3.1.2.2.1.

LRA Table 3.1-1, item 3.1.1-26, is based on the AMR criteria in SRP-LR Section 3.1.2.2.12 and 

SRP-LR Table 3.1-1, item No. 26, which invokes AMR items for Combustion 

Engineering-designed core support barrel assembly lower flange welds, upper internals 

assembly fuel alignment plates, and lower support structure core support plates in AMR items 

IV.B3.RP-333, IV.B3.RP-338, and IV.B3.RP-343 of the GALL Report. SRP-LR 

Section 3.1.2.2.12 states that EPRI 1016596, “Materials Reliability Program: Pressurized Water 

Reactor Internals Inspection and Evaluation Guidelines,” (MRP-227-A, Revision 0) identifies 

cracking due to fatigue as an aging effect that can occur for the lower flange weld in 

Combustion Engineering-designed core support barrel assembly lower flange welds, upper 

internals assembly fuel alignment plates, and lower support structure core support plates. 

SRP-LR states that the GALL Report recommends that inspection for cracking in this 

component be performed if acceptable fatigue life cannot be demonstrated by TLAA through the 

period of extended operation as defined in 10 CFR 54.3.

The staff reviewed LRA Sections 2 and FSAR and noted that FSAR defines the Callaway Plant 

as a Westinghouse-designed 4-loop light water reactor. Based on this review, the staff finds 

that the applicant has provided an acceptable basis for claiming that the criteria in SRP-LR 

Section 3.1.2.2.12 and SRP-LR Table 3.1-1, item No 26, is not applicable to Callaway because 

the staff has confirmed that: (a) the recommendations in SRP-LR Section 3.1.2.2.12 and 

SRP-LR Table 3.1-1, item No 26, are only applicable to specific Combustion 

Engineering-designed RVI components, and (b) Callaway is a Westinghouse-designed PWR.

The staff confirmed that the applicant has addressed metal fatigue of the Callaway RVI core 

support structure components in LRA Section 3.1.2.2.1 and has included the metal fatigue 

TLAAs for these components in LRA Section 4.3.3 and LRA Table 4.3-5. The staff evaluation of 

these LRA Sections is documented in SER Sections 3.1.2.2.1 and 4.3.3.2.

3.1.2.2.13 Cracking Due to Stress Corrosion Cracking and Fatigue

LRA Section 3.1.2.2.13, associated with LRA Table 3.1-1, item 3.1.1-27, addresses nickel alloy 

guide tube support pins of Westinghouse CRGT assemblies, exposed to reactor coolant and 

neutron flux. LRA Section 3.1.2.2.13 states that this item is not applicable because this item is 
AGING MANAGEMENT REVIEW RESULTS

3-320

only applicable to nickel-alloy guide tube support pins and Callaway’s guide tube support pins 

are made of stainless steel. 

The criteria in SRP-LR Section 3.1.2.2.13 invoke AMR Item IV.B2.RP-355 of the GALL Report 

and state that cracking due to SCC and fatigue could occur in nickel alloy CRGT assembly

guide tube support pins exposed to reactor coolant and neutron flux. GALL Report, AMR 

item IV.B2.RP-355, recommends further evaluation of a plant-specific AMP to ensure this aging 

effect is adequately managed. 

In comparison, LRA Section B2.1.6, “PWR Vessel Internals,” indicates that based on industry 

operating experience the applicant replaced the Alloy X-750 guide tube support pins (also called 

split pins) with strain-hardened (cold-worked) 316 stainless steel pins during RFO 13 

(spring 2004), to reduce the susceptibility of the support pins to SCC. The LRA also states that 

there were no cracked Alloy X-750 pins discovered during the replacement process. It is noted 

that Alloy X-750 is a type of nickel alloy.

In addition, LRA Table 3.1.2-1 indicates that cracking of the stainless steel CRGT support pins 

is managed by the Water Chemistry Program and PWR Vessel Internals Program (Existing 

Program Components) under LRA item 3.1.1-53. Furthermore, LRA Table 3.1.2-1 indicates that 

cracking of the stainless steel CRGT support pins is also managed by ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program under LRA item 3.1.1-32.

After the issuance of SRP-LR and the GALL Report, the staff issued Revision 1 of the Safety 

Evaluation of EPRI MRP-227-A, Revision 0, “Pressurized Water Reactor (PWR) Internals 

Inspection and Evaluation Guidelines,” dated December 16, 2011. Section 3.2.5.3, “Evaluation 

of the Adequacy of Plant-Specific Existing Programs,” of Revision 1 of the Safety Evaluation 

states:

Westinghouse guide tube support pins are made from either 316 stainless steel or Alloy X750. 

There have been issues with cracking of the original Alloy X750 pins and many licensees have 

replaced them with type 316 stainless steel materials. Applicants/licensees shall evaluate the 

adequacy of their plant-specific existing program and ensure that the aging degradation is 

adequately managed during the extended period of operation for both Alloy X750 and type 316 

stainless steel guide tube support pins (split pins). Therefore, it is recommended that the 

evaluation consider the need to replace the Alloy X750 support pins (split pins), if applicable, or 

inspect the replacement type 316 stainless steel support pins (split pins) to ensure that cracking 

has been mitigated and that aging degradation is adequately monitored during the extended 

period of operation.

Revision 1 of the Safety Evaluation of MRP-227 also identified the aging management for the 

CRGT support pins as A/LAI 3. Therefore, the staff needed additional information regarding the 

applicant’s aging management and inspections to manage cracking of the replacement stainless 

steel CRGT support pins as described below. 

By letter dated August 16, 2012, the staff issued RAI 3.1.1.27-1 requesting that the applicant 

clarify whether the ASME Section Xl lnservice Inspection, Subsections IWB, IWC, and IWD 

Program is the existing program that is used to manage cracking of these stainless steel CRGT 

support pins in conjunction with the PWR Vessel Internals Program. The staff also requested 

that the applicant provide the technical basis for why the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program is adequate to ensure that aging degradation is 

adequately monitored during the period of extended operation. In addition, the staff requested 

that the applicant clarify whether the VT-3 examination under Examination Category B-N-3 
AGING MANAGEMENT REVIEW RESULTS

3-321

includes examination of the support pins to manage cracking. The staff further requested that 

the applicant confirm whether the applicant’s actions in response to A/LAI 3 are consistent with 

the existing staff-mandated and vendor/supplier-recommended inspection monitoring bases for 

the applicant’s stainless steel CRGT support pins. 

In its response dated September 20, 2012, the applicant stated that LRA Table 3.1.2-1 identifies 

that cracking of stainless steel CRGT support pins is managed by the Water Chemistry Program 

and the PWR Vessel Internals Program, consistent with GALL Report AMR item B2.RP-346. 

The applicant also clarified that as described in LRA Table 3.1.2-1, the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program is the existing program that is 

used to manage cracking of the support pins in conjunction with the PWR Vessel Internals 

Program, consistent with GALL Report item IV.B2.RP-382. The applicant further stated that it 

has replaced the Alloy X750 CRGT support pins (split pins) with 316 stainless steel materials 

and the support pins are included in the Existing Program Components of MRP-227-A, 

Table 3-3. In addition, the applicant indicated that the LRA includes the stainless steel CRGT 

support pins in response to the December 2011 staff Safety Evaluation, Section 3.2.5.3 and 

there are no staff-mandated or vendor/supplier-recommended inspection requirements for the 

CRGT support pins in the applicant’s CLB. 

In its response regarding the examination method, the applicant stated that, consistent with 

MRP-227-A, Category B-N-3 examinations of the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program manage the aging degradation of Existing Program 

Components. The applicant also stated that consistent with IWB-3520, Examination 

Category B-N-3 uses a VT-3 examination, and IWB-3200(b) permits supplemental surface or 

volumetric examinations to determine the extent of relevant conditions detected by the VT-3 

examinations. The applicant further stated that therefore, the aging degradation of the CRGT 

support pins is adequately managed by Category B-N-3 examinations of the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program in conjunction with the PWR 

Vessel Internals Program during the period of extended operation.

In its review, the staff finds the applicant’s response acceptable because: (a) the applicant 

clarified that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program is the existing program to manage cracking of the replacement stainless steel support 

pins of the CRGT components in conjunction with the PWR Vessel Internals Program; (b) VT-3 

examinations in accordance with ASME Code Examination Category B-N-3 are used to detect 

and manage cracking of the support pins, consistent with the GALL Report; (c) ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program also includes 

adequate provisions to correct relevant conditions that would be detected from the VT-3 

examinations; and (d) the applicant’s CLB does not include staff-mandated or 

vendor/supplier-recommended inspection requirements, other than the ASME Code ISI, for the 

CRGT support pins so that the applicant’s aging management for the support pins are 

consistent with its CLB. RAI 3.1.1.27-1 is resolved. 

The staff’s evaluations of the Water Chemistry Program, PWR Vessel Internals Program and 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program are 

documented in SER Sections 3.0.3.1.2, 3.0.3.1.5, and 3.0.3.1.1, respectively. In its review, the 

staff finds the applicant’s use of the Water Chemistry Program acceptable to manage the aging 

effect because: (a) the monitoring and controlling of water chemistry is performed periodically in 

accordance with the EPRI PWR water chemistry guidelines as recommended by GALL Report 

AMP XI.M2, “Water Chemistry,” and (b) the chemistry control can minimize the concentrations 

of detrimental contaminants and mitigate the SCC in the components. In addition, the staff finds 
AGING MANAGEMENT REVIEW RESULTS

3-322

the applicant’s use of the PWR Vessel Internals Program and ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program acceptable to manage the aging effect 

because the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program 

is identified as the existing program for the CRGT support pins in conjunction with the PWR 

Vessel Internals Program, consistent with the GALL Report, and the VT-3 examinations of these 

components in accordance with the ASME Code Section XI Examination Category B-N-3 are 

adequate to detect and manage cracking of these components. 

Based on the programs identified, the staff concludes that the applicant’s programs meet the 

criteria in SRP-LR Section 3.1.2.2.13. For those items associated with LRA Section 3.1.2.2.13, 

the staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.1.2.2.14 Loss of Material due to Wear

LRA Section 3.1.2.2.14, associated with LRA Table 3.1-1, item 3.1.1-28, addresses loss of 

material due to wear in Westinghouse-designed RVI CRGT assembly support pins (split pins) 

and ICI lower thimble tubes exposed to a reactor coolant environment. The applicant stated 

that this item is not applicable to the Callaway LRA with respect to the design of the Callaway 

CRGT split pins because this item is only applicable to Westinghouse-design CRGT split pins 

that are made from nickel alloy materials and the CRGT spilt pins at the Callaway Plant are 

made from stainless steel. 

LRA Table 3.1-1, item 3.1.1-28 is based on the AMR criteria in SRP-LR Section 3.1.2.2.14 and 

SRP-LR Table 3.1-1, item No. 28, which invokes the AMR item for managing loss of material 

due to wear of Westinghouse-design CRGT split pins in GALL Report AMR item IV.B2.RP-356. 

SRP-LR Section 3.1.2.2.14 states that loss of material due to wear could occur in 

Westinghouse-designed CRGT split pins that are made from nickel alloy materials. SRP-LR 

Section 3.1.2.2.14 also states that the AMR item IV.B2.RP-356 on management of wear in 

Westinghouse-designed CRGT split pins recommends further evaluation of a plant-specific 

AMP to ensure wear will be adequately managed during the period of extended operation.

LRA Section B2.1.6, “PWR Vessel Internals,” is based in part on the recommended guidelines 

for Westinghouse-designed RVI components in EPRI Report No. 1022863, “Materials Reliability 

Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines 

(MRP-227-A).” This EPRI Report was approved in a revised staff Safety Evaluation, Revision 1, 

dated December 16, 2011. This Safety Evaluation included appropriate A/LAIs that were to be 

responded to for incoming PWR LRAs. The staff noted that the basis in SRP-LR 

Section 3.1.2.2.14 is based in part on the criteria for managing wear in Westinghouse-designed 

CRGT split pins, as defined in the MRP-227-A report and impacted by the staff’s evaluation in 

Section 3.2.5.3 of the Safety Evaluation, Revision 1, on the MRP-227-A methodology. In this 

section of the revised Safety Evaluation, the staff stated that Westinghouse CRGT split pins are 

made from either 316 stainless steel or Alloy X-750 (i.e., a nickel alloy material). The staff 

stated that there have been issues with cracking and wear of the original Alloy X-750 pins and 

that many licensees have replaced them with cold worked, type 316 stainless steel materials. 

Thus, in the Safety Evaluation, the staff recommended that license renewal applicants for 

Westinghouse-design light water reactors should evaluate the adequacy of their plant-specific 

existing programs and ensure that the aging degradation is adequately managed during the 

extended period of operation for CRGT split pins made from either Alloy X-750 or stainless steel 
AGING MANAGEMENT REVIEW RESULTS

3-323

materials. Thus, the staff recommended that applicants should either consider the need to 

replace CRGT split pins made from Alloy X-750 materials, if applicable, or inspect their 

replacement stainless steel CRGT split pins to ensure that potential cases of wear would be 

adequately monitored during the extended period of operation. The staff identified this 

recommendation as A/LAI No. 3 on the MRP-227-A methodology.

The staff noted that the LRA does not currently include Callaway’s responses to the A/LAIs on 

MRP-227-A, including the response to A/LAI No. 3 as made relative to the applicant’s basis for 

managing cracking and inspecting the CRGT spilt pins at Callaway. By letter dated 

September 25, 2012, the staff issued RAI B2.1.6-4, requesting that the applicant provide its 

basis for omitting responses to the applicable A/LAIs on MRP-227-A methodology that are 

determined to be applicable to Westinghouse-designed RVI components at Callaway. 

By letter dated October 24, 2012, the applicant provided its response to RAI B2.1.6-4. The 

staff’s evaluation of the applicant’s response to RAI B2.1.6-4 is documented in SER 

Section 3.0.3.1.5, which provides the staff’s evaluation of the applicant’s PWR Vessel Internals 

Program and the applicant’s response basis for A/LAI No. 3. As described in SER 

Section 3.0.3.1.5, the staff found the applicant had appropriately resolved the request in A/LAI 

No. 3 because: (a) the applicant had already replaced the previous CRGT split pins that were 

made from Inconel X-750 materials with CRGT split pins made from cold-worked Type 316 

stainless steel materials; (b) the applicant was crediting its ASME Code Section XI Examination 

Category B-N-3 examinations as the basis for managing loss of material and cracking that might 

occur in the CRGT split pins during the period of extended operations; and (c) this basis was in 

conformance with the staff’s recommendation in A/LAI No. 3.

However, the staff has noted that, in LRA Table 3.1.2-1, the applicant only credited its Water 

Chemistry Program as the basis for managing loss of material in the CRGT split pins. In 

contrast, the staff noted that, in Table 3-3 of the MRP-227-A report, the EPRI MRP identifies 

that loss of material caused by wear is an applicable aging effect for CRGT split pins. Thus, the 

staff noted that the implementation of the Water Chemistry Program would not be an acceptable 

basis for managing loss of material that would initiate by mechanical mechanisms such as wear, 

abrasion or fretting because the mitigative chemical control activities of the AMP would not have 

any impact on alleviating the consequences of loss of material initiating from these types of 

mechanical aging mechanisms. Thus, the staff did not have sufficient information to conclude 

that wear would not be applicable to the CRGT split pins at Callaway or how loss of material 

caused by wear could be adequately managed solely through implementation of the Callaway 

Water Chemistry Program. Therefore, by letter dated September 25, 2012, the staff issued 

RAI 3.1.2.1-4, Parts (a) and (b). RAI 3.1.2.1-4, Part (a), requested that the applicant provide the 

basis as to why loss of material caused by wear was not identified as an applicable AERM for 

the CRGT split pins when this AERM is identified in the MRP-227-A report for these 

components. If loss of material caused by wear is an applicable AERM for CRGT split pins, the 

staff requested the applicant to justify its basis for managing loss of material in the CRGT split 

pins using only the Water Chemistry Program. The staff’s description and evaluation of 

RAI 3.1.2.1-4, Part (b), is documented in SER Section 3.1.2.1.3.

The applicant responded to RAI 3.1.2.1-4, Part (a) in a letter dated October 24, 2012. In its 

response to RAI 3.1.2.1-4, Part (a), the applicant stated that the CRGT split pins are designated 

as ASME Code Section XI, Examination Category B-N-3 components for the CLB. As part of its 

response the applicant amended the AMR item in LRA Table 3.1.2-1 on cracking of the CRGT 

split pins to add loss of material as an additional aging effect that is within the scope of the AMR 

item (i.e., in addition to cracking) and to indicate that it would be using the PWR Vessel Internals 
AGING MANAGEMENT REVIEW RESULTS

3-324

Program as an alternative basis for conforming to the guidance in GALL Report AMR 

item IV.B2.RP-382. The applicant also stated that it will be using the “Existing Program” bases 

of the PWR Vessel Internals Program as the basis for managing cracking and loss of material in 

the CRGT split pins and for implementing the existing Examination Category B-N-3 visual 

(VT-3) examinations that are mandated for these components in accordance with the 

requirements in 10 CFR 50.55a and Section XI of the ASME Code. The staff confirmed that the 

applicant adequately amended the LRA the AMR item in its October 24, 2012, letter. 

Based on this review, the staff finds that the applicant has provided an acceptable alternative 

basis for managing loss of material due to wear (and cracking) in the CRGT split pins because: 

(a) the applicant will still be using its ASME Code Section XI ISI of the CRGT splits pins as the 

basis for managing loss of material and cracking in the components; (b) the applicant will be 

using the “Existing Program” bases of its PWR Vessel Internals Program as an alternative basis 

for implementing the mandated ASME Code Section XI, Examination Category B-N-3 visual 

examinations of these components in lieu of using ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program to implement them; and (c) this demonstrates an 

acceptable alternative basis for implementing mandated ASME Code Section XI requirements 

for the components that are mandated in 10 CFR 50.55a and recommended in GALL Report 

AMR item IV.B2.RP-382. Therefore, the staff’s concern described in RAI 3.1.2.1-4, Part (a), is 

resolved. 

3.1.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA Program.

3.1.2.2.16 Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of aging management 

programs.

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.1.2-1 through 3.1.2-4, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.1.2-1 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 an 

AMR item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the AMR item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the AMR 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 
AGING MANAGEMENT REVIEW RESULTS

3-325

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.

3.1.2.3.1 Reactor Vessel, Internals, and Reactor Coolant System—Summary of Aging 

Management Evaluation—Reactor Vessel and Internals—LRA Table 3.1.2-1

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the 

reactor vessel and internals component groups.

Nickel Alloy Reactor Vessel Flange Leak Monitoring Tubing Exposed to Borated Water 

Leakage. In LRA Table 3.1.2-1, the applicant stated that nickel alloy reactor vessel flange leak 

monitoring tubing exposed to borated water leakage will be managed for cracking by the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program. The AMR item cites 

generic note F, and plant-specific note 1. Plant-specific note 1 states the following:

[The GALL Report] does not address cracking of nickel-alloy reactor vessel 

flange leak monitoring tube with an internal environment of reactor coolant 

leakage. The ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD [P]rogram (B2.1.1) manages the cracking of the nickel-alloy reactor 

vessel flange leak monitoring tube with an internal environment of reactor coolant 

leakage. 

The staff reviewed the associated items in the LRA and confirmed that the GALL Report does 

not include entries for nickel-alloy reactor vessel flange leak monitoring tubing exposed to air 

with borated water leakage (internal). Therefore, the staff finds the applicant’s use of generic 

note F appropriate. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, material 

and environment description. The staff noted that the GALL Report has entries for vessel flange 

leak detection lines fabricated from stainless steel, and recommends that a plant-specific aging 

management program be evaluated. The staff noted that the applicant addressed cracking for 

this component. Specifically, LRA Section 3.1.2.2.6, item 1, is associated with LRA Table 3.1-1, 

item 3.1.1-19, which in part also addresses the aging management of cracking in PWR reactor 

vessel flange leakage detection lines, under the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program. The staff finds the applicant’s use of plant-specific 

note 1, appropriate because, during normal operations the environment for the reactor vessel 

flange leak monitoring line is not expected to be exposed to borated water. The staff finds that 

during normal operations, the reactor vessel flange leak detection line would only be exposed to 

borated water, if there is leakage past the vessel O-ring. Therefore, the staff finds the 

applicants proposal to use its ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program acceptable, because if leakage does occur past the O-ring, and results in 

leakage of the flange monitoring tubing, the applicant’s credited examinations during ISIs would 

detect the leakage. 

SER Section 3.0.3.1.1 documents the staff’s evaluation of the applicant’s ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program. SER Section 3.1.2.2.6.1, 

item 1 documents the staff’s evaluation of the applicant’s further evaluation associated with its 

reactor vessel flange leak monitoring tubing.

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 
AGING MANAGEMENT REVIEW RESULTS

3-326

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.2 Reactor Vessel, Internals, and Reactor Coolant System—Summary of Aging 

Management Evaluation—Reactor Coolant System—LRA Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the 

RCS component groups. The staff’s review did not identify any AMR items with notes F through 

J, indicating that the combinations of component type, material, environment, and AERM for the 

RCS component groups are consistent with the GALL Report.

3.1.2.3.3 Reactor Vessel, Internals, and Reactor Coolant System—Summary of Aging 

Management Evaluation—Pressurizer—LRA Table 3.1.2-3 

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the 

pressurizer component groups. The staff’s review did not identify any AMR items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for the pressurizer component groups are consistent with the GALL Report.

3.1.2.3.4 Reactor Vessel, Internals, and Reactor Coolant System—Summary of Aging 

Management Evaluation—Steam Generators—LRA Table 3.1.2-4

The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations for the 

steam generators component groups.

Nickel Alloy Steam Generator Tubes Exposed to Secondary Water (loss of material). In LRA 

Table 3.1.2-4, the applicant stated that nickel alloy steam generator tubes exposed to 

secondary water will be managed for loss of material due to wear by the TLAA for replacement 

steam generator tubes as described in LRA Section 4.7.9. The AMR item in the LRA table cites 

generic note H, which indicates that the applicant’s material, environment, aging effect, and 

aging management combination is not evaluated in the GALL Report. 

In addition, LRA Table 3.1.2-4 includes another AMR item, associated with LRA Table 1 AMR 

item 3.1.1-77, to manage the same aging effect of this component using the Steam Generators 

Program, consistent with GALL Report item IV.D1.RP-233. Therefore, the staff noted that the 

applicant proposed use of the steam generator tube TLAA and Steam Generators Program to 

manage loss of material caused by wear for the steam generator tubes. 

The staff’s evaluations of the applicant’s Steam Generators Program and replacement steam 

generator tube wear TLAA are documented in SER Sections 3.0.3.1.7 and 4.7.9, respectively. 

The staff finds the applicant’s proposal to manage aging using the Steam Generators Program 

acceptable because the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), 

as described in LRA Amendment No. 9 dated September 20, 2012, that the effects of wear on 

the intended function of the steam generator tubes will be adequately managed by the Steam 

Generators Program. The staff finds that the Steam Generators Program includes inspections 

of the steam generator tubes, assessment of tube integrity, and plugging and repair activities for 

degraded tubes, which are adequate to detect and manage steam generator tube wear. 

Nickel Alloy Steam Generator Tubes Exposed to Secondary Water (reduction in heat transfer). 

During its review of the AMR items in LRA Table 3.1.2-4 associated with SG tubes, the staff 

noted that heat transfer was listed as an intended function of the SG tubes, but reduction of heat 
AGING MANAGEMENT REVIEW RESULTS

3-327

transfer was not cited as an applicable aging effect. By letter dated September 20, 2012, the 

staff issued RAI 3.1.2.4-1, requesting the applicant to identify how the reduction of heat transfer 

aging effect would be managed for nickel alloy steam generator tubes. In its response letter 

dated October 24, 2012, the applicant stated that it revised LRA Table 3.1.2-4 to include an 

AMR item that identifies the Steam Generators Program for verifying the effectiveness of the 

Water Chemistry Program in managing the aging effect of reduction of heat transfer due to 

fouling on the nickel alloy steam generator tube external surfaces in a secondary water 

environment. The applicant stated that LRA Section 3.1.2.1.4, Appendix A1.9, and 

Appendix B2.1.9 were also revised to include an aging effect of reduction of heat transfer. 

Additionally, the applicant stated, in part, that an aging effect of reduction of heat transfer due to 

fouling is not an applicable aging effect for the primary side of the steam generator tubes based 

on the decision of the Steam Generator Task Force (meeting summary, ADAMS Accession 

No. ML110670317, February 18, 2011). The staff’s evaluations of the applicant’s Water 

Chemistry and Steam Generators AMPs are documented in SER Sections 3.0.3.1.2 and 

3.0.3.1.7, respectively. 

The staff noted that the applicant’s revision to LRA Table 3.1.2-4 states that nickel alloy steam 

generator tubes exposed to secondary water will be managed for reduction of heat transfer by 

the Steam Generators and the Water Chemistry AMPs. The revision also cites generic note H 

and plant-specific note 5 for the AMR item, that the reduction in heat transfer due to fouling is a 

potential aging effect/mechanism for steam generator tubes in secondary water, and that the 

GALL Report, Revision 2, does not address the aging effect of reduction in heat transfer for this 

combination of component, material, and environment.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that nickel alloy steam generator tubes exposed to secondary water (external) are 

susceptible to cracking, loss of material, and cumulative fatigue damage, and recommends 

GALL Report AMP XI.M2, Steam Generators, and XI.M19, Water Chemistry, to manage the 

aging effects. The applicant addressed the GALL Report identified aging effects for this 

component, material, and environment combination in other AMR items in LRA Table 3.1.2-4.

The staff reviewed the applicant’s response to RAI 3.1.2.4-1 and finds the applicant’s proposal 

to manage reduction of heat transfer using its Water Chemistry and Steam Generator AMPs 

acceptable because maintaining proper secondary water chemistry will minimize the amount of 

sludge deposits that can lead to a reduction in heat transfer in the steam generators. Periodic 

cleaning of the steam generator secondary side internals, including tubes and tubesheet, will 

also act to remove accumulated deposits from the steam generator, thus ensuring that the heat 

transfer ability of the tubes is not hindered. Additionally, based on the discussion between the 

Steam Generator Task Force and the NRC on February 18, 2011, it was agreed that primary 

side fouling is not an issue in the United States; therefore, a separate AMR line item would not 

be needed for the reduction of heat transfer due to fouling of nickel alloy steam generator tubes 

exposed to primary water. The staff’s concerns with RAI 3.1.2.4-1 are resolved.

Summary. 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

3-328

3.1.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the reactor vessel, RVIs, RCS, pressurizer, and steam generators 

components within the scope of license renewal and subject to an AMR will be adequately 

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

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2 Aging Management of Engineered Safety Features Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the ESF 

systems components and component groups of the following systems:

• containment spray system

• containment integrated leak rate testing system

• containment hydrogen control system

• containment purge system

• high pressure coolant injection (HPCI) system

• RHR system

3.2.1 Summary of Technical Information in the Application

LRA Section 3.2 provides AMR results for the ESF systems components and component 

groups. LRA Table 3.2-1, “Summary of Aging Management Programs in Chapter V of 

NUREG-1801 for Engineered Safety Features,” provides a summary comparison of its AMRs to 

those evaluated in the GALL Report for ESF systems components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

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 if the applicant provided sufficient information 

to demonstrate that the effects of aging for ESF systems components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

function(s) will remain 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 confirm 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 confirm that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. Details of the 

staff’s evaluation are discussed in SER Section 3.2.2.1.
AGING MANAGEMENT REVIEW RESULTS

3-329

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staff’s evaluations 

are documented in SER Section 3.2.2.2.

The staff also 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 that the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR items and the plant’s operating experience to confirm 

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.

The staff’s review of the ESF systems 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 that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.2.2.2, discusses the staff’s 

review of AMR results for components that the applicant indicated are consistent with the GALL 

Report and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.2.2.3, discusses the staff’s review of AMR results for components that the applicant 

indicated are not consistent with or not addressed in the GALL Report. The staff’s review of 

AMPs credited to manage or monitor aging effects of the ESF systems components is 

documented in SER Section 3.0.3.

Table 3.2-1 Staff Evaluation for ESF Systems Components in the GALL Report

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel, Steel 

Piping, piping 

components, and 

piping elements 

exposed to Treated 

water (borated) 

(3.2.1-1)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a 

time-limited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation. See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1)).

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.2.1)

Steel (with stainless 

steel cladding) Pump 

casings exposed to 

Treated water 

(borated) (3.2.1-2)

Loss of material 

caused by 

cladding breach

A plant-specific AMP 

is to be evaluated 

Reference NRC 

Information 

Notice 94-63, “Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.”

Yes Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.2.2) 
AGING MANAGEMENT REVIEW RESULTS

3-330

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

Partially-encased 

tanks with breached 

moisture barrier 

exposed to Raw 

water (3.2.1-3)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

A plant-specific AMP 

is to be evaluated for 

pitting and crevice 

corrosion of tank 

bottom because 

moisture and water 

can egress under the 

tank caused by 

cracking of the 

perimeter seal from 

weathering.

Yes Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.2.3(

1))

Stainless steel Piping, 

piping components, 

and piping elements; 

tanks exposed to Air 

– outdoor (3.2.1-4)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.2.3(

2))

Stainless steel Orifice 

(miniflow 

recirculation) exposed 

to Treated water 

(borated) (3.2.1-5)

Loss of material 

caused by 

erosion

A plant-specific AMP 

is to be evaluated for 

erosion of the orifice 

caused by extended 

use of the centrifugal 

HPSI pump for 

normal charging. 

See LER 

50-275/94-023 for 

evidence of erosion.

Yes Water 

Chemistry and 

One-Time 

Inspection

Not applicable to 

Callaway

(see SER 

Section 3.2.2.2.4)

Steel Drywell and 

suppression chamber 

spray system (internal 

surfaces): flow orifice; 

spray nozzles 

exposed to Air –

indoor, uncontrolled 

(Internal) (3.2.1-6)

Loss of material 

caused by 

general 

corrosion; 

fouling that 

leads to 

corrosion

A plant-specific AMP 

is to be evaluated

Yes Not applicable Not applicable to 

PWRs

(see SER 

Section 3.2.2.2.5)

Stainless steel Piping, 

piping components, 

and piping elements; 

tanks exposed to Air 

– outdoor (3.2.1-7)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External 

Surfaces 

Monitoring of 

Mechanical 

Components 

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.2.6)

Aluminum, 

copper-alloy (>15% 

Zn or >8% Al) piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage (3.2.1-8)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Boric Acid 

Corrosion

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.1.1)

Steel External 

surfaces, Bolting 

exposed to Air with 

borated water 

leakage (3.2.1-9)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Boric Acid 

Corrosion

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-331

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Cast austenitic 

stainless steel Piping, 

piping components, 

and piping elements 

exposed to Treated 

water (borated) 

>250 °C (>482 °F), 

Treated water 

>250 °C (>482 °F) 

(3.2.1-10)

Loss of fracture 

toughness 

caused by 

thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Steel Piping, piping 

components, and 

piping elements 

exposed to Steam, 

Treated water 

(3.2.1-11)

Wall thinning 

caused by 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.2.2.1.1)

Steel, high-strength 

Closure bolting 

exposed to Air with 

steam or water 

leakage (3.2.1-12)

Cracking 

caused by cyclic 

loading, stress 

corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway 

(see SER 

Section 3.2.2.1.1)

Steel; stainless steel 

Bolting, Closure 

bolting exposed to Air 

– outdoor (External), 

Air – indoor, 

uncontrolled 

(External) (3.2.1-13)

Loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting 

Integrity

Consistent with the 

GALL Report

Steel Closure bolting 

exposed to Air with 

steam or water 

leakage (3.2.1-14)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Copper alloy, nickel 

alloy, steel; stainless 

steel, stainless steel, 

steel; stainless steel 

bolting, closure 

bolting exposed to 

any environment, air 

– outdoor (external), 

raw water, treated 

borated water, fuel oil, 

treated water, air –

indoor, uncontrolled 

(external) (3.2.1-15)

Loss of preload 

caused by 

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting 

Integrity

Consistent with the 

GALL Report

Steel Containment 

isolation piping and 

components (Internal 

surfaces), Piping, 

piping components, 

and piping elements 

exposed to Treated 

water (3.2.1-16)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-332

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Aluminum, Stainless 

steel Piping, piping 

components, and 

piping elements 

exposed to Treated 

water (3.2.1-17)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.2.2.1.1)

Stainless steel 

Containment isolation 

piping and 

components (Internal 

surfaces) exposed to 

Treated water 

(3.2.1-18)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel Heat 

exchanger tubes 

exposed to Treated 

water, Treated water 

(borated) (3.2.1-19)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report (see 

SER 

Section 3.2.2.1.1)

Stainless steel Piping, 

piping components, 

and piping elements; 

tanks exposed to 

Treated water 

(borated) >60 °C 

(>140 °F) (3.2.1-20)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

GALL Report 

(see SER 

Section 3.2.2.1.2)

Steel (with stainless 

steel or nickel-alloy 

cladding) Safety 

injection tank 

(accumulator) 

exposed to Treated 

water (borated) 

>60 °C (>140 °F) 

(3.2.1-21)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One–Time 

Inspection”

No Not applicable Not applicable to 

Callway (see SER 

Section 3.2.2.1.1)

Stainless steel Piping, 

piping components, 

and piping elements; 

tanks exposed to 

Treated water 

(borated) (3.2.1-22)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One–Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.1.3)

Steel Heat exchanger 

components, 

Containment isolation 

piping and 

components (Internal 

surfaces) exposed to 

Raw water (3.2.1-23)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

- influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-333

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Raw 

water (3.2.1-24)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1))

Stainless steel Heat 

exchanger 

components, 

Containment isolation 

piping and 

components (Internal 

surfaces) exposed to 

Raw water (3.2.1-25)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER

Section 3.2.2.1.1)

Stainless steel Heat 

exchanger tubes 

exposed to Raw 

water (3.2.1-26)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.2.2.1.1)

Stainless steel, Steel 

Heat exchanger tubes 

exposed to Raw 

water (3.2.1-27)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to 

Closed-cycle cooling 

water >60 °C 

(>140 °F) (3.2.1-28)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to 

Closed-cycle cooling 

water (3.2.1-29)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Steel Heat exchanger 

components exposed 

to Closed-cycle 

cooling water 

(3.2.1-30)

Loss of material 

caused by 

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Stainless steel Heat 

exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to 

Closed-cycle cooling 

water (3.2.1-31)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-334

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-32)

Loss of material 

caused by 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water (3.2.1-33)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Closed Treated 

Water Systems

Consistent with the 

GALL Report

Copper-alloy (>15% 

Zn or >8% Al) piping, 

piping components, 

and piping elements, 

heat exchanger 

components exposed 

to closed-cycle 

cooling water 

(3.2.1-34)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Gray cast iron motor 

cooler exposed to 

treated water 

(3.2.1-35)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Gray cast iron piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-36)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Selective 

Leaching

Consistent with the 

GALL Report

Gray cast iron Piping, 

piping components, 

and piping elements 

exposed to Soil 

(3.2.1-37)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Elastomers Elastomer 

seals and 

components exposed 

to Air – indoor, 

uncontrolled 

(External) (3.2.1-38)

Hardening and 

loss of strength 

caused by 

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

PWRs 

(see SER

Section 3.2.2.1.1)

Steel Containment 

isolation piping and 

components (External 

surfaces) exposed to 

Condensation 

(External) (3.2.1-39)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-335

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel Ducting, piping, 

and components 

(External surfaces), 

Ducting, closure 

bolting, Containment 

isolation piping and 

components (External 

surfaces) exposed to 

Air – indoor, 

uncontrolled 

(External) (3.2.1-40)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Steel External

surfaces exposed to 

Air – outdoor 

(External) (3.2.1-41)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Air –

outdoor (3.2.1-42)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Elastomers Elastomer 

seals and 

components exposed 

to Air – indoor, 

uncontrolled (Internal) 

(3.2.1-43)

Hardening and 

loss of strength 

caused by 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.2.2.1.1)

Steel Piping and 

components (Internal 

surfaces), Ducting 

and components 

(Internal surfaces) 

exposed to Air –

indoor, uncontrolled 

(Internal) (3.2.1-44)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel Encapsulation 

components exposed 

to Air – indoor, 

uncontrolled (Internal) 

(3.2.1-45)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Steel Piping and 

components (Internal 

surfaces) exposed to 

Condensation 

(Internal) (3.2.1-46)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.2.2.1.1)

Steel Encapsulation 

components exposed 

to Air with borated 

water leakage 

(Internal) (3.2.1-47)

Loss of material 

caused by 

general, pitting, 

crevice, and 

boric acid 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-336

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel Piping, 

piping components, 

and piping elements 

(Internal surfaces); 

tanks exposed to 

Condensation 

(Internal) (3.2.1-48)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to 

Lubricating oil 

(3.2.1-49)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper-alloy, 

stainless steel piping, 

piping components, 

and piping elements 

exposed to lubricating 

oil (3.2.1-50)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel, copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to lubricating 

oil (3.2.1-51)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.2.1-52)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway

(see SER 

Section 3.2.2.1.1)

Stainless steel, nickel 

alloy, piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.2.1-53)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report

Steel; stainless steel, 

nickel alloy, 

underground piping, 

piping components, 

and piping elements 

exposed to air-indoor 

uncontrolled or 

condensation 

(external) (3.2.1-53a)

Loss of material 

caused by 

general (steel 

only), pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Stainless steel piping, 

piping components, 

and piping elements 

exposed to treated 

water >60 °C 

(>140 °F) (3.2.1-54)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,” 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.2.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-337

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.2.1-55)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 

2) plant OE indicates 

no degradation of 

the concrete

No, if 

conditions 

are met.

Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(internal/external) 

(3.2.1-56)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external), gas 

(3.2.1-57)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Copper-alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.2.1-58)

None None NA - No 

AEM or 

AMP

None Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Galvanized steel 

Ducting, piping, and 

components exposed 

to Air – indoor, 

controlled (External) 

(3.2.1-59)

None None NA - No 

AEM or 

AMP

None Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-338

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Glass Piping 

elements exposed to 

Air – indoor, 

uncontrolled 

(External), Lubricating 

oil, Raw water, 

Treated water, 

Treated water 

(borated), Air with 

borated water 

leakage, 

Condensation 

(Internal/External), 

Gas, Closed-cycle 

cooling water, Air –

outdoor (3.2.1-60)

None None NA - No 

AEM or 

AMP

None Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Nickel alloy Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(External) (3.2.1-61)

None None NA - No 

AEM or 

AMP

None Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Nickel alloy Piping, 

piping components, 

and piping elements 

exposed to Air with 

borated water 

leakage (3.2.1-62)

None None NA - No 

AEM or 

AMP

None Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)

Stainless steel Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(External), Air with 

borated water 

leakage, Concrete, 

Gas, Air – indoor, 

uncontrolled (Internal) 

(3.2.1-63)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to Air –

indoor, controlled 

(External), Gas 

(3.2.1-64)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Any material piping, 

piping components 

and piping elements 

exposed to treated 

water and treated 

borated water

(3.2.1-65)

Wall thinning 

due to erosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.2.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-339

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

waste water 

(3.2.1-66)

Loss of 

material due to 

recurring 

internal 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated to 

address recurring 

internal corrosion

Yes, 

plantspecific 

Not 

applicable

Not applicable to 

Callaway (see 

SER 

Section 3.2.2.2.9)

Stainless steel or 

aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments 

air-outdoor, 

air-indoor 

uncontrolled, moist 

air, condensation 

(3.2.1-67)

Cracking due 

to stress 

corrosion 

cracking

Aboveground 

Metallic Tanks 

(B2.1.15)

No Not 

applicable

Not applicable to 

Callaway (see 

SER 

Section 3.2.2.1.1)

Metallic piping, piping 

components, heat 

exchangers, tanks 

with Service Level III 

augmented) internal 

coatings exposed to 

closed-cycle cooling 

water, raw water, 

treated water, treated 

borated water, or 

lubricating oil 

(3.2.1-67a)

Loss of 

coating 

integrity due to 

blistering, 

cracking, 

flaking, 

peeling, or 

physical 

damage

Chapter XI.M42, 

“Service Level III 

(augmented) 

Coatings 

Monitoring and 

Maintenance 

Program”

No Not 

applicable

Not applicable to 

Callaway (see 

SER 

Section 3.2.2.1.1)

Steel, stainless 

steel, or aluminum 

tanks (within the 

scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments 

air-outdoor, 

air-indoor 

uncontrolled, moist 

air, condensation 

(3.2.1-68)

Loss of 

material due to 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not 

applicable

Not applicable to 

Callaway (see 

SER 

Section 3.2.2.1.1) 
AGING MANAGEMENT REVIEW RESULTS

3-340

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Insulated steel, 

stainless steel, 

copper alloy, or 

aluminum, piping, 

piping components, 

and tanks exposed 

to condensation, 

air-outdoor 

(3.2.1-69)

Loss of 

material due to 

general (steel, 

and copper 

alloy only), 

pitting, and 

crevice 

corrosion

Chapter XI.M36, 

"External Surfaces 

Monitoring of 

Mechanical 

Components" or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks,” (for 

tanks only)

No External 

Surfaces 

Monitoring of 

Mechanical 

Components 

Consistent with 

the GALL Report 

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water, treated 

borated water 

(3.2.1-70)

Loss of 

material due to 

general (steel 

only), pitting 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic 

Tanks

Consistent with 

the GALL Report 

Insulated stainless 

steel, aluminum, or 

copper alloy 

(>15% Zn) piping, 

piping components, 

and tanks exposed 

to condensation, 

air-outdoor 

(3.2.1-71)

Cracking due 

to stress 

corrosion 

cracking

Chapter XI.M36, 

"External Surfaces 

Monitoring of 

Mechanical 

Components" or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks,” (for 

tanks only)

No External 

Surfaces 

Monitoring of 

Mechanical 

Components 

or 

Aboveground 

Metallic 

Tanks

Consistent with 

the GALL Report

3.2.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the ESF systems components:

• Aboveground Metallic Tanks

• ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

• Bolting Integrity

• Boric Acid Corrosion (B2.1.4)

• Buried and Underground Piping and Tanks

• Closed Treated Water Systems

• External Surfaces Monitoring of Mechanical Components

• Flow-Accelerated Corrosion

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Lubricating Oil Analysis

• One-Time Inspection

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping

• Selective Leaching

• Water Chemistry
AGING MANAGEMENT REVIEW RESULTS

3-341

LRA Tables 3.2.2-1 through 3.2.2-6 summarize AMRs for the ESFs components and indicate 

AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the GALL Report and for which it does not recommend further evaluation, the 

staff’s audit and review determined if the plant-specific components of these GALL Report 

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with notes A–E, indicating how 

the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these items to confirm consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff audited these items to confirm consistency with the GALL Report and confirmed 

that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. 

The staff also determined whether the applicant’s AMP was consistent with the GALL Report 

AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL Report AMP. This note indicates that the applicant was unable to find 

a listing of some system components in the GALL Report; however, the applicant identified in 

the GALL Report a different component with the same material, environment, aging effect, and 

AMP as the component under review. The staff audited these items to confirm consistency with 

the GALL Report. The staff also determined whether the AMR item of the different component 

was applicable to the component under review and whether the AMR was valid for the 

site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL Report AMP. The staff audited these AMR items to confirm 

consistency with the GALL Report. The staff confirmed whether the AMR item of the different 

component was applicable to the component under review and whether the identified 

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also 

determined whether the applicant’s AMP was consistent with the GALL Report AMP and 

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect but credits a different AMP. The staff audited these items to 

confirm 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 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 confirm that the material 
AGING MANAGEMENT REVIEW RESULTS

3-342

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation is discussed below.

3.2.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.2-1, items 3.2.1-17, 3.2.1-26, 3.2.1-38, 3.2.1-43, 3.2.1-46, and 3.2.1-54, the 

applicant claimed that the corresponding AMR items in the GALL Report are not applicable 

because the associated items are only applicable to BWRs. The staff reviewed the SRP-LR, 

confirmed these items only apply to BWRs, and finds that these items are not applicable to 

Callaway, which is a PWR.

For LRA Table 3.2-1, items 3.2.1-10, 3.2.1-11, 3.2.1-12, 3.2.1-14, 3.2.1-16, 3.2.1-21, 3.2.1-23, 

3.2.1-24, 3.2.1-25, 3.2.1-27, 3.2.1-34, 3.2.1-35, 3.2.1-37, 3.2.1-39, 3.2.1-42, 3.2.1-45, 3.2.1-53a, 

3.2.1-55, 3.2.1-67, 3.2.1-67a, and 3.2.1-68, the applicant claimed that the corresponding items 

in the GALL Report are not applicable because the component, material, and environment 

combination described in the SRP-LR does not exist for in-scope SCs at Callaway. The staff 

reviewed the LRA and FSAR and confirmed that the applicant’s LRA does not have any AMR 

results applicable for these items.

For LRA Table 3.2-1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable; however, the staff non-applicability verification of 

these items required the review of sources beyond the LRA and FSAR, and/or the issuance of 

RAIs.

LRA Table 3.2-1, item 3.2.1-8 addresses aluminum and copper-alloy (greater than 15 percent 

zinc or greater than 8 percent aluminum) piping, piping components, and piping elements 

exposed to air with borated water leakage. The GALL Report recommends GALL Report 

AMP XI.M10, “Boric Acid Corrosion,” to manage loss of material caused by boric acid corrosion 

for this component group. In the original LRA, the applicant stated that this item was not 

applicable; however, in LRA Amendment No. 1 dated April 25, 2012, the applicant revised the 

LRA to state that the item was applicable and consistent with the GALL Report guidance. The 

applicant also added AMR items that reference LRA item 3.2.1-8. The staff reviewed the 

associated AMR items, which cite generic notes A or C, and confirmed the applicant’s claim of 

consistency with the GALL Report.

LRA Table 3.2-1, item 3.2.1-14 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity” to 

manage loss of material caused by general corrosion for this component group. The applicant 

stated that this item is not applicable because closure bolting was evaluated using the plant 

indoor air environment and SRP-LR Table 3.2-1, item 3.2.1-13 for steel closure bolting exposed 

to an air-indoor uncontrolled environment. The staff evaluated the applicant’s claim and finds it 

acceptable because the component group is being managed for loss of material by the Bolting 

Integrity Program, consistent with the GALL Report recommendations.

LRA Table 3.2-1, item 3.2.1-16 addresses steel containment isolation piping and components 

(internal surfaces), piping, piping components, and piping elements exposed to treated water. 

The GALL Report recommends GALL Report AMP XI.M2, “Water Chemistry,” and XI.M32, 

“One-Time Inspection,” to manage loss of material caused by general, pitting, and crevice 

corrosion for this component group. The applicant stated that this item is not applicable 

because the containment isolation components were evaluated in the systems in which the 

components were found to have the function of containment integrity. The staff evaluated the 

applicant’s claim and finds it acceptable because the applicant has evaluated steel containment 
AGING MANAGEMENT REVIEW RESULTS

3-343

isolation components with LRA items 3.4.1-13 and 3.4.1-14 and is managing loss of material 

caused by general, pitting, and crevice corrosion for the subject components with the Water 

Chemistry and One-Time Inspection Programs, consistent with the GALL Report guidance for 

LRA item 3.2.1-16.

LRA Table 3.2-1, item 3.2.1-19 addresses stainless steel heat exchanger tubes exposed to 

treated water, or treated water (borated). The GALL Report recommends AMP XI.M2, “Water 

Chemistry,” and AMP XI.M32, “One-Time Inspection,” to manage reduction of heat transfer 

caused by fouling for this component group. The applicant stated that this item is not applicable 

because Callaway has no in-scope stainless steel heat exchanger tubes exposed to treated 

water in the containment spray system. In its review of the applicant’s claim, the staff noted that 

although Callaway’s containment spray system does not have stainless steel heat exchanger 

tubes exposed to treated water, this component type with an intended function of heat transfer 

can be found in the RHR system. The staff noted that LR-ISG-2011-01, “Aging Management of 

Stainless Steel Structures and Components in Treated Borated Water,” discusses the 

applicability of reduction of heat transfer for components in both treated water and treated 

borated water. Therefore, the staff required additional information to ensure that the aging 

effects for this component group were being adequately managed. By letter dated 

August 16, 2012, the staff issued RAI 3.2.1.19-2 requesting the applicant to justify the 

non-applicability of this item. In its response dated September 20, 2012, the applicant added 

item 3.2.1.019 to LRA Table 3.2.2-6 reflecting reduction of heat transfer as an aging effect for 

the stainless steel heat exchanger tubes in the RHR heat exchangers and the RHR pump seal 

water coolers. The applicant also revised LRA Table 3.2-1, item 19, as being consistent with 

the GALL Report. In a letter dated December 19, 2012, the applicant also added reduction of 

heat transfer as an aging effect for the stainless steel reactor coolant pump thermal barrier 

cooler in LRA Table 3.1.2-2. The staff finds the applicant’s response acceptable because, 

consistent with SRP-LR A.1.2.1, the applicant’s determination of applicable aging effects is now 

based on those aging effects that potentially could cause component degradation. The staff 

notes that the applicant’s use of the Water Chemistry and One-Time Inspection Programs to 

manage reduction of heat transfer in the heat exchanger tubes exposed to treated borated 

water for item 3.2.1-19 is consistent with the GALL Report. The staff’s concern described in 

RAI 3.2.1.19-2 is resolved.

LRA Table 3.2-1, item 3.2.1-38 addresses elastomer seals and components externally exposed 

to indoor uncontrolled air. The GALL Report recommends GALL Report AMP XI.M36, “External

Surfaces Monitoring of Mechanical Components,” to manage hardening and loss of strength 

caused by elastomer degradation for this component group. The applicant stated that this item 

is not applicable because it only applies to BWR plants. The staff finds that the applicant’s 

claim acceptable because SRP-LR item 3.2.1-38, which cites GALL Report item V.B.EP-59, is 

only associated with BWR standby gas treatment systems. The staff confirmed that the 

applicant is appropriately managing hardening and loss of strength caused by elastomer 

degradation because the applicant cited item 3.3.1-76 to manage the aging of the flexible 

connectors in the ESF systems. Both item 3.2.1-38 and 3.3.1-76 state the same material, 

components, environment, AERM, and AMP.

LRA Table 3.2-1, item 3.2.1-43 addresses elastomer seals and components exposed to internal 

indoor uncontrolled air. The GALL Report recommends GALL Report AMP XI.M38, “Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to manage hardening 

and loss of strength caused by elastomer degradation for this component group. The applicant 

stated that this item is not applicable because it only applies to BWR plants. The staff finds that 

the applicant’s claim acceptable because SRP-LR item 3.2.1-43, which cites GALL Report 
AGING MANAGEMENT REVIEW RESULTS

3-344

item V.B.EP-58, is only associated with BWR standby gas treatment systems. The staff 

confirmed that the applicant is appropriately managing hardening and loss of strength caused 

by elastomer degradation because the only applicable in-scope components in the ESF 

systems are flexible connectors which cite item 3.3.1-76 and use the External Surfaces 

Monitoring of Mechanical Components Program to manage hardening and loss of strength. The 

staff noted that the “scope of program” program element of AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” allows for the inspection of internal surfaces of 

polymeric components when the external and internal surfaces are in the same environment 

such that the external condition of the component would be representative of the internal 

surfaces. The applicant’s External Surfaces Monitoring of Mechanical Components Program 

states that it inspects for “hardening/loss of strength as evidenced by loss of suppleness during 

manual or physical manipulation.” The staff also noted that the plant indoor air environment 

(external surface) and ventilation atmosphere environment (internal) are sufficiently similar in 

temperature such that the external surfaces would be representative of the internal surfaces.

LRA Table 3.2-1, item 3.2.1-52 addresses steel (with coating or wrapping) piping, piping 

components, and piping elements exposed to soil or concrete. The SRP-LR recommends 

GALL Report AMP XI.M41 “Buried and Underground Piping and Tanks” to manage loss of 

material caused by general, pitting, crevice, and MIC for this component group. The applicant 

stated that this item is not applicable because the item is only applicable to BWR plants. The 

staff noted that SRP-LR, item 3.2.1-52 is applicable to both PWR and BWR plants. While the 

staff does not agree with the applicant’s basis for disposition of this item as being not applicable 

to PWRs, the staff did a search of the FSAR and the piping and instrument drawings submitted 

with the LRA for steel (with coatings or wrappings) piping, piping components, and piping 

elements exposed to soil or concrete and based on its review the staff confirmed that this 

material and environment combination does not exist in the engineered safety features systems. 

The staff finds it acceptable that the applicant is not using this AMR item because, based on a 

review of the LRA and FSAR, there are no in-scope steel piping, piping components, and piping 

elements exposed to soil or concrete in the engineered safety features systems.

LRA Table 3.2-1, item 3.2.1-58 addresses copper-alloy (less than or equal to 15 percent zinc 

and less than or equal to 8 percent aluminum) piping, piping components, and piping elements 

exposed to air with borated water leakage. The applicant stated that this item is not applicable 

because there are no in-scope components associated with this item and that there are no 

aging effects, aging mechanisms or AMPs for this component group. SRP-LR item 3.2.1-58 

recommends that there is no aging effect or aging mechanism and that no AMP is 

recommended for this component group exposed to this environment and therefore, the staff 

finds the applicant’s determination acceptable.

LRA Table 3.2-1, item 3.2.1-59 addresses galvanized steel ducting, piping, and components 

exposed to air-indoor, controlled (external) and states that there are no aging effects, aging 

mechanisms, or AMPs. The applicant stated that the item is not applicable because there are 

no in-scope components associated with this item. SRP-LR item 3.2.1-59 states that there is no 

aging effect or aging mechanism and that no AMP is recommended for this component group 

exposed to this environment; therefore, the staff finds the applicant’s determination acceptable.

LRA Table 3.2-1, item 3.2.1-60 addresses glass piping elements exposed to uncontrolled indoor 

air, lubricating oil, raw water, treated water, treated borated water, air with borated water 

leakage, condensation, gas, closed-cycle cooling water, and outdoor air. The applicant stated 

that the item is not applicable because there are no in-scope components associated with this 

item. SRP-LR item 3.2.1-60 states that there is no aging effect or aging mechanism and that no 
AGING MANAGEMENT REVIEW RESULTS

3-345

AMP is recommended for this component group exposed to these environments; therefore, the 

staff finds the applicant’s determination acceptable.

LRA Table 3.2-1, items 3.2.1-61 and 3.2.1-62, address nickel alloy piping, piping components, 

and piping elements exposed to (respectively) air-indoor, uncontrolled (external) and air with 

borated water leakage. The applicant stated that these items are not applicable because there 

are no in-scope components associated with them. SRP-LR items 3.2.1-61 and 3.2.1-62 both 

state that there are no respective aging effects or aging mechanisms and that no AMP is 

recommended for this component group exposed to these environments; therefore, the staff 

finds the applicant’s determination acceptable.

LRA Table 3.2-1, item 3.2.1-65, addresses piping, piping component and piping elements made 

from any material exposed to treated water and treated borated water. The GALL Report 

recommends GALL Report AMP XI.M17, “Flow-Accelerated Corrosion,” to manage wall thinning 

due to erosion for this component group. The applicant stated that this item is not applicable 

because it has not experienced this aging effect in any ESF systems. The staff noted that 

item 3.2.1-65 was generated as part of LR-ISG-2012-01, “Wall Thinning Due to Erosion 

Mechanisms,” which applies to management of erosion mechanisms that have been identified 

but where the underlying design issue has not been corrected. The staff evaluated the 

applicant’s claim and finds it acceptable because, during its independent review of the 

applicant’s operating experience database, the staff did not identify any issues with wall thinning 

due to erosion in any ESF systems at Callaway Unit 1.

3.2.2.1.2 Cracking Due to Stress Corrosion Cracking

LRA Table 3.2-1, item 3.2.1-20 addresses stainless steel pumps, pipes, pipe elements, tanks, 

and heat exchangers exposed to treated borated water which will be managed for cracking due 

to SCC. For the AMR items that cite generic note E, the LRA credits the Water Chemistry and 

One-Time Inspection Programs to manage the aging effect for these components with this 

material and environment combination.

The GALL Report as revised by LR-ISG-2011-01, Revision 1, “Aging Management of Stainless 

Steel Structures and Components in Treated Borated Water,” recommends GALL Report AMP 

XI.M2, “Water Chemistry,” and XI.M32, “One-Time Inspection” Programs to ensure that these 

aging effects are adequately managed. By letter dated December 19, 2012, the applicant 

revised the subject AMR items to cite generic notes A or C to reflect the LRA consistency with 

the revised GALL Report guidance. The staff confirmed the consistency with the GALL Report 

and, therefore, finds the applicant’s proposal to manage aging acceptable. 

The staff concludes that for LRA item 3.2.1-20, 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 and Crevice Corrosion

LRA Table 3.2-1, item 3.2.1-22 addresses stainless steel piping, piping components, piping 

elements, and tanks exposed to treated borated water, which will be managed for loss of 

material due to pitting and crevice corrosion. For the AMR items that cite generic note E, the 

LRA credits the Water Chemistry and One-Time Inspection Programs to manage the aging 

effect for stainless steel piping, piping components, piping elements, tanks, and heat exchanger 

components. The GALL Report, as revised by LR-ISG-2011-01, Revision 1, “Aging 
AGING MANAGEMENT REVIEW RESULTS

3-346

Management of Stainless Steel Structures and Components in Treated Borated Water,” 

recommends GALL Report AMPs XI.M2, “Water Chemistry,” and XI.M32, “One-Time 

Inspection,” to ensure that these aging effects are adequately managed. By letter dated 

December 19, 2012, the applicant revised the subject AMR items to cite generic notes A or C to 

reflect the LRA consistency with the revised GALL Report guidance. The staff confirmed the 

consistency with the GALL Report and, therefore, finds the applicant’s proposal to manage 

aging acceptable.

The staff concludes that for LRA item 3.2.1-22, 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 No Aging Effects Requiring Management

LRA Table 3.2-1, item 3.2.1-63 addresses stainless steel piping, piping components, and piping 

elements exposed to air-indoor uncontrolled, air with borated water leakage, concrete, or gas 

and states that there are no AERM and no AMP is proposed. The GALL Report states that

there are no AERM and no AMP is proposed for this component group. 

During its review of components associated with item 3.2.1-63, for which the applicant cited 

generic notes A or C, the staff noted that the LRA states that there are no AERM and no AMP is 

proposed for stainless steel expansion joints, piping, and tanks exposed internally to borated 

water leakage in LRA Table 3.2.2-6. However, the GALL Report environment of air with borated 

water leakage is usually referred to as an external environment. The GALL Report 

recommends that stainless steel components exposed to treated borated water or condensation 

be managed for loss of material. It was unclear to the staff how the components exposed 

internally to borated water leakage are configured such that exposure to borated water leakage 

can occur, but the leakage does not accumulate such that the environment becomes borated 

water or condensation. By letter dated August 16, 2012, the staff issued RAI 3.2.1.063-1 

requesting that the applicant explain the configuration of the components exposed internally to 

borated water leakage and how accumulation of the borated water leakage is prevented. If 

accumulation of borated water leakage can occur, the staff also requested the applicant to 

explain why the components have no AERM.

In its response dated September 20, 2012, the applicant stated that the components are 

associated with the RHR lines between the containment sump and the pump suction. The 

applicant stated that subject components are in a watertight enclosure outside the containment 

building that houses the system isolation valves and that the enclosure was identified as a tank 

in the LRA and includes expansion joints and guard pipes. The applicant also stated that the 

borated water leakage environment was selected because the RHR lines are internally partially 

filled with borated water. The applicant further stated that the domes on the enclosure are 

periodically removed for testing of the isolation valves and visual inspection of the enclosure. In 

addition, the applicant stated that if any signs of borated water leakage are observed, corrective 

action is taken in accordance with its CAP and Boric Acid Corrosion Program; therefore, 

preventing accumulation of borated water in the enclosure. 

The staff finds the applicant’s response acceptable because the stainless steel components are 

located within an enclosure in which borated water leakage is not expected, which is an 

environment similar to being externally exposed to borated water leakage, and the components 
AGING MANAGEMENT REVIEW RESULTS

3-347

are managed such that accumulation of borated water leakage would not occur. The staff’s 

concern described in RAI 3.2.1.063-1 is resolved.

The staff concludes that for LRA item 3.2.1-63, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.2.2.1.5 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3-1, item 3.3.1-79 addresses copper-alloy piping, piping components, and piping 

elements exposed to condensation (external) which will be managed for loss of material due to 

general, pitting, and crevice corrosion. For the AMR items that cite generic note E in LRA 

Table 3.2.2-4, the LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program to manage the aging effect for heat exchanger components 

exposed externally to a ventilation atmosphere. The AMR item also cites a plant-specific note 

that states the subject components are enclosed within another component. The GALL Report 

recommends GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” to ensure that these aging effects are adequately managed. GALL Report AMP 

XI.M36 recommends using periodic visual inspections of the external surfaces of components to 

manage aging for metallic components. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program proposes to manage the aging of metallic components through the use of visual 

inspections. In its review of components associated with item 3.3.1-79, for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable because the program includes visual inspections of components which are capable 

of detecting loss of material and the subject components are located inside other components. 

The staff concludes that for LRA item 3.3.1-79, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended

In LRA Section 3.2.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the ESF components and provides information concerning how it will 

manage the following aging effects:

• cumulative fatigue damage

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• loss of material due to erosion

• loss of material due to general corrosion and fouling that leads to corrosion 

• cracking due to SCC

• QA for aging management of nonsafety-related components
AGING MANAGEMENT REVIEW RESULTS

3-348

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 it 

adequately addressed the issues further evaluated. In addition, the staff reviewed the 

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.2.2.2. The 

staff’s review of the applicant’s further evaluation follows.

3.2.2.2.1 Cumulative Fatigue Damage

LRA Section 3.2.2.2.1, associated with LRA Table 3.2-1, item 3.2.1-1, addresses steel and 

stainless steel piping, piping components, and piping elements in the engineered-safety 

systems and being managed for cumulative fatigue damage. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that fatigue is a TLAA, as defined in 

10 CFR 54.3, and is required to be evaluated in accordance with 10 CFR 54.21(c). The 

applicant stated that its evaluation of the TLAA is addressed separately in LRA Section 4.3. 

The staff reviewed LRA Section 3.2.2.2.1 against the criteria in SRP-LR Section 3.2.2.2.1 which 

states that cumulative fatigue damage of steel and stainless steel piping, piping components, 

and piping elements in the emergency core cooling (ECC) systems is a TLAA, and that these 

TLAAs are to be evaluated in accordance with the TLAA acceptance criteria requirements of 

10 CFR 54.21(c). The staff reviewed the applicant’s AMR items and determined that the AMR 

results are consistent with the recommendations of the GALL Report and SRP-LR, for 

managing cumulative fatigue damage in steel and stainless steel piping, piping components, 

and piping elements.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.2.2.2.1 criteria. For those items that apply to LRA Section 3.2.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components.

3.2.2.2.2 Loss of Material Due to Cladding Breach

LRA Section 3.2.2.2.2, associated with LRA Table 3.2-1, item 3.2.1-2, addresses loss of 

material due to cladding breach in steel with stainless steel cladding pump casings exposed to 

treated borated water. The applicant stated that this item is not applicable because there are no 

in-scope steel with stainless steel cladding pump casings exposed to treated borated water in 

the ECC system. The staff reviewed LRA Sections 2.3.2 and 3.2, and FSAR Section 6.0 SP, 

Table 6.1-1 and finds that no in-scope steel with stainless steel cladding pump casings exposed 

to treated borated water are present in the ESF systems.

3.2.2.2.3 Loss of Material due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP-LR 

Section 3.2.2.2.3:

(1) LRA Section 3.2.2.2.3.1, associated with LRA Table 3.2-1, item 3.2.1-3, addresses loss 

of material due to pitting and crevice corrosion in stainless steel, partially-encased tanks 

with breached moisture barrier exposed to raw water. The applicant stated that this item 

is not applicable because it has no in-scope stainless steel tanks exposed to raw water 
AGING MANAGEMENT REVIEW RESULTS

3-349

in the ECC system. The staff reviewed LRA Sections 2.3.2 and 3.2, and the FSAR and 

finds that no in-scope stainless steel, partially-encased tanks with breached moisture 

barrier exposed to raw water are present in the ESF systems.

(2) LRA Section 3.2.2.2.3.2, associated with LRA Table 3.2-1, item 3.2.1-4, and as 

amended by letter dated December 20, 2013, addresses stainless steel piping, piping 

components, and piping elements exposed to outdoor air, which will be managed for 

loss of material by the External Surfaces Monitoring of Mechanical Components 

Program. The criteria in SRP-LR Section 3.2.2.2.3, item 2, 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 outdoor air. The SRP-LR also 

states that GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” is an acceptable method to manage this aging effect. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the External 

Surfaces Monitoring of Mechanical Components Program manages loss of material from 

pitting and crevice corrosion for stainless steel external surfaces exposed to the outdoor 

air environment. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components Program is documented in SER Section 3.0.3.1.10. In its review of 

components associated with item 3.2.1-4 for which the applicant credited the External 

Surfaces Monitoring of Mechanical Components Program to manage aging, the staff 

finds that the applicant has met the further evaluation criteria, and the applicant’s 

proposal to manage aging using the External Surfaces Monitoring of Mechanical 

Components Program is acceptable because: (a) the program includes periodic visual 

inspections that will occur at least every RFO, which are capable of detecting loss of 

material; and (b) the inspection technique and frequency are consistent with the GALL 

Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.3, item 2 criteria. For those items associated with LRA 

Section 3.2.2.2.3.2, the staff determined that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.2.4 Loss of Material Due to Erosion

LRA Section 3.2.2.2.4, associated with LRA Table 3.2-1, item 3.2.1-5, addresses stainless steel 

minimum flow orifices exposed to treated borated water, which will be managed for loss of 

material due to erosion by the Water Chemistry and One-Time Inspection Programs. The 

criterion in SRP-LR Section 3.2.2.2.4 states that a plant-specific AMP should be evaluated for 

erosion of the orifice caused by extended use of the centrifugal high-pressure safety injection 

pump for normal charging. The staff noted that the erosion issue was based on the length of 

time that the orifice experiences flow and was not based on any chemistry control concern. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that the AMPs used 

to manage the aging include the Water Chemistry and One-Time Inspection Programs.

In its review of components associated with item 3.2.1-5, the staff noted that the GALL Report 

credits AMP XI.M2 “Water Chemistry,” for managing loss of material due to corrosion in 

stainless steel components exposed to treated borated water. However, the GALL Report does 

not credit AMP XI.M2 for managing loss of material due to erosion, and consequently, it was not 

clear to the staff how the combination of the Water Chemistry and One-Time Inspection 
AGING MANAGEMENT REVIEW RESULTS

3-350

Programs could effectively manage this aging effect for the minimum flow orifice. Therefore, by 

letter dated August 6, 2012, the staff issued RAI 3.2.2.2.4-1 requesting the applicant to clarify 

how the Water Chemistry and One-Time Inspection Programs manage loss of material caused 

by erosion of the minimum flow orifice in the high pressure safety injection system. 

In its response dated September 6, 2012, the applicant stated that erosion is not an applicable 

aging effect for the associated minimum flow orifices because the centrifugal high pressure 

charging pumps are not used for normal charging at Callaway. The applicant also stated that 

normal charging is provided by the normal charging pump and that check valves in the system 

prevent normal charging flow from going through the high pressure safety injection pump 

minimum flow recirculation orifices. Based on this information, the applicant revised LRA 

Section 3.2.2.2.4 and Table 3.2-1, item 3.2.1-5 to state that erosion of the minimum flow orifices 

for the high pressure safety injection pumps is not applicable to Callaway. The staff finds the 

applicant’s response acceptable because it provided sufficient bases to conclude that the aging 

effect addressed by this further evaluation item does not apply to Callaway. The staff’s concern 

described in RAI 3.2.2.2.4-1 is resolved.

3.2.2.2.5 Loss of Material Due to General Corrosion and Fouling that Leads to Corrosion

LRA Section 3.2.2.2.5, associated with LRA Table 3.2-1, item 3.2.1-6, addresses loss of 

material due to general corrosion and fouling that leads to corrosion in steel drywell and 

suppression chamber spray system nozzle and flow orifice internal surfaces exposed to 

air-indoor uncontrolled. The applicant stated that this item is not applicable because loss of 

material for these BWR components is only applicable to BWR plants. The staff noted that this 

item is associated only with BWRs and, therefore, finds the applicant’s claim acceptable.

3.2.2.2.6 Cracking Due to Stress Corrosion Cracking

LRA Section 3.2.2.2.6, associated with LRA Table 3.2-1, item 3.2.1-7, and as amended by letter 

dated December 20, 2013, addresses stainless steel piping, piping components, and piping

elements exposed to outdoor air, which will be managed for SCC by the External Surfaces 

Monitoring of Mechanical Components Program. The criteria in SRP-LR Section 3.2.2.2.6 

states that SCC could occur for stainless steel piping, piping components, piping elements, and 

tanks exposed to outdoor air. The SRP-LR also states that GALL Report AMP XI.M36, 

“External Surfaces Monitoring of Mechanical Components,” is an acceptable method to manage 

this aging effect. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the External Surfaces Monitoring of Mechanical Components Program manages 

SCC for stainless steel external surfaces exposed to outdoor environment. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components Program is documented in SER Section 3.0.3.1.10. In its review of components 

associated with item 3.2.1-7 for which the applicant credited the External Surfaces Monitoring of 

Mechanical Components Program to manage aging, the staff finds that the applicant has met 

the further evaluation criteria, and the applicant’s proposal is acceptable because: (a) the 

program includes periodic visual inspections that will occur at least every RFO, which are 

capable of detecting SCC; and (b) the inspection technique and frequency are consistent with 

the GALL Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.6 criteria. For those items associated with LRA Section 3.2.2.2.6, the 

staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
AGING MANAGEMENT REVIEW RESULTS

3-351

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.2.2.2.7 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA Program.

3.2.2.2.8 Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of aging management 

programs.

3.2.2.2.9 Loss of Material due to Recurring Internal Corrosion

LRA Section 3.2.2.2.9, as modified through LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation,” is 

associated with LRA Table 3.2-1, item 3.2.1-66, and addresses loss of material due to recurring 

internal corrosion in metallic piping, piping components, and tanks exposed to raw water or 

waste water. By letter dated October 7, 2013, the staff issued RAI 3.0.3-1 requesting the 

applicant to address issues related to recurring internal corrosion that are addressed by the new 

SRP-LR Section 3.2.2.2.9. In its response dated December 20, 2013, the applicant stated that 

this item is not applicable because operating experience associated with ESF systems does not 

meet the threshold for significance or frequency of occurrence of the aging effect to be 

considered as recurring internal corrosion.

The staff evaluated the applicant’s claim and finds it acceptable because the applicant’s reviews 

of past operating experience did not identify instances of recurring internal corrosion in ESF 

systems. The staff notes that its independent search of plant-specific operating experience 

during the AMP audit did not identify instances that warranted augmenting any AMPs that

manage components in ESF systems to address internal corrosion.

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.2.2-1 through 3.2.2-6, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.2.2-1 through 3.2.2-6, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an 

AMR item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the AMR item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the AMR 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 
AGING MANAGEMENT REVIEW RESULTS

3-352

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. 

The staff’s evaluation is discussed in the following sections.

3.2.2.3.1 Engineered Safety Features—Summary of Aging Management Evaluation—

Containment Spray System—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 spray system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the containment spray system component groups are consistent 

with the GALL Report.

3.2.2.3.2 Engineered Safety Features—Summary of Aging Management Evaluation—

Containment Integrated Leak Rate Testing System—LRA Table 3.2.2-2

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the 

containment integrated leak rate testing system component groups. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the containment integrated leak rate testing system 

component groups are consistent with the GALL Report.

3.2.2.3.3 Engineered Safety Features—Summary of Aging Management Evaluation—

Containment Hydrogen Control System—LRA Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the 

containment hydrogen control system component groups.

Stainless Steel Piping Exposed to Plant Indoor Air. In LRA Table 3.2.2-3, the applicant stated 

there is a TLAA for stainless steel piping exposed to plant indoor air which cite generic note H. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.5, for this 

component and material. The staff’s evaluation of the fatigue TLAA for ANSI B31.1 and ASME 

Code Section III Class 2 and 3 piping is documented in SER Section 4.3.5.2.

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).

3.2.2.3.4 Engineered Safety Features—Summary of Aging Management Evaluation—

Containment Purge System—LRA Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the 

containment purge system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the containment purge system component groups are consistent 

with the GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-353

3.2.2.3.5 Engineered Safety Features—Summary of Aging Management Evaluation—High 

Pressure Coolant Injection System—LRA Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the 

high pressure coolant injection system component groups. The staff’s review did not identify 

any AMR items with notes F through J, indicating that the combinations of component type, 

material, environment, and AERM for the high pressure coolant injection system component 

groups are consistent with the GALL Report.

3.2.2.3.6 Engineered Safety Features—Summary of Aging Management Evaluation—Residual 

Heat Removal System—LRA Table 3.2.2-6

The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the 

RHR system component groups.

Stainless Steel Heat Exchangers Exposed to Treated Borated Water and Carbon Steel Heat 

Exchangers Exposed to Closed Cycle Cooling Water. In LRA Table 3.2.2-6, the applicant 

stated there is a TLAA for stainless steel heat exchangers exposed to treated borated water and 

carbon steel heat exchangers exposed to closed cycle cooling water which cite generic note H. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.8, for this 

component and material. The staff’s evaluation of the fatigue TLAA for ASME Code Class 2 

heat exchangers is documented in SER Section 4.3.8.2.

Calcium Silicate Insulation Exposed to Plant Indoor Air. In LRA Table 3.2.2-6, as amended by 

letter dated December 19, 2012, the applicant stated that for calcium silicate insulation exposed 

to plant indoor air, there is no aging effect and no AMP is proposed. The AMR item cited

generic note J, indicating that neither the component nor the material and environment are 

evaluated in the GALL Report.

The staff noted that, subsequent to the applicant’s December 19, 2012, LRA amendment, 

License Renewal Interim Staff Guidance (LR-ISG) LR-ISG-2012-02, “Aging Management of 

Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under 

Insulation,” was issued, adding SRP-LR item 3.4.1-64 to manage reduced thermal insulation 

resistance for calcium silicate insulation exposed to plant air using GALL Report AMP XI.M36, 

“External Surfaces Monitoring of Mechanical Components.” In LRA Amendment 28, dated 

December 20, 2013, the applicant revised this item to manage reduced thermal insulation 

resistance with the External Surfaces Monitoring of Mechanical Components Program, 

consistent with LR-ISG-2012-02. Therefore, the staff finds the applicant’s proposal to manage 

aging 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 as discussed here. The staff 

finds that the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB for the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

3.2.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the ESF system components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended function(s) will be 
AGING MANAGEMENT REVIEW RESULTS

3-354

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

auxiliary systems components and component groups of the following systems:

• fuel storage and handling system

• fuel pool cooling and cleanup system

• cranes, hoists, and elevators

• ESW system

• service water system

• reactor makeup water system

• component cooling water (CCW) system

• compressed air system

• nuclear sampling system

• CVC system

• control building HVAC system 

• ESW pumphouse HVAC system 

• auxiliary building HVAC system 

• fuel building HVAC system 

• miscellaneous buildings HVAC system 

• diesel generator building HVAC system 

• turbine building HVAC system 

• containment cooling system 

• fire protection system 

• emergency diesel engine fuel oil storage and transfer system 

• standby diesel generator engine system 

• EOF and TSC diesels, security building system 

• liquid radwaste system

• decontamination system

• oily waste system

• floor and equipment drainage system

• miscellaneous systems in scope ONLY for Criterion 10 CFR 54.4(a)(2)

• circulating water 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 Programs in Chapter VII of 

NUREG-1801 for 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 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.
AGING MANAGEMENT REVIEW RESULTS

3-355

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine if the applicant provided sufficient information 

to demonstrate that the effects of aging for auxiliary systems components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

function(s) will remain 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 confirm 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 confirm that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. Details of the 

staff’s evaluation are discussed in SER Section 3.3.2.1.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staff’s evaluations are 

documented in SER Section 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 that the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR items and the plant’s operating experience to confirm 

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.

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 that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.3.2.2, discusses the staff’s 

review of AMR results for components that the applicant indicated are consistent with the GALL 

Report and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.3.2.3, discusses the staff’s review of AMR results for components that the applicant 

indicated are not consistent with or not addressed in the GALL Report. The staff’s review of 

AMPs credited to manage or monitor aging effects of the auxiliary systems components is 

documented in SER Section 3.0.3.
AGING MANAGEMENT REVIEW RESULTS

3-356

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

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel Cranes: 

structural girders 

exposed to Air –

indoor, uncontrolled 

(External) (3.3.1-1)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a time-limited 

aging analysis (TLAA) 

to be evaluated for the 

period of extended 

operation for structural 

girders of cranes that 

fall within the scope of 

10 CFR 54 (see SRP, 

Section 4.7, “Other 

Plant-Specific TLAAs,” 

for acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.1)

Stainless steel, Steel 

Heat exchanger 

components and 

tubes, Piping, piping 

components, and 

piping elements 

exposed to Treated 

borated water, 

Air - indoor, 

uncontrolled, 

Treated water 

(3.3.1-2)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a time-limited 

aging analysis (TLAA) 

to be evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for acceptable 

methods for meeting the 

requirements of 

10 CFR 54.21(c)(1)).

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.1)

Stainless steel Heat 

exchanger 

components, 

non-regenerative 

exposed to Treated 

borated water 

>60 °C (>140 °F) 

(3.3.1-3)

Cracking 

caused by 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M2, “Water 

Chemistry” The AMP is 

to be augmented by 

confirming the absence 

of cracking caused by 

stress corrosion 

cracking and cyclic 

loading. An acceptable 

verification program is 

to include temperature 

and radioactivity 

monitoring of the shell 

side water, and eddy 

current testing of tubes.

Yes Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.2.2)

Stainless steel 

Piping, piping 

components, and 

piping elements; 

tanks exposed to Air 

– outdoor (3.3.1-4)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.2.3)
AGING MANAGEMENT REVIEW RESULTS

3-357

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with stainless 

steel or nickel-alloy 

cladding) Pump 

Casings exposed to 

Treated borated 

water (3.3.1-5)

Loss of material 

caused by 

cladding breach

A plant-specific aging 

management program is 

to be evaluated. 

Reference NRC 

Information Notice 

94-63, “Boric Acid 

Corrosion of Charging 

Pump Casings Caused 

by Cladding Cracks.”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.2.3)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air–outdoor (3.3.1-6)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.2.5)

Stainless steel 

high-pressure pump, 

casing exposed to 

treated borated 

water (3.3.1-7)

Cracking 

caused by cyclic 

loading

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, 

Subsections IWB, IWC, 

and IWD”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections I

WB, IWC, and 

IWD

Consistent with the 

GALL Report

Stainless steel heat 

exchanger 

components and 

tubes exposed to 

treated borated 

water >60 °C 

(>140 °F) (3.3.1-8)

Cracking 

caused by cyclic 

loading

Chapter XI.M1, “ASME 

Section XI Inservice 

Inspection, 

Subsections IWB, IWC, 

and IWD”

No ASME 

Section XI 

Inservice 

Inspection, 

Subsections I

WB, IWC, and 

IWD

Consistent with the 

GALL Report

Steel, aluminum, 

copper-alloy (>15% 

Zn or >8% Al) 

external surfaces, 

piping, piping 

components, and 

piping elements, 

bolting exposed to 

air with borated 

water leakage 

(3.3.1-9)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, “Boric 

Acid Corrosion”

No Boric Acid 

Corrosion

Consistent with the 

GALL Report

Steel, high-strength 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-10)

Cracking 

caused by 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel, high-strength 

high-pressure pump, 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-11)

Cracking 

caused by 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-358

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel; stainless steel 

Closure bolting, 

Bolting exposed to 

Condensation, Air –

indoor, uncontrolled 

(External), Air –

outdoor (External) 

(3.3.1-12)

Loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting 

Integrity

Consistent with the 

GALL Report

Steel Closure bolting 

exposed to Air with 

steam or water 

leakage (3.3.1-13)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel, Stainless 

Steel Bolting 

exposed to Soil 

(3.3.1-14)

Loss of preload Chapter XI.M18, 

“Bolting Integrity”

No Bolting 

Integrity

Consistent with the 

GALL Report

Steel; stainless 

steel, copper alloy, 

nickel alloy, stainless 

steel closure bolting, 

bolting exposed to 

air – indoor, 

uncontrolled 

(external), any 

environment, air –

outdoor (external), 

raw water, treated 

borated water, fuel 

oil, treated water 

(3.3.1-15)

Loss of preload 

caused by 

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting 

Integrity

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60 °C 

(>140 °F) (3.3.1-16)

Cracking 

caused by 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M25, “BWR 

Reactor Water Cleanup 

System”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.3.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water, Treated 

borated water

(3.3.1-17)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.1)

Stainless steel 

high-pressure pump, 

casing, piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

>60 °C (>140 °F), 

sodium pentaborate 

solution >60 °C 

(>140 °F) (3.3.1-18)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with 

the GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-359

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

regenerative heat 

exchanger 

components 

exposed to treated 

water >60 °C 

(>140 °F) (3.3.1-19)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.3.2.1.1)

Stainless steel, 

stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to treated 

borated water 

>60 °C (>140 °F), 

treated water >60 °C 

(>140 °F) (3.3.1-20)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.3.1-21)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.3.2.1.1)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-22)

Loss of material 

caused by 

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

PWRs

(see SER 

Section 3.3.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-23)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-24)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.3.2.1.1)

Stainless steel, 

stainless steel; steel 

with stainless steel 

cladding, aluminum 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to treated 

water, sodium 

pentaborate solution 

(3.3.1-25)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.3.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-360

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with elastomer 

lining), steel (with 

elastomer lining or 

stainless steel 

cladding) piping, 

piping components,

and piping elements 

exposed to treated 

water (3.3.1-26)

Loss of material 

caused by 

pitting and 

crevice 

corrosion (only 

for steel after 

lining/cladding 

degradation)

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.3.1-27)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.3.2.1.1)

Stainless steel, 

Piping, piping 

components, and 

piping elements; 

tanks exposed to 

treated borated 

water (Primary, 

oxygen levels 

controlled) >60 °C 

(>140 °F) (3.3.1-28)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry”

No Water 

Chemistry 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.2)

Steel (with stainless 

steel cladding); 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

(Primary, oxygen 

levels controlled) 

(3.3.1-29)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry”

No Water 

Chemistry 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.3)

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

Water (3.3.1-30)

Changes in 

material 

properties 

caused by 

aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Fiberglass, HDPE 

Piping, piping 

components, and 

piping elements 

exposed to raw 

water (internal) 

3.3.1-30a)

Cracking, 

blistering, 

change in color 

caused by water 

absorption

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-31)

Cracking 

caused by 

settling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-361

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-32)

Cracking 

caused by 

aggressive 

chemical attack 

and leaching; 

changes in 

material 

properties 

caused by 

aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No External 

Surfaces 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.4)

Elastomer seals and 

components 

exposed to raw 

water (3.3.1-32a)

Hardening and 

loss of strength 

caused by 

elastomer 

degradation; 

loss of material 

caused by 

erosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.18)

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-33)

Loss of material 

caused by 

abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Nickel alloy, 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-34)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-35)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-36)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.5)
AGING MANAGEMENT REVIEW RESULTS

3-362

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with coating or 

lining) piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-37)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion; 

lining/coating 

degradation

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components or 

Fire Water 

System

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.5)

Copper alloy, steel 

heat exchanger 

components 

exposed to raw 

water (3.3.1-38)

Loss of material 

caused by 

general, pitting, 

crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-39)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-40)

Loss of material 

caused by 

pitting and 

crevice 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Bolting 

Integrity

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.5)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-41)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report

Copper alloy, 

titanium, stainless 

steel heat exchanger 

tubes exposed to 

raw water (3.3.1-42)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-363

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.3.1-43)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Closed Treated 

Water System

Consistent with the 

GALL Report

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.3.1-44)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

closed-cycle cooling 

water (3.3.1-45)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Closed Treated 

Water System

Consistent with the 

GALL Report

Steel, copper alloy 

heat exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.3.1-46)

Loss of material 

caused by 

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Closed Treated 

Water System

Consistent with the 

GALL Report

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water (3.3.1-47)

Loss of material 

caused by 

microbiologically

-influenced 

corrosion

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.3.2.1.1)

Aluminum piping, 

piping components, 

and piping elements

exposed to 

closed-cycle cooling 

water (3.3.1-48)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water (3.3.1-49)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Closed Treated 

Water System

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-364

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel, 

copper alloy, steel 

heat exchanger 

tubes exposed to 

closed-cycle cooling 

water (3.3.1-50)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M21A, 

“Closed Treated Water 

Systems”

No Closed Treated 

Water System

Consistent with the 

GALL Report

Boraflex Spent fuel 

storage racks: 

neutron-absorbing 

sheets (PWR), spent 

fuel storage racks: 

neutron-absorbing 

sheets (BWR) 

exposed to treated 

borated water, 

treated water 

(3.3.1-51)

Reduction of 

neutron-absorbi

ng capacity 

caused by 

boraflex 

degradation

Chapter XI.M22, 

“Boraflex Monitoring”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel cranes: rails 

and structural 

girders exposed to 

air – indoor, 

uncontrolled 

(external) (3.3.1-52)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M23, 

“Inspection of Overhead 

Heavy Load and Light 

Load (Related to 

Refueling) Handling 

Systems”

No Inspection of 

Overhead 

Heavy Load 

and Light Load 

(Related to 

Refueling) 

Handling 

Systems

Consistent with the 

GALL Report

Steel cranes - rails 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-53)

Loss of material 

caused by wear

Chapter XI.M23, 

“Inspection of Overhead 

Heavy Load and Light 

Load (Related to 

Refueling) Handling 

Systems”

No Inspection of 

Overhead 

Heavy Load

and Light Load 

(Related to 

Refueling) 

Handling 

Systems

Consistent with the 

GALL Report

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(3.3.1-54)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.6)

Steel piping, piping 

components, and 

piping elements: 

compressed air

system exposed to 

condensation 

(Internal) (3.3.1-55)

Loss of material 

caused by 

general and 

pitting corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the

GALL Report 

(see SER 

Section 3.3.2.1.6)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(Internal) (3.3.1-56)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.6)
AGING MANAGEMENT REVIEW RESULTS

3-365

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Elastomers fire 

barrier penetration 

seals exposed to 

air - indoor, 

uncontrolled, air –

outdoor (3.3.1-57)

Increased

hardness; 

shrinkage; loss 

of strength 

caused by 

weathering

Chapter XI.M26, “Fire 

Protection”

No Fire Protection Consistent with the 

GALL Report

Steel halon/carbon 

dioxide fire 

suppression system 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-58)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M26, “Fire 

Protection”

No Fire Protection Consistent with the 

GALL Report

Steel fire rated doors 

exposed to 

air - indoor, 

uncontrolled, air –

outdoor (3.3.1-59)

Loss of material 

caused by wear

Chapter XI.M26, “Fire 

Protection”

No Fire Protection Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings and floors 

exposed to 

air - indoor, 

uncontrolled 

(3.3.1-60)

Concrete 

cracking and 

spalling caused 

by aggressive 

chemical attack, 

and reaction 

with aggregates

Chapter XI.M26, “Fire 

Protection,” and 

Chapter XI.S6, 

“Structures Monitoring”

No Fire Protection 

and Structures 

Monitoring

Consistent with the 

GALL Report

Reinforced concrete 

Structural fire 

barriers: walls, 

ceilings and floors 

exposed to Air –

outdoor (3.3.1-61)

Cracking, loss 

of material 

caused by 

freeze-thaw, 

aggressive 

chemical attack, 

and reaction 

with aggregates

Chapter XI.M26, “Fire 

Protection,” and 

Chapter XI.S6, 

“Structures Monitoring”

No Fire Protection 

and Structures 

Monitoring

Consistent with the 

GALL Report

Reinforced concrete 

Structural fire 

barriers: walls, 

ceilings and floors 

exposed to 

Air - indoor, 

uncontrolled, Air –

outdoor (3.3.1-62)

Loss of material 

caused by 

corrosion of 

embedded steel

Chapter XI.M26, “Fire 

Protection,” and 

Chapter XI.S6, 

“Structures Monitoring”

No Fire Protection 

and Structures 

Monitoring

Consistent with the 

GALL Report

Steel Fire Hydrants 

exposed to Air –

outdoor (3.3.1-63)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M27, “Fire 

Water System”

No Fire Water 

System

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-366

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel, Copper-alloy 

Piping, piping 

components, and 

piping elements 

exposed to Raw 

water (3.3.1-64)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, “Fire 

Water System”

No Fire Water 

System

Consistent with the 

GALL Report (see 

SER 

Section 3.3.2.1.20)

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Raw 

water (3.3.1-65)

Loss of material 

caused by 

pitting and 

crevice 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, “Fire 

Water System”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to Raw 

water (3.3.1-66)

Loss of material 

caused by 

pitting and 

crevice 

corrosion; 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, “Fire 

Water System”

No Fire Water 

System

Consistent with the 

GALL Report

Steel Tanks exposed 

to Air – outdoor 

(External) (3.3.1-67)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel Piping, piping 

components, and 

piping elements 

exposed to Fuel oil 

(3.3.1-68)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M30, “Fuel 

Oil Chemistry”, and 

Chapter XI.M32, 

“One-Time Inspection” 

No Fuel Oil 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper-alloy Piping, 

piping components, 

and piping elements 

exposed to Fuel oil 

(3.3.1-69)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M30, “Fuel 

Oil Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Fuel Oil 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-367

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel Piping, piping 

components, and 

piping elements; 

tanks exposed to 

Fuel oil (3.3.1-70)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M30, “Fuel 

Oil Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Fuel Oil 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel, 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Fuel oil 

(3.3.1-71)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M30, “Fuel 

Oil Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Bolting 

Integrity 

Consistent with the 

GALL Report (see 

SER Section 

3.3.2.1.4)

Gray cast iron, 

Copper-alloy (>15% 

Zn or >8% Al) 

Piping, piping 

components, and 

piping elements, 

Heat exchanger 

components 

exposed to Treated 

water, Closed-cycle 

cooling water, Soil,

Raw water, Waste 

water (3.3.1-72)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Selective 

Leaching

Consistent with the 

GALL Report

Concrete; 

cementitious 

material Piping, 

piping components, 

and piping elements 

exposed to Air –

outdoor (3.3.1-73)

Changes in 

material 

properties 

caused by 

aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Concrete; 

cementitious 

material Piping, 

piping components, 

and piping elements 

exposed to Air –

outdoor (3.3.1-74)

Cracking 

caused by 

settling

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Reinforced concrete, 

asbestos cement 

Piping, piping 

components, and 

piping elements 

exposed to Air –

outdoor (3.3.1-75)

Cracking 

caused by 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties 

caused by 

aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-368

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Elastomers 

Elastomer: seals and 

components 

exposed to Air –

indoor, uncontrolled 

(Internal/External) 

(3.3.1-76)

Hardening and 

loss of strength 

caused by 

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with 

GALL Report (see 

SER 

Section 3.3.2.1.7)

Concrete; 

cementitious 

material Piping, 

piping components, 

and piping elements 

exposed to Air –

outdoor (3.3.1-77)

Loss of material 

caused by 

abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel Piping and 

components 

(External surfaces), 

Ducting and 

components 

(External surfaces), 

Ducting; closure 

bolting exposed to 

Air – indoor, 

uncontrolled 

(External), Air –

indoor, uncontrolled 

(External), Air –

outdoor (External), 

Condensation 

(External) (3.3.1-78)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.8)

Copper-alloy Piping, 

piping components, 

and piping elements 

exposed to 

Condensation 

(External) (3.3.1-79)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report 

(see SER 

Section 3.3.2.1.9)

Steel Heat 

exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(External), Air –

outdoor (External) 

(3.3.1-80)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Copper-alloy, 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Air –

outdoor (External), 

Air – outdoor 

(3.3.1-81)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-369

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Elastomers 

Elastomer: seals and 

components 

exposed to Air –

indoor, uncontrolled 

(External) (3.3.1-82)

Loss of material 

caused by wear

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with 

GALL Report 

(see SER 

Section 3.3.2.1.10)

Stainless steel 

Diesel engine 

exhaust piping, 

piping components, 

and piping elements 

exposed to Diesel 

exhaust (3.3.1-83)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Elastomers 

Elastomer seals and 

components 

exposed to 

Closed-cycle cooling 

water (3.3.1-85)

Hardening and 

loss of strength 

caused by 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Elastomers, linings, 

Elastomer: seals and 

components 

exposed to Treated 

borated water, 

Treated water, Raw 

water (3.3.1-86)

Hardening and 

loss of strength 

caused by 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel; stainless steel 

Piping, piping 

components, and 

piping elements, 

Piping, piping 

components, and

piping elements, 

diesel engine 

exhaust exposed to 

Raw water (potable), 

Diesel exhaust 

(3.3.1-88)

Loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel, Copper-alloy 

Piping, piping 

components, and 

piping elements 

exposed to Moist air 

or condensation 

(Internal) (3.3.1-89)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

For fire water system 

components: Chapter 

XI.M27, “Fire Water 

System.” 

For other components: 

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components or 

Fire Water 

System

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-370

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel Ducting and 

components 

(Internal surfaces) 

exposed to 

Condensation 

(Internal) (3.3.1-90)

Loss of material 

caused by 

general, pitting, 

crevice, and (for 

drip pans and 

drain lines) 

microbiologically

-influenced 

corrosion 

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Fire Protection Consistent with 

GALL Report

(see SER 

Section 3.3.2.1.11)

Steel Piping, piping 

components, and 

piping elements; 

tanks exposed to 

Waste Water 

(3.3.1-91)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to 

Condensation 

(Internal) (3.3.1-92)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.12)

Copper-alloy Piping, 

piping components, 

and piping elements 

exposed to Raw 

water (potable) 

(3.3.1-93)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Stainless steel 

Ducting and 

components 

exposed to 

Condensation 

(3.3.1-94)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.12)

Copper-alloy, 

Stainless steel, 

Nickel alloy, Steel 

Piping, piping 

components, and 

piping elements, 

Heat exchanger 

components, Piping, 

piping components, 

and piping elements; 

tanks exposed to 

Waste water, 

Condensation 

(Internal) (3.3.1-95)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report 
AGING MANAGEMENT REVIEW RESULTS

3-371

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Elastomers 

Elastomer: seals and 

components 

exposed to Air –

indoor, uncontrolled 

(Internal) (3.3.1-96)

Loss of material 

caused by wear

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements, 

Reactor coolant 

pump oil collection 

system: tanks, 

Reactor coolant 

pump oil collection 

system: piping, 

tubing, valve bodies 

exposed to 

Lubricating oil 

(3.3.1-97)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and Chapter 

XI.M32, “One-Time 

Inspection”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report 

(see SER 

Section 3.3.2.1.13)

Steel Heat 

exchanger 

components 

exposed to 

Lubricating oil 

(3.3.1-98)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and Chapter 

XI.M32, “One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time

Inspection

Consistent with the 

GALL Report

Copper-alloy, 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to 

Lubricating oil 

(3.3.1-99)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and Chapter 

XI.M32, “One-Time 

Inspection”

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to 

Lubricating oil 

(3.3.1-100)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and Chapter 

XI.M32, “One-Time 

Inspection”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with 

GALL Report

(see SER 

Section 3.3.2.1.14)

Aluminum Heat 

exchanger tubes 

exposed to 

Lubricating oil 

(3.3.1-101)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and Chapter 

XI.M32, “One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-372

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Boral®; boron steel, 

and other materials 

(excluding Boraflex) 

Spent fuel storage 

racks: 

neutron-absorbing 

sheets (PWR), 

Spent fuel storage 

racks: 

neutron-absorbing 

sheets (BWR) 

exposed to Treated 

borated water, 

Treated water 

(3.3.1-102)

Reduction of 

neutron-absorbi

ng capacity; 

change in 

dimensions and 

loss of material 

caused by 

effects of SFP 

environment

Chapter XI.M40, 

“Monitoring of 

Neutron-Absorbing 

Materials other than 

Boraflex”

No Monitoring of 

Neutron 

Absorbing 

Materials other 

than Boraflex

Consistent with the 

GALL Report

Reinforced concrete, 

asbestos cement 

Piping, piping 

components, and 

piping elements 

exposed to Soil or 

concrete (3.3.1-103)

Cracking 

caused by 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties 

caused by 

aggressive 

chemical attack

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

HDPE, Fiberglass 

Piping, piping 

components, and 

piping elements 

exposed to Soil or 

concrete (3.3.1-104)

Cracking, 

blistering, 

change in color 

caused by water 

absorption

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report

Concrete cylinder 

piping, Asbestos 

cement pipe Piping, 

piping components, 

and piping elements 

exposed to Soil or 

concrete (3.3.1-105)

Cracking, 

spalling, 

corrosion of 

rebar caused by 

exposure of 

rebar

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel (with coating or 

wrapping) Piping, 

piping components, 

and piping elements 

exposed to Soil or 

concrete (3.3.1-106)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report

Stainless steel, 

nickel alloy, Piping, 

piping components, 

and piping elements 

exposed to Soil or 

concrete (3.3.1-107)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-373

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Titanium, 

Super-austenitic, 

Aluminum, 

Copper-alloy, 

Stainless Steel, 

nickel alloy, Piping, 

piping components, 

and piping elements, 

Bolting exposed to 

Soil or concrete 

(3.3.1-108)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Steel Bolting 

exposed to Soil or 

concrete (3.3.1-109)

Loss of material 

caused by 

general, pitting 

and crevice 

corrosion

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report

Underground 

Aluminum, 

Copper-alloy, 

Stainless Steel, 

nickel alloy and 

Steel Piping, piping 

components, and 

piping elements 

(3.3.1-109a)

Loss of material 

caused by

general (steel 

only), pitting and 

crevice 

corrosion

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to Treated 

water >60 °C 

(>140 °F) 

(3.3.1-110)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M7, “BWR 

Stress Corrosion 

Cracking,” and Chapter 

XI.M2, “Water 

Chemistry” 

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.3.2.1.1)

Steel Structural steel 

exposed to Air –

indoor, uncontrolled 

(External) 

(3.3.1-111)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S6, 

“Structures Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.3.1-112)

None None, provided 

1) attributes of the 

concrete are consistent 

with ACI 318 or ACI 349 

(low water-to-cement 

ratio, low permeability, 

and adequate air 

entrainment) as cited in

NUREG-1557, and

2) plant OE indicates no 

degradation of the 

concrete

No, if 

conditions 

are met.

None Consistent with 

GALL Report (see 

SER 

Section 3.3.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-374

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Air – dry 

(Internal/External),

Air – indoor, 

uncontrolled 

(Internal/External), 

Air – indoor, 

controlled (External), 

Gas (3.3.1-113)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Copper-alloy Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(Internal/External), 

Air – dry, Gas 

(3.3.1-114)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Copper-alloy (≤15% 

Zn and ≤8% Al) 

Piping, piping 

components, and 

piping elements 

exposed to Air with 

borated water 

leakage (3.3.1-115)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Galvanized steel 

Piping, piping 

components, and 

piping elements 

exposed to 

Air - indoor, 

uncontrolled 

(3.3.1-116)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Glass Piping 

elements exposed to 

Air – indoor, 

uncontrolled 

(External), 

Lubricating oil, 

Closed-cycle cooling 

water, Air – outdoor, 

Fuel oil, Raw water, 

Treated water, 

Treated borated 

water, Air with 

borated water 

leakage, 

Condensation 

(Internal/External) 

Gas (3.3.1-117)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-375

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Nickel alloy Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(External) 

(3.3.1-118)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Nickel alloy, PVC, 

Glass Piping, piping 

components, and 

piping elements 

exposed to Air with 

borated water 

leakage, Air –

indoor, uncontrolled, 

Condensation 

(Internal), Waste 

Water (3.3.1-119)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to Air –

indoor, uncontrolled 

(Internal/External), 

Air – indoor, 

uncontrolled 

(External), Air with 

borated water 

leakage, Concrete, 

Air – dry, Gas 

(3.3.1-120)

None None NA - No 

AEM or 

AMP

None Consistent with 

GALL Report (see 

SER 

Section 3.3.2.1.15)

Steel Piping, piping 

components, and 

piping elements 

exposed to Air –

indoor, controlled 

(External), Air – dry, 

Gas (3.3.1-121)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Titanium Heat 

exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

or Air – outdoor 

(3.3.1-122)

None None NA - No 

AEM or 

AMP

None Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-376

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Titanium (ASTM 

Grades 1,2, 7, 11, or 

12 that contains 

>5% aluminum or 

more than 0.20% 

oxygen or any 

amount of tin) Heat 

exchanger 

components other 

than tubes, Piping, 

piping components, 

and piping elements 

exposed to Raw 

water (3.3.1-123)

None None NA - No 

AEM or 

AMP

None Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Stainless steel, Steel 

(with stainless steel 

or nickel-alloy 

cladding) Spent fuel 

storage racks 

(BWR), Spent fuel 

storage racks 

(PWR), Piping, 

piping components, 

and piping elements; 

exposed to Treated 

water >60°C 

(>140°F), Treated 

borated water >60°C 

(>140°F) (3.3.1-124)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Water 

Chemistry and 

One-Time 

Inspection 

Consistent with the 

GALL Report

Steel (with stainless

steel cladding);

stainless steel Spent

fuel storage racks

(BWR), Spent fuel

storage racks

(PWR), Piping,

piping components,

and piping elements;

exposed to Treated

water, Treated 

borated water 

(3.3.1-125)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, “Water 

Chemistry,” and 

Chapter XI.M32, 

“One-Time Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report (see 

SER 

Section 3.3.2.1.16)

Any material piping, 

piping components 

and piping elements 

exposed to reactor 

coolant (3.3.1-126)

Wall thinning 

due to erosion

Chapter XI.M17,

“Flow-Accelerated 

Corrosion”

No Open-Cycle 

Cooling Water 

System

Consistent with the

GALL Report (see 

SER 

Section 3.3.2.1.17)

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

waste water 

(3.3.1-127)

Loss of material 

due to recurring 

internal 

corrosion

A plant-specific aging 

management program is 

to be evaluated to 

address recurring 

internal corrosion

Yes, plantspecific 

(see SER 

Section 

3.3.2.2.8)

Open-Cycle 

Cooling Water 

System

Consistent with the 

GALL Report (see 

SER 

Section 3.3.2.2.8)
AGING MANAGEMENT REVIEW RESULTS

3-377

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel, stainless 

steel, or aluminum 

tanks (within the 

scope of 

Chapter XI.M29,

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments 

air-outdoor, 

air-indoor 

uncontrolled, moist 

air, condensation 

(3.3.1-128)

Loss of material 

due to general 

(steel only), 

pitting, or 

crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum)

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Metallic piping, 

piping components, 

heat exchangers, 

tanks with Service

Level III 

(augmented) internal 

coatings exposed to 

closed-cycle cooling 

water, raw water, 

treated water, 

treated borated 

water, waste water, 

lubricating oil, or fuel 

oil (3.3.1-128a)

Loss of coating 

integrity due to 

blistering, 

cracking, 

flaking, peeling,

or physical 

damage

Chapter XI.M42, 

“Service Level III 

(augmented) Coatings 

Monitoring and 

Maintenance Program”

No Open-Cycle 

Cooling Water 

System, Fire 

Water System, 

Fuel Oil 

Chemistry, 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report (see 

SER 

Section 3.3.2.1.19)

Steel tanks exposed 

to soil or concrete; 

air-indoor 

uncontrolled, raw 

water, treated water, 

waste water, 

condensation 

(3.3.1-129)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

Metallic sprinklers 

exposed to 

air-indoor controlled, 

air-indoor 

uncontrolled, 

air-outdoor, moist 

air, condensation, 

raw water, treated 

water (3.3.1-130)

Loss of material 

due to general 

(where 

applicable), 

pitting, crevice, 

and 

microbiologically

influenced 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, “Fire 

Water System”

No Fire Water 

System

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-378

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel, stainless 

steel, copper alloy, 

or aluminum fire 

water system piping, 

piping components 

and piping elements 

exposed to 

air-indoor 

uncontrolled 

(internal), air-outdoor 

(internal), or 

condensation 

(internal) (3.3.1-131)

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

crevice, and 

microbiologically

influenced 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling

Chapter XI.M27, “Fire 

Water System”

No Fire Water 

System

Consistent with the 

GALL Report

Insulated steel, 

stainless steel, 

copper alloy, 

aluminum, or copper 

alloy (>15% Zn) 

piping, piping 

components, and 

tanks exposed to 

condensation, 

air-outdoor 

(3.3.1-132)

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

and crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(aluminum, 

stainless steel 

and copper alloy 

(>15% Zn) only)

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground Metallic 

Tanks” (for tanks only)

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report 

Underground HDPE 

piping, piping 

components, and 

piping elements in 

an air-indoor 

uncontrolled or 

condensation 

(external) 

environment 

(3.3.1-133)

Cracking, 

blistering, 

change in color 

due to water 

absorption

Chapter XI.M41, “Buried 

and Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report

Steel, stainless 

steel, or copper alloy 

piping, piping 

components, and 

piping elements, and 

heat exchanger 

components 

exposed to a raw 

water environment 

(for 

nonsafety-related 

components not 

covered by NRC 

GL 89-13) 

(3.3.1-134)

Loss of material 

due to general 

(steel and 

copper alloy 

only), pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, 

fouling that 

leads to 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report (see 

SER 

Section 3.3.2.1.5
AGING MANAGEMENT REVIEW RESULTS

3-379

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP in 

SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel or stainless 

steel pump casings 

submerged in a 

waste water (internal 

and external) 

environment 

(3.3.1-135)

Loss of material 

due to general 

(steel only), 

pitting, crevice, 

and 

microbiologically

influenced 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Bolting 

Integrity

Consistent with the 

GALL Report (see 

SER 

Section 3.3.2.1.5)

Steel, stainless 

steel, or aluminum 

fire water storage 

tanks exposed to 

air-indoor 

uncontrolled, 

air-outdoor, 

condensation, moist 

air, raw water, 

treated water 

(3.3.1-136)

Loss of material 

due to general 

(steel only), 

pitting, crevice, 

and 

microbiologically

influenced 

corrosion, 

fouling that 

leads to 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only)

Chapter XI.M27, "Fire 

Water System"

No Fire Water 

System

Consistent with the 

GALL Report 

Steel, stainless 

steel, or aluminum 

tanks (within the 

scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water, treated 

borated water 

(3.3.1-137)

Loss of material 

due to general 

(steel only) 

pitting and 

crevice 

corrosion

Chapter XI.M29,

“Aboveground Metallic

Tanks”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.3.2.1.1)

3.3.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the auxiliary systems components:

• Aboveground Metallic Tanks

• ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

• Bolting Integrity

• Boric Acid Corrosion

• Buried and Underground Piping and Tanks

• Closed Treated Water Systems

• External Surfaces Monitoring of Mechanical Components 
AGING MANAGEMENT REVIEW RESULTS

3-380

• Fire Protection

• Fire Water System

• Fuel Oil Chemistry

• Flow-Accelerated Corrosion

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

• Lubricating Oil Analysis

• Monitoring of Neutron-Absorbing Materials other than Boraflex 

• One-Time Inspection 

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping

• Open-Cycle Cooling Water System

• Selective Leaching

• Structures Monitoring

• Water Chemistry

LRA Tables 3.3.2-1 through 3.3.2-29 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 claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine if the plant-specific components in these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR item. 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–E, which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions.

Note C indicates that the component for the AMR item, although different from, 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 
AGING MANAGEMENT REVIEW RESULTS

3-381

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 

AMR items to confirm consistency with the GALL Report. The staff also determined whether the 

AMR item of the different component applied to the component under review and whether the 

AMR was valid for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the AMP identified in the GALL Report. The staff audited these AMR items 

to confirm consistency with the GALL Report and confirmed whether the AMR item of the 

different component was applicable to the component under review. The staff confirmed 

whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 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 item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff audited these AMR 

items to confirm consistency with the GALL Report and determined whether the identified AMP 

would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff did not repeat its review of the matters described in the GALL Report; however, it did 

confirm that the material presented in the LRA was applicable and that the applicant identified 

the appropriate GALL Report AMRs. The staff’s evaluation is discussed below.

3.3.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.3-1, items 3.3.1-16, 3.3.1-24, 3.3.1-25, 3.3.1-27, and 3.3.1-110, the applicant 

claimed that the corresponding AMR items in the GALL Report are not applicable because the 

associated items are only applicable to BWRs. The staff reviewed the SRP-LR, confirmed 

these items only apply to BWRs, and finds that these items are not applicable to Callaway, 

which is a PWR.

For LRA Table 3.3-1, items 3.3.1-10, 3.3.1-23, 3.3.1-30, 3.3.1-30, 3.3.1-31, 3.3.1-33, 3.3.1-48, 

3.3.1-51, 3.3.1-65, 3.3.1-67, 3.3.1-73 through 3.3.1-75, 3.3.1-77, 3.3.1-101, 3.3.1-103, 

3.3.1-105, 3.3.1-108, 3.3.1-122, 3.3.1-123, 3.3.1-128, 3.3.1-129, and 3.3.1-137, the applicant 

claimed that the corresponding items in the GALL Report are not applicable because the

component, material, and environment combination described in the SRP-LR does not exist for 

in-scope SCs at Callaway. The staff reviewed the LRA and FSAR and confirmed that the 

applicant’s LRA does not have any AMR results applicable for these items.

For LRA Table 3.3-1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable; however, the staff non-applicability verification of 

these items required the review of sources beyond the LRA and FSAR, and/or the issuance of 

RAIs.

LRA Table 3.3-1, item 3.3.1-13 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity” to 

manage loss of material caused by general corrosion for this component group. The applicant 

stated that this item is not applicable because closure bolting was evaluated using plant indoor 

air as the external environment and SRP-LR Table 3.3-1, item 3.3.1-12 for steel closure bolting 

exposed to an air-indoor uncontrolled environment instead of item 3.3.1-13. The staff evaluated 
AGING MANAGEMENT REVIEW RESULTS

3-382

the applicant’s claim and finds it acceptable because the component group is being managed 

for the loss of material aging effect by the Bolting Integrity Program, consistent with the GALL 

Report recommendations.

LRA Table 3.3-1, item 3.3.1-17 addresses stainless steel heat exchanger tubes exposed to 

treated water or treated, borated water. The GALL Report recommends AMP XI.M2, “Water 

Chemistry,” and AMP XI.M32, “One-Time Inspection,” to manage reduction of heat transfer 

caused by fouling for this component group. The applicant stated that this item is not applicable 

because it only applies to BWRs. However, in its review of the applicant’s claim, the staff noted 

that LR-ISG-2011-01, “Aging Management of Stainless Steel Structures and Components in 

Treated Borated Water,” discussed the applicability of reduction of heat transfer for components 

in both treated water and treated borated water. Therefore, the staff required additional 

information to ensure that the aging effects for this component group was being adequately 

managed. By letter dated August 16, 2012, the staff issued RAI 3.3.1.17-1 requesting the 

applicant to justify the non-applicability of item 3.3.1-17. In its response dated 

September 20, 2012, the applicant added item 3.3.1-17 to LRA Tables 3.3.2-2 and 3.3.2-10 

reflecting reduction of heat transfer as an aging effect for the stainless steel heat exchanger 

tubes in the fuel pool cooling and CVC seal water heat exchangers. The applicant also revised 

LRA Table 3.3-1, item 3.3.1-17 as being consistent with the GALL Report. The staff finds the 

applicant’s response acceptable because, consistent with SRP-LR A.1.2.1, the applicant’s 

determination of applicable aging effects is now based on those aging effects that potentially 

could cause component degradation. The staff notes that the applicant’s use of the Water 

Chemistry and One-Time Inspection Programs to manage reduction of heat transfer in the heat 

exchanger tubes exposed to treated borated water for item 3.3.1-17 is consistent with the GALL 

Report. The staff’s concern described in RAI 3.3.1.17-1 is resolved. 

LRA Table 3.3-1, item 3.3.1-19 addresses stainless steel regenerative heat exchanger 

components exposed to treated water. The GALL Report recommends AMP XI.M2, “Water 

Chemistry,” and AMP XI.M32, “One-Time Inspection,” to manage cracking caused by SCC for 

this component group. The applicant stated that this item is not applicable because it only 

applies to BWRs. In its review of the applicant’s claim, the staff noted that LRA Table 3.3-1, 

item 3.3.1-20 also addresses stainless steel heat exchanger components exposed to treated 

borated water and uses the same AMPs as those recommended for item 3.3.1-19. The staff 

also noted that the applicant extensively cited item 3.3.1-20 in several of the auxiliary system 

“Summary of Aging Management Evaluation,” tables. The staff accepts the applicant’s claim 

that item 3.3.1-19 is not applicable because the applicant is using an alternate AMR item, 

item 3.3.1-20, which uses the same AMPs to manage this aging effect for these components. 

LRA Table 3.3-1, item 3.3.1-22 addresses copper-alloy piping, piping components, and piping 

elements exposed to treated water. The GALL Report recommends GALL Report AMPs XI.M2, 

“Water Chemistry,” and XI.M32, “One-Time Inspection” to manage loss of material for this 

component group but states that the item is for BWRs only. The applicant stated that this item 

is not applicable because it is only applicable to BWRs. However, the staff noted that PWRs 

may have copper alloy components exposed to treated water in the auxiliary systems, and that 

this is the case at Callaway. The staff evaluated the applicant’s claim and finds it acceptable 

because the applicant used LRA Table 3.4-1, item 3.4.1-16, to manage aging for copper alloy 

items exposed to treated water in the auxiliary systems, which manages aging consistent with 

the recommendations in item 3.3.1-22.

LRA Table 3.3.1, item 3.3.1-26 addresses steel (with elastomer lining or stainless steel 

cladding) piping, piping components and piping elements exposed to treated water. The GALL 
AGING MANAGEMENT REVIEW RESULTS

3-383

Report recommends GALL Report AMPs XI.M2, “Water Chemistry,” and XI.M32, “One-Time 

Inspection,” to manage loss of material caused by pitting and crevice corrosion (only for steel 

after lining or cladding degradation for this component group). The applicant stated that this 

item is not applicable because “Callaway has no in-scope steel (with elastomer lining or 

stainless steel cladding) piping, piping components or piping elements exposed to treated water 

in the fuel pool cooling and clean up system, so the applicable NUREG-1801 lines were not 

used.” The staff finds that the applicant’s claim acceptable because SRP-LR item 3.3.1-26, 

which cites GALL Report items VII.A3.AP-107 and VII.A4.AP-108, is only associated with spent 

fuel pool cooling and cleanup system; and based on a review of the FSAR, there is no steel 

piping in this system except for that with an internal environment of closed-cycle cooling water 

which is being managed for loss of material by the Closed Treated Water Systems Program. 

LRA Table 3.3-1, item 3.3.1-34 addresses nickel alloy and copper-alloy piping components 

exposed to raw water. The GALL Report recommends GALL Report AMP XI.M20, 

“Open-Cycle Cooling Water System,” to manage loss of material caused by general, pitting, 

and crevice corrosion for this component group. The applicant stated that this item is not 

applicable because Callaway has no in-scope nickel alloy components exposed to raw water in 

the auxiliary systems, and because the copper alloy components are being addressed in 

items 3.3.1-35, 3.3.3-36, and 3.3.1-38. The staff evaluated the applicant’s claim and finds it 

acceptable because the staff reviewed LRA Sections 2.3.3 and 3.3 and FSAR Section 9.2, 

“Water Systems,” and confirmed that there were no in-scope nickel alloy components exposed 

to raw water. In addition, the staff confirmed that the LRA addressed copper alloy components 

exposed to raw water through items 3.3.1-35, 3.3.3-36, and 3.3.1-38, which also specify the 

Open-Cycle Cooling Water System Program as the applicable AMP. 

LRA Table 3.3-1, item 3.3.1-39 addresses stainless steel piping components exposed to raw 

water. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling 

Water System,” to manage loss of material caused by pitting and crevice corrosion and fouling 

that leads to corrosion for this component group. The applicant stated that this item is not 

applicable because Callaway has no in-scope stainless steel piping components exposed to raw 

water in the UHS, and because stainless steel piping components in the ESW system are being 

managed by GALL Report items from Section VII.C1, “Open-Cycle Cooling Water System.” The 

staff evaluated the applicant’s claim and finds it acceptable because the staff reviewed LRA 

Sections 2.3.3 and 3.3 and FSAR Section 9.2, “Water Systems,” and confirmed that there were 

no in-scope stainless steel components exposed to raw water in the UHS system. In addition, 

the staff confirmed that the LRA addressed stainless steel components exposed to raw water in 

the auxiliary systems through item 3.3.1-40, which also specifies the Open-Cycle Cooling Water 

System Program as the applicable AMP. 

LRA Table 3.3-1, item 3.3.1-44 addresses stainless steel and steel with stainless steel cladding 

heat exchanger components exposed to closed-cycle cooling water greater than 60 °C (140 °F). 

The GALL Report recommends GALL Report AMP XI.M21A, “Closed Treated Water 

Systems,” to manage cracking caused by SCC for this component group. The applicant stated 

that this item is not applicable because it is applicable to BWR plants only. The staff noted that 

SRP-LR Table 3.3-1, item 44 is applicable to PWR and BWR plants; however, the 

corresponding AMR item in the GALL Report is for the reactor water cleanup system, which is a 

BWR system. The staff evaluated the applicant’s claim and found it acceptable because the 

staff confirmed that stainless steel heat exchanger components exposed to closed-cycle cooling 

water greater than 60 °C (140 °F) in the auxiliary systems reference an alternative piping item, 

LRA item 3.3.1-43, which manages for cracking caused by SCC in a manner consistent with 

LRA item 3.3.1-44 and GALL Report recommendations.
AGING MANAGEMENT REVIEW RESULTS

3-384

LRA Table 3.3-1, item 3.3.1-47 addresses stainless steel and steel with stainless steel cladding 

heat exchanger components exposed to closed-cycle cooling water. The GALL Report 

recommends GALL Report AMP XI.21A, “Closed Treated Water Systems,” to manage loss of 

material caused by MIC for this component group. The applicant stated that this item is not 

applicable because it is applicable to BWR plants only. Although SRP-LR Table 3.3-1, item 47, 

does not explicitly state that MIC is applicable to PWR plants, the staff noted that 

EPRI 1007820, “Closed Cooling Water Chemistry Guideline, Revision 1,” states that 

microbiological organisms can be found in virtually all closed cooling water systems. The staff 

also noted that, as documented in the staff’s Audit Report of the Closed Treated Water Systems 

Program, the applicant is managing loss of material caused by MIC in its closed treated water 

systems by monitoring bacteria counts and has provisions in its procedures for adding biocides 

on an as-needed basis. The staff further noted that the LRA contains AMR items for stainless 

steel heat exchanger components exposed to closed cycle cooling water that are managed for 

loss of material with the Closed Treated Water Systems Program. As a result, the staff finds 

that the applicant is appropriately managing loss of material caused by MIC for the subject 

components through the water chemistry controls and visual inspections for corrosion in the 

Closed Treated Water Systems Program, consistent with GALL Report guidance. 

LRA Table 3.3-1, item 3.3.1-86 addresses elastomer linings, seals, and components exposed to 

treated borated water, treated water, and raw water. The GALL Report recommends GALL 

Report AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components," to manage hardening and loss of strength caused by elastomer degradation for 

this component group. The applicant stated that this item is not applicable because, “Callaway 

has no in-scope elastomers or linings, exposed to treated borated water within the fuel pool 

cooling and cleanup system, so the applicable NUREG-1801 lines were not used.” The staff 

finds that the applicant’s claim acceptable because SRP-LR item 3.3.1-86, which cites GALL 

Report items VII.A3.AP-100 and VII.A4.AP-101, is only associated with spent fuel pool cooling 

and cleanup system; and based on a review of the FSAR and LRA, there are no elastomer lined 

components in the spent fuel pool cooling and cleanup system.

During its review of the LRA, the staff noted that the applicant cited SRP-LR items 3.3.1-112 

and 3.3.1-120 for several steel and stainless steel piping, piping components, and other 

component types embedded in concrete. There is an internal misalignment in the GALL Report 

in that the definition of buried piping and scope of AMP XI.M41 conflicts with items 3.3.1-112 

and 3.3.1-120, which state that there are no AERM or recommended AMP for the concrete 

environment. Regardless of the misalignment, the staff lacks sufficient information to conclude 

that the in-scope steel and stainless steel piping and piping components embedded in concrete 

do not need to be age managed. For example, if steel piping embedded in concrete is within a 

building or under a building but above the water table, the potential for water intrusion into the 

concrete is very low, and therefore, the conditional statements associated with SRP-LR 

item 3.3.1-112 represent a sufficient basis for why there are no aging effects for these items. 

By letter dated July 5, 2012, the staff issued RAI 3.3.1-1 requesting that the applicant state the 

basis for why there are no aging effects for these items.

In its response dated August 6, 2012, and amended by letter dated August 21, 2012, the 

applicant stated that it has floor and equipment drains which are located inside of buildings, 

metal dampers, and essential service water piping that is embedded in concrete and within a 

building, and structural steel anchorages where the potential for water intrusion into the 

concrete is very low. The applicant also stated that are no in-scope steel or stainless steel 

piping or piping components that transition directly from a buried environment to an embedded 

in concrete environment in that buried piping which enters buildings passes through sleeved 
AGING MANAGEMENT REVIEW RESULTS

3-385

penetrations in the building walls which have elastomeric water seals to prevent moisture 

intrusion into the building.

The staff finds the applicant’s response acceptable because despite the internal misalignment 

within the GALL Report, given that these components are not exposed to the potential for 

groundwater intrusion into the concrete, there is no AERM for steel and stainless steel piping 

components embedded in dry concrete as stated in SRP-LR items 3.3.1-112 and 3.3.1-120. 

The staff’s concern described in RAI 3.3.1-1 is resolved. 

3.3.2.1.2 Cracking Due to Stress Corrosion Cracking

LRA Table 3.3-1, item 3.3.1-28 addresses stainless steel pipes, piping components, piping 

elements, and heat exchangers exposed to treated borated water which will be managed for 

cracking due to SCC. For the AMR items that cite generic note E, the LRA credits the Water 

Chemistry and One-Time Inspection Programs to manage the aging effect for these 

components with this material and environment combination.

The staff noted that, during the LRA review, the environment for this item changed to treated 

borated water in primary systems (oxygen levels controlled), following the revised guidance in 

LR-ISG-2011-01. By letter dated December 19, 2012, the applicant revised the LRA AMR items 

that are associated with item 3.3.1-28. For these items, the applicant proposes to manage 

aging with the Water Chemistry program, citing generic note A to reflect the LRA consistency 

with the revised GALL Report guidance. The staff confirmed the consistency with the GALL 

Report and, therefore, finds the applicant’s proposal to manage aging acceptable.

LRA Table 3.3-1, item 3.3.1-124 was added to the LRA by letter dated December 19, 2012, in 

response to the issuance of LR-ISG-2011-01. Item 3.3.1-124 addresses stainless steel spent 

fuel storage equipment, piping, piping components, piping elements, tanks, and heat exchanger 

components exposed to treated borated water. For the AMR items that cite generic notes A or 

C, the LRA credits the Water Chemistry and One-Time Inspection Programs to manage 

cracking due to SCC for stainless steel components in treated borated water. The GALL 

Report, as revised by LR-ISG-2011-01, recommends GALL Report AMPs XI.M2, “Water 

Chemistry,” and XI.M32, “One-Time Inspection,” to ensure that these aging effects are 

adequately managed. The staff confirmed the consistency with the GALL Report and, therefore, 

finds the applicant’s proposal to manage aging acceptable.

The staff concludes that for LRA item 3.3.1-28, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.3 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3-1, item 3.3.1-29 addresses steel (with stainless steel cladding) and stainless 

steel piping, piping components, and piping elements exposed to treated borated water 

(primary, oxygen levels controlled), which will be managed for loss of material due to pitting and 

crevice corrosion. The staff noted that, during the LRA review, the environment for this item 

changed to treated borated water in primary systems, following the revised SRP-LR and GALL 

Report guidance in LR-ISG-2011-01, Revision 1, “Aging Management of Stainless Steel 

Structures and Components in Treated Borated Water.” Previously, item 3.3.1-29 did not 

specify that the environment was limited to primary water. 
AGING MANAGEMENT REVIEW RESULTS

3-386

By letter dated December 19, 2012, the applicant revised the AMR items that are associated 

with item 3.3.1-29. For these items, the applicant proposes to manage aging with the Water 

Chemistry Program, citing generic note A to reflect the LRA consistency with the revised GALL 

Report guidance. The staff confirmed the consistency with the GALL Report and, therefore, 

finds the applicant’s proposal to manage aging acceptable. 

The staff concludes that for LRA item 3.3.1-29, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.4 Cracking Due to Aggressive Chemical Attack, Leaching; and Changes in Material 

Properties Due to Aggressive Chemical Attack 

LRA Table 3.3-1, item 3.3.1-32 addresses reinforced concrete and asbestos cement piping 

components exposed to raw water which will be managed for cracking caused by aggressive 

chemical attack, leaching; and changes in material properties due to aggressive chemical 

attack. For the AMR item that cites generic note E, the LRA credits the External Surfaces 

Monitoring of Mechanical Components Program to manage the aging effect for asbestos 

cement splash panels. The GALL Report recommends GALL Report AMP XI.M20, 

“Open-Cycle Cooling Water System,” to ensure that these aging effects are adequately 

managed. GALL Report AMP XI.M20 recommends using routine inspections to manage this 

type of aging. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components Program is documented in SER Section 3.0.3.1.10. The staff noted that the 

External Surfaces Monitoring of Mechanical Components Program proposes to manage the 

aging of asbestos cement splash panels through the use of periodic visual inspections. In its 

review of components associated with item 3.3.1-32 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the External Surfaces 

Monitoring of Mechanical Components Program acceptable because the proposed program 

conducts visual inspections which are able to detect cracking of components.

The staff concludes that for LRA item 3.3.1-32, 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 General, Pitting, Crevice and Microbiologically-Influenced 

Corrosion; and Fouling that Leads to Corrosion

LRA Table 3.3-1, items 3.3.1-36 and 3.3.1-37, address steel and copper alloy piping, piping 

components, piping elements, and heat exchanger components and steel tanks exposed to raw 

water, which will be managed for loss of material due to general, pitting, crevice, and 

microbiologically influenced corrosion, and fouling that leads to corrosion. For the AMR items 

that cite generic note E, the LRA credits the Inspection of Internal Surfaces of Miscellaneous 

Piping and Ducting Components Program to manage the aging effect for carbon steel and 

copper alloy piping components and the Fire Water System Program to manage the aging effect 

for carbon steel fire water tanks. The GALL Report recommends GALL Report AMP XI.M20, 

“Open-Cycle Cooling Water System,” to ensure that this aging effect is adequately managed for 

safety-related service water system components, as defined by GL 89-13, “Service Water 

System Problems Affecting Safety-Related Equipment.” However, the staff noted that, because 
AGING MANAGEMENT REVIEW RESULTS

3-387

the subject components are not within the essential service water system, GALL Report 

AMP XI.M20 is not applicable. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces of Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 

that this program uses visual inspections performed during surveillances and maintenance 

activities when the surfaces are made available for inspection to manage aging. Also, at a 

minimum, in each 10-year period during the period of extended operation, a representative 

sample of the inspection population is inspected. The staff finds the applicant’s proposal to 

manage aging of carbon steel and copper alloy piping components using the Inspection of 

Internal Surfaces of Miscellaneous Piping and Ducting Components Program acceptable 

because the proposed program conducts opportunistic and periodic visual inspections that are 

capable of identifying loss of material prior to loss of intended function(s).

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.2.7. The staff noted that the program proposes to manage the aging of fire water 

tanks through the use of periodic visual inspections, as recommended by NFPA 25, “Standard 

for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems.” The 

staff noted that NFPA 25 Section 9.2.6 states that inspections for corrosion and coating 

degradation occur every 3 years. The staff also noted that the use of NFPA 25 is consistent 

with the guidance in LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water 

Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” In its review of carbon 

steel tanks associated with item 3.3.1-37, for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the Fire Water System Program 

acceptable because the proposed program conducts periodic visual inspections in accordance 

with NFPA 25 that are capable of identifying loss of material prior to loss of intended function(s).

The staff concludes that, for LRA items 3.3.1-36 and 3.3.1-37, 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 3.3.1-40, as amended by letters dated August 29, 2013, and 

January 16, 2014, addresses stainless steel piping, piping components, piping elements, heat 

exchanger components, tanks, and bolting exposed to raw water which will be managed for loss 

of material due to pitting and crevice corrosion and fouling that leads to corrosion. For the AMR 

item that cites generic note E, the LRA credits the Bolting Integrity Program to manage the 

aging effect for stainless steel closure bolting in the essential service water system. The GALL 

Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure 

that this aging effect is adequately managed for safety-related service water system 

components. GALL Report AMP XI.M20 recommends visual or nondestructive inspections to 

determine if corrosion is occurring, with a frequency in accordance with the applicant’s response 

to GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment.”

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.2. The staff noted that the program proposes to manage the aging of 

submerged bolting associated with the essential service water system pumps by (a) quarterly 

testing of the pumps, which may detect bolting degradation that would be manifested in 

abnormal pump performance, (b) visual inspections of a sample of the bolt heads during 

dewatering of the intake bays, which occurs every four refueling outages, and (c) visual 

inspection of the bolt threads when pump casings are disassembled during maintenance 
AGING MANAGEMENT REVIEW RESULTS

3-388

activities. In its review of stainless steel bolting associated with item 3.3.1-40, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Bolting Integrity Program acceptable because the frequent pump performance monitoring can 

reveal gross bolting failures that would prevent the pump from delivering flow and the visual 

inspections of the bolt heads and threads described above are capable of identifying loss of 

material prior to loss of bolting intended functions. 

The staff concludes that, for LRA item 3.3.1-40, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

LRA Table 3.3-1, item 3.3.1-71, as amended by letters dated August 29, 2013, and 

January 16, 2014, addresses stainless steel and aluminum piping, piping components, piping 

elements, and bolting exposed to fuel oil which will be managed for loss of material due to 

pitting, crevice, and microbiologically influenced corrosion. For the AMR item that cites generic 

note E, the LRA credits the Bolting Integrity Program to manage the aging effect for carbon steel 

closure bolting in the emergency diesel engine fuel oil storage and transfer system. The GALL 

Report recommends GALL Report AMP XI.M30, “Fuel Oil Chemistry,” and XI.M32, “One-Time 

Inspection,” to ensure that this aging effect is adequately managed. GALL Report AMPs XI.M30 

and XI.M32 recommend that loss of material be managed by monitoring and controlling fuel oil 

quality and verifying the effectiveness of the oil quality controls through visual inspection of 

components exposed to fuel oil.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.2. The staff noted that the program proposes to manage the aging of 

submerged bolting associated with the fuel oil storage tank transfer pumps by (a) periodic 

testing of the pumps, which may detect bolting degradation that would be manifested in 

abnormal pump performance, and (b) visual inspection of a sample of the bolting when the 

pumps are disassembled during maintenance activities, which is performed on a 10-year 

frequency. In its review of stainless steel bolting associated with item 3.3.1-71, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Bolting Integrity Program acceptable because the pump performance monitoring can reveal 

gross bolting failures that would prevent the pump from delivering flow and the visual 

inspections of the bolting during pump disassembly described above are capable of identifying 

loss of material prior to loss of bolting intended functions. 

The staff concludes that, for LRA item 3.3.1-71, 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 3.3.1-134, as amended by letters dated December 20, 2013, 

February 14, 2014, and April 23, 2014, addresses copper-alloy, steel, and stainless steel piping, 

piping components, and piping elements exposed to raw water which will be managed for loss 

of material due to general, pitting, crevice, and microbiologically influenced corrosion, and 

fouling that leads to corrosion. For the AMR items that cite generic note E, the LRA credits the 

External Surfaces Monitoring of Mechanical Components Program to manage aging effects for 

the internal and external surfaces of gray cast iron pumps. The GALL Report recommends 

GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” to ensure that these aging effects are adequately managed. GALL Report 
AGING MANAGEMENT REVIEW RESULTS

3-389

AMP XI.M38 recommends using visual inspections performed during surveillances and 

maintenance activities when the surfaces are made available for inspection to manage aging. 

In addition, GALL Report AMP XI.M38 also recommends that, at a minimum, in each 10-year 

period during the period of extended operation, a representative sample of the inspection 

population be inspected. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components Program is documented in SER Section 3.0.3.1.10. The staff noted that the 

External Surfaces Monitoring of Mechanical Components Program proposes to manage aging 

through the use of periodic visual inspections, conducted at least once every refueling cycle. In 

its review of components associated with item 3.3.1-134, for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the External Surfaces 

Monitoring of Mechanical Components Programs acceptable because the proposed program 

conducts periodic visual inspections at a greater frequency than the GALL-recommended AMP, 

and the inspections are capable of identifying loss of material prior to loss of intended 

function(s). The staff also noted that the internal and external environments are the same for 

the gray cast iron pumps in the service water system, which, in accordance with the GALL 

Report AMP XI.M36, allows the External Surfaces Monitoring of Mechanical Components 

Program to be credited for managing the loss of material from internal surfaces as well.

The staff concludes that for LRA item 3.3.1-134 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 3.3.1-135, as amended by letters dated August 29, 2013, 

December 20, 2013, and January 16, 2014, addresses carbon steel and stainless steel pumps 

and associated bolting exposed to waste water which will be managed for loss of material due 

to general (steel only) pitting, crevice, and microbiologically influenced corrosion. For the AMR 

items that cite generic note E, the LRA credits the Bolting Integrity Program to manage the 

aging effect for carbon steel and stainless steel closure bolting in the oily waste system and 

floor and equipment drains system. The GALL Report recommends GALL Report AMP XI.M36, 

“External Surfaces Monitoring of Mechanical Components,” to ensure that this aging effect is 

adequately managed. GALL Report AMP XI.M36 recommends that loss of material be 

managed by periodic visual inspections, conducted at least once per refueling outage, to detect 

corrosion and material wastage of metallic components.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.2. The staff noted that the program proposes to manage the aging of 

submerged bolting by (a) monitoring of the waste water sumps during operator rounds to 

confirm that they are being drained, which may detect bolting degradation that would be 

manifested in abnormal pump performance; (b) visual inspections of a sample of the bolt heads 

when the pumps are dewatered, but at least once every four refueling outages; and (c) visual 

inspection of the bolt threads when pump casings are disassembled during maintenance 

activities. In its review of stainless steel bolting associated with item 3.3.1-71, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Bolting Integrity Program acceptable because the pump performance monitoring can reveal 

gross bolting failures that would prevent the pump from delivering flow and the visual 

inspections of the bolt heads and threads described above are capable of identifying loss of 

material prior to loss of bolting intended functions. 
AGING MANAGEMENT REVIEW RESULTS

3-390

The staff concludes that for LRA item 3.3.1-135 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, and Crevice Corrosion 

LRA Table 3.3-1, item 3.3.1-54 addresses copper-alloy piping, piping components, and piping 

elements exposed to condensation which will be managed for loss of material due to general, 

pitting, and crevice corrosion. LRA Table 3.3-1, item 3.3.1-55 addresses steel compressed air 

system piping, piping components, and piping elements exposed to condensation which will be 

managed for loss of material due to general and pitting corrosion. LRA Table 3.3-1, 

item 3.3.1-56 addresses stainless steel compressed air system piping, piping components, and 

piping elements exposed to condensation which will be managed for loss of material caused by 

pitting and crevice corrosion. For the AMR items that cite generic note E, the LRA credits the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage the aging effect for copper-alloy piping and valves, steel piping and valves, and 

stainless steel flow orifice, piping, and valves. The GALL Report recommends GALL Report 

AMP XI.M24, “Compressed Air Monitoring,” to ensure that the aging effect is adequately 

managed. GALL Report AMP XI.M24 recommends monitoring of air quality and inspection of 

the internal surfaces of critical components to manage aging.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program proposes to manage loss of material of internal surfaces of various components 

exposed to condensation through the use of opportunistic visual inspections of the internal 

surfaces of the components. Based on its review of components associated with 

items 3.3.1-54, 3.3.1-55, and 3.3.1-56, for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program acceptable because the opportunistic 

visual inspections of the internal surfaces of the compressed air system components will ensure 

that if a loss of material is occurring, it will be detected prior to a loss of intended function 

(e.g., pressure boundary). Although GALL Report AMP XI.M24 also recommends monitoring of 

air quality, the components primarily responsible for achieving air quality (e.g., air dryers, after 

filters) are not within the scope of license renewal. Furthermore, the applicant does not assume 

that the air is dry rather it considers the environment to be “condensation.” Thus, monitoring of 

air quality for the purpose of aging management is unnecessary for copper-alloy, steel and 

stainless steel piping, piping components, and piping elements in the compressed air system. 

The staff concludes that for LRA items 3.3.1-54, 3.3.1-55, and 3.3.1-56, the applicant has 

demonstrated that the effects of aging for these components will be adequately managed so 

that the intended function(s) will be maintained consistent with the CLB during the period of

extended operation as required by 10 CFR 54.21(a)(3).

3.3.2.1.7 Hardening and Loss of Strength Due to Elastomer Degradation

LRA Table 3.3-1, item 3.3.1-76 addresses external and internal surfaces of elastomeric seals 

and components exposed to uncontrolled indoor air which will be managed for hardening and 

loss of strength due to elastomer degradation. The GALL Report recommends GALL Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to ensure that these 

aging effects are adequately managed. During its review of components associated with 
AGING MANAGEMENT REVIEW RESULTS

3-391

item 3.3.1-76, for which the applicant cited generic note A, the staff noted that the LRA credits 

the External Surfaces Monitoring of Mechanical Components Program to manage the aging 

effects for flexible hoses in LRA Table 3.4.2-5; however, the staff did not know if these hoses 

are sufficiently flexible such that manipulation of the external surface will result in inspection 

results which are representative of internal conditions. In addition, the staff lacked sufficient 

information on the use of the flexible hoses to be able to conclude that there are no 

contaminants that could be present that could result in degradation on the internal surfaces of 

the hose that would not be detected by an external examination. By letter dated 

August 6, 2012, the staff issued RAI 3.3.2.28-1, Parts (a), (b), and (c), requesting that the 

applicant:

(a) State the basis for why the expansion joints and flexible hoses in LRA Tables 3.3.2-3 

and 3.3.2-28, and the external surface of the flexible hoses in LRA Table 3.4.2-5, are not 

being managed for loss of material due to wear or propose how the aging effect will be 

managed.

(b) State whether the flexible hoses in LRA Table 3.4.2-5 are sufficiently flexible such that 

an external inspection would yield representative results of potential degradation of the 

internal surfaces. If they are not; state how hardening and loss of strength of the internal 

surfaces will be managed.

(c) State whether there are contaminants which could result in internal degradation of the 

flexible hoses in LRA Table 3.4.2-5, and if so, state how aging will be managed.

By letter dated September 6, 2012, the applicant provided its response to RAI 3.3.2.28-1, 

Parts (a), (b) and (c). The staff’s evaluation of the applicant response to Part (a) is documented 

in SER Section 3.3.2.1.10. In response to Part (b) the applicant amended LRA Table 3.4.2-5 to 

include the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program to manage hardening and loss of strength for the flexible hoses. In response to 

Part (c) the applicant stated that, “[t]here has been no plant operating experience at Callaway 

which would indicate that there are contaminants present for an internal environment of

condensation,” and “[t]he presence of contaminants or hard abrasive particles in the auxiliary 

feedwater system is extremely unlikely.” 

The staff finds the applicant’s response acceptable because: (a) the applicant will manage the 

internal surfaces of the flexible hoses for hardening and loss of strength with the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program, which includes 

opportunistic visual and physical manipulation inspections of elastomeric and polymeric 

materials that are capable of detecting hardening and loss of strength; and (b) the applicant’s 

response confirmed the staff’s understanding that typical air environments within the power 

block would not result in contaminants or abrasives entering flexible hoses for this system. The 

staff’s concerns described in RAI 3.3.2.28-1, Parts (b) and (c) are resolved.

The staff concludes that for LRA item 3.3.1-76, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.8 Loss of Material Due to General Corrosion 

LRA Table 3.3-1, item 3.3.1-78 addresses steel piping, ducting, and closure bolting exposed to 

indoor uncontrolled air, outdoor air, or condensation which will be managed for loss of material 
AGING MANAGEMENT REVIEW RESULTS

3-392

due to general corrosion. For the AMR items that cite generic note E, the LRA credits the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage the aging effect for steel piping, ductwork, and fans exposed to ventilation atmosphere 

(external). The AMR items also cite a plant-specific note which states that the subject 

components are enclosed within other components. The GALL Report recommends GALL 

Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to ensure that 

these aging effects are adequately managed. Further, GALL Report AMP XI.M36 also 

recommends using visual inspections of external surfaces conducted during periodic plant 

system inspections and walkdowns to manage aging for this component group.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program proposes to manage loss of material for the components exposed to ventilation 

atmospheres using periodic, opportunistic visual inspections performed during surveillance and 

maintenance activities whenever the internal surfaces are made accessible for inspection. In its 

review of components associated with item 3.3.1-78 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program acceptable because: (a) 

the subject components are enclosed within other components such that access to the external 

surface requires the surface be made accessible and (b) the proposed program includes visual 

inspections performed during surveillance and maintenance activities that are capable of 

identifying loss of material consistent with the GALL Report recommendations.

The staff concludes that for LRA item 3.3.1-78, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.9 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3-1, item 3.3.1-79 addresses copper-alloy piping, piping components, and piping 

elements exposed to condensation (external) which will be managed for loss of material due to 

general, pitting, and crevice corrosion. For the AMR items that cite generic note E, the LRA, as 

amended by letter dated August 21, 2012, credits the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program or the Open-Cycle Cooling Water 

Program to manage the aging effect for piping and heat exchanger components exposed to 

plant indoor air (external) or ventilation atmosphere (internal or external). The AMR items that 

credit the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program to manage aging also cite a plant-specific note which states that the subject 

components are enclosed within another component. The AMR items that credit the 

Open-Cycle Cooling Water Program to manage aging also cite a plant-specific note that states 

reduction of heat transfer and loss of material for the air-side of safety-related air-to-water heat 

exchangers is managed by the Open-Cycle Cooling Water System Program consistent with the 

Callaway commitments to GL 89-13. The GALL Report recommends GALL Report AMP 

XI.M36, “External Surfaces Monitoring,” to ensure that these aging effects are adequately 

managed. GALL Report AMP XI.M36 recommends using periodic visual inspections of the 

external surfaces of components to manage aging for metallic components. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 
AGING MANAGEMENT REVIEW RESULTS

3-393

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program proposes to manage the aging of metallic components through the use of visual 

inspections. In its review of components associated with item 3.3.1-79, for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable because the program includes visual inspections of components which are capable 

of detecting loss of material and the subject components are either located inside other 

components, or exposed internally to an environment where condensation could occur. 

The staff’s evaluation of the applicant’s Open-Cycle Cooling Water Program is documented in 

SER Section 3.0.3.2.3. The staff noted that the Open-Cycle Cooling Water Program proposes 

to manage the aging of the air side of safety-related air-to-water heat exchanger components 

through the use of visual inspections and, if necessary, cleaning. In its review of components 

associated with item 3.3.1-79, for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the Open-Cycle Cooling Water Program acceptable 

because the program includes visual inspections and cleaning of the air side of heat exchanger 

components, which are capable of detecting loss of material and is consistent with the 

applicant’s existing commitments associated with GL 89-13. 

The staff concludes that for LRA item 3.3.1-79, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.10 Loss of Material Due to Wear

LRA Table 3.3.1, item 3.3.1-82 addresses external surfaces of elastomeric seals and 

components exposed to uncontrolled indoor air which will be managed for loss of material due 

to wear. The GALL Report recommends GALL Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” to ensure that these aging effects are adequately 

managed. During its review of components associated with item 3.3.1-82, for which the 

applicant cited generic note A, the staff noted that the LRA credits the External Surfaces 

Monitoring of Mechanical Components Program to manage the aging effects for expansion 

joints and flexible hoses in LRA Tables 3.3.2-23, 3.3.2-28, and 3.4.2-5; however, these items 

are being managed for hardening and loss of strength, but not loss of material caused by wear. 

GALL Report Section IX.F defines wear “as the removal of surface layers caused by relative 

motion between two surfaces or under the influence of hard, abrasive particles. Wear occurs in 

parts that experience intermittent relative motion, frequent manipulation, or in clamped joints 

where relative motion is not intended, but may occur because of a loss of the clamping force.” It 

was unclear to the staff why the expansion joints and flexible hoses in LRA Tables 3.3.2-23 and 

3.3.2-28, and the external surface of the flexible hoses in LRA Table 3.4.2-5, are not being 

managed for loss of material caused by wear due to possible relative motion, frequent 

manipulation, or loss of the clamping force over time. By letter dated August 6, 2012, the staff 

issued RAI 3.3.2.28-1, Part (a) requesting that the applicant state the basis for why the 

expansion joints and flexible hoses are not being managed for loss of material caused by wear, 

or propose how the aging effect will be managed. RAI 3.3.2.28-1 also included Parts (b) and 

(c). The staff evaluation of the applicant response to RAI 3.3.2.28-1, Parts (b) and (c) is 

documented in SER Section 3.3.2.1.7.

In its response to RAI 3.3.2.28-1, Part (a) dated September 6, 2012, the applicant amended 

LRA Tables 3.3.2-23, 3.3.2-28, and 3.4.2-5 to use the External Surfaces Monitoring of 
AGING MANAGEMENT REVIEW RESULTS

3-394

Mechanical Components Program to manage loss of material for flexible hoses and expansion 

joints exposed to plant indoor air.

The staff finds the applicant’s response acceptable because the applicant will manage the 

external surfaces of the flexible hoses and expansion joints for loss of material caused by wear 

with the External Surfaces Monitoring of Mechanical Components Program, which includes 

visual examinations that are capable of detecting loss of material caused by wear. The staff’s 

concern described in RAI 3.3.2.28-1, Part (a) is resolved.

The staff concludes that for LRA item 3.3.1-82, 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 Loss of Material Due to General, Pitting, Crevice and Microbiologically-Influenced 

Corrosion

LRA Table 3.3-1, item 3.3.1-90 addresses internal surfaces of steel ducting and components 

exposed to condensation, which will be managed for loss of material due to general, pitting, 

crevice corrosion, and (for drip pans and drain lines) MIC. For the AMR items that cite generic 

note E, the LRA credits the Fire Protection Program to manage the aging effect for carbon steel 

(galvanized) dampers exposed to ventilation atmosphere (internal). The GALL Report 

recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” to ensure that these aging effects are adequately managed. 

GALL Report AMP XI.M38 recommends using periodic opportunistic visual inspections 

performed during surveillances and maintenance activities when the surfaces are made 

available for inspection to manage aging.

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.6. The staff noted that the Fire Protection Program proposes to manage aging 

of carbon steel dampers through the use of periodic visual inspections of not less than 

10 percent of the fire dampers at least once every 18 months. In its review of components 

associated with item 3.3.1-90 for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the Fire Protection Program acceptable because 

the program includes periodic visual inspections which are capable of detecting loss of material 

and are performed on a frequency consistent with the GALL Report recommendations for fire 

dampers. 

The staff concludes that for LRA item 3.3.1-90, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.12 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3-1, item 3.3.1-92 addresses aluminum piping, piping components, and piping 

elements exposed to condensation (internal), which will be managed for loss of material due to 

pitting and crevice corrosion. For the AMR item that cites generic note E, the LRA, as amended 

by letter dated August 21, 2012, credits the Open-Cycle Cooling Water System Program to 

manage the aging effect for aluminum HVAC heat exchangers in the control building. The 

GALL Report recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to ensure that these aging effects are 
AGING MANAGEMENT REVIEW RESULTS

3-395

adequately managed. GALL Report AMP XI.M38 recommends using opportunistic visual 

inspections to manage aging. 

The staff’s evaluation of the applicant’s Open-Cycle Cooling Water System Program is 

documented in SER Section 3.0.3.2.3. The staff noted that the Open-Cycle Cooling Water 

System Program proposes to manage the aging of the air-side of safety-related air-to-water 

heat exchangers exposed to condensation (internal) through the use of periodic inspection and 

cleaning of heat exchangers with a heat transfer intended function, which is performed in 

accordance with Callaway commitments to NRC Generic Letter 89-13 to confirm heat transfer 

capabilities. In its review of components associated with item 3.3.1-92, for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Open-Cycle Cooling Water System Program acceptable because the activities associated with 

the applicant’s Open-Cycle Cooling Water System Program are consistent with the Callaway 

commitments to the requirements in Generic Letter 89-13 which identify periodic heat transfer 

testing or inspection and cleaning of heat exchangers with a heat transfer intended function as 

an appropriate method to detect aging effects associated with heat exchangers.

LRA Table 3.3-1, item 3.3.1-94 addresses stainless steel ducting and components exposed to 

condensation, which will be managed for loss of material due to pitting and crevice corrosion. 

For the AMR items that cite generic note E, the LRA, as amended by letter dated 

August 21, 2012, credits the Open-Cycle Cooling Water System Program to manage the aging 

effect for stainless steel HVAC in the auxiliary and fuel buildings, and auxiliary feedwater room 

heat exchangers. The GALL Report recommends GALL Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” to ensure that these aging 

effects are adequately managed. GALL Report AMP XI.M38 recommends using opportunistic 

visual inspections to manage aging. 

The staff’s evaluation of the applicant’s Open-Cycle Cooling Water System Program is 

documented in SER Section 3.0.3.2.3. The staff noted that the Open-Cycle Cooling Water 

System Program proposes to manage the aging of the air-side of safety-related air-to-water 

heat exchangers exposed to ventilation atmosphere through the use of periodic inspection and 

cleaning of heat exchangers with a heat transfer intended function, which is performed in 

accordance with NRC’s GL 89-13 to confirm heat transfer capabilities. In its review of 

components associated with item 3.3.1-94, for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the Open-Cycle Cooling Water System 

Program acceptable because the activities associated with the applicant’s Open-Cycle Cooling 

Water System Program are consistent with the Callaway commitments, as revised by letter 

dated July 16, 2007, to the requirements in GL 89-13 which identify periodic heat transfer 

testing or inspection and cleaning of heat exchangers with a heat transfer intended function as 

an appropriate method to detect aging effects associated with heat exchangers.

The staff concludes that for LRA items 3.3.1-92 and 3.3.1-94, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation 

as required by 10 CFR 54.21(a)(3).

3.3.2.1.13 Loss of Material Due to General, Pitting and Crevice Corrosion

LRA Table 3.3-1, item 3.3.1-97, addresses steel piping, piping components, piping elements, 

reactor coolant pump oil collection system tanks, reactor coolant pump oil collection system 

piping, tubing, and valve bodies exposed to lubricating oil which will be managed for loss of 

material due to general, pitting, and crevice corrosion. For the AMR items that cite generic note 
AGING MANAGEMENT REVIEW RESULTS

3-396

E, the LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program to manage the aging effect for carbon steel and galvanized carbon steel 

piping and valves. The GALL Report recommends the GALL Report AMP XI.M39, “Lubricating 

Oil Analysis,” to ensure that these aging effects are adequately managed. GALL Report 

AMP XI.M39 recommends sampling for water and a particle count to detect evidence of 

contamination by moisture or excessive corrosion to manage aging. The applicant cited 

plant-specific note 1 which states the following: 

[c]omponents associated with the reactor coolant pump oil collection system do 

not normally contain lubricating oil. Any oil or water that is found during operator 

visual inspections is documented and reviewed. If there is an accumulation of 

liquid, it is removed and discarded during the outage inspection. The Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components [P]rogram 

(B2.1.23) inspects the piping, valves and tank for loss of material to maintain 

these components' intended function. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program proposes to manage the aging of carbon steel and galvanized carbon steel piping and 

valves through the use of mechanical and visual inspections. In its review of components 

associated with item 3.3.1-97 for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program acceptable because the components proposed to be 

managed under item 3.3.1-97 are part of the applicant’s equipment and floor drainage system 

which collects drainage and leak-off from various systems and is not a closed system utilized 

solely for lubricating oil; therefore, sampling for water and particulate count to manage aging 

would be ineffective. The visual and mechanical inspections proposed in the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components program will provide actual 

detection of loss of material in the affected components and is therefore acceptable. 

The staff concludes that for LRA Item 3.3.1-97, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.14 Loss of material due to pitting, crevice, and microbiologically influenced corrosion

LRA Table 3.3-1, item 3.3.1-100, addresses stainless steel piping, piping components, and 

piping elements exposed to lubricating oil (internal) which will be managed for loss of material 

due to pitting, crevice, and MIC. For the AMR items that cite generic note E, the LRA credits the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage the aging effect for stainless steel flexible hoses, piping, tanks, tubing, and valves. The 

GALL Report recommends the GALL Report AMP XI.M39, “Lubricating Oil Analysis,” to ensure 

that these aging effects are adequately managed. GALL Report AMP XI.M39 recommends 

sampling for water and a particle count, to detect evidence of contamination by moisture or 

excessive corrosion, to manage aging. The applicant cited plant-specific note 1 which states 

the following: 

[c]omponents associated with the reactor coolant pump oil collection system do 

not normally contain lubricating oil. Any oil or water that is found during operator 

visual inspections is documented and reviewed. If there is an accumulation of 
AGING MANAGEMENT REVIEW RESULTS

3-397

liquid, it is removed and discarded during the outage inspection. The Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components [P]rogram 

(B2.1.23) inspects the piping, valves and tank for loss of material to maintain 

these components' intended function. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Proram proposes to manage the aging of stainless steel flexible hoses, piping, tanks, tubing, 

and valves. In its review of components associated with item 3.3.1-100 for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable because the components proposed to be managed under item 3.3.1-100 are part of 

the applicant’s equipment and floor drainage system which collects drainage and leak off from 

various systems and is not a closed system utilized solely for lubricating oil; therefore, sampling 

for water and particle count to manage aging would be ineffective. The visual and mechanical 

inspections proposed in the Inspection of Internal Surfaces In Miscellaneous Piping and Ducting 

Components Program will provide actual detection of loss of material in the affected 

components and is therefore acceptable.

The staff concludes that for LRA item 3.3.1-100, 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).

3.3.2.1.15 No Aging Effects Requiring Management

LRA Table 3.3-1, item 3.3.1-120 addresses stainless steel piping, piping components, and 

piping elements exposed to air-indoor uncontrolled, air with borated water leakage, concrete, 

air-dry, or gas and states that there are no AERM and no AMP is proposed. The GALL Report 

states that there are no AERM and no AMP is proposed for this component group. 

During its review of components associated with item 3.3.1-120 for which the applicant cited 

generic note A, the staff noted that the LRA states that there are no AERM and no AMP is 

proposed for stainless steel expansion joints exposed internally to borated water leakage in LRA 

Table 3.3.2-2. However, the GALL Report environment of air with borated water leakage is 

usually referred to as an external environment. The GALL Report recommends that stainless 

steel components exposed to treated borated water or condensation be managed for loss of 

material. It was unclear to the staff how the components exposed internally to borated water 

leakage are configured such that exposure to borated water leakage can occur, but the leakage 

does not accumulate such that the environment becomes borated water or condensation. By 

letter dated August 16, 2012, the staff issued RAI 3.2.1.063-1 requesting that the applicant 

explain the configuration of the components exposed internally to borated water leakage and 

how accumulation of the borated water leakage is prevented. If accumulation of borated water 

leakage can occur; the staff requested the applicant to explain why the components have no 

AERM. 

In its response dated September 20, 2012, the applicant stated that the expansion joint is part of 

the sleeve surrounding the fuel transfer tube. The applicant stated that the external surface of 

the expansion joint and sleeve are exposed to borated water during refueling operations, but the 

interior surfaces are dry because the sleeve is welded to the transfer tube. The applicant 
AGING MANAGEMENT REVIEW RESULTS

3-398

revised LRA Table 3.3.2-2 to indicate that the internal environment for the expansion joint and 

the external environment for the fuel transfer tube is plant indoor air. The staff finds the 

applicant’s response acceptable because the applicant described the configuration of the 

expansion joint and its relation to the fuel transfer tube , and clarified that normal internal 

environment is plant indoor air. Consistent with the GALL Report for this material and 

environment combination, no aging effects are expected; therefore, no aging management 

program is needed. The staff’s concern described in RAI 3.2.1.063-1 is resolved.

The staff concludes that for LRA item 3.3.1-120, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.16 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3-1, item 3.3.1-125 was added to the LRA by letter dated December 19, 2012, in 

response to the issuance of LR-ISG-2011-01, Revision 1, “Aging Management of Stainless 

Steel Structures and Components in Treated Borated Water.” Item 3.3.1-125 addresses steel 

(with stainless steel cladding) and stainless steel spent fuel storage racks, piping, piping 

components, and piping elements exposed to treated water and treated borated water. For the 

AMR items that cite generic notes A or C, the LRA credits the Water Chemistry and One-Time 

Inspection Programs to manage loss of material caused by pitting and crevice corrosion for 

stainless steel components in treated borated water. The GALL Report, as revised by 

LR-ISG-2011-01, recommends GALL Report AMPs XI.M2, “Water Chemistry,” and XI.M32, 

“One-Time Inspection,” to ensure that these aging effects are adequately managed. The staff 

confirmed the consistency with the GALL Report and, therefore, finds the applicant’s proposal to 

manage aging acceptable.

The staff concludes that for LRA item 3.3.1-125, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.17 Wall Thinning Due to Erosion

LRA Table 3.3-1, item 3.3.1-126, addresses piping, piping components, and piping elements 

made from any material exposed to treated water, treated borated water, or raw water which will 

be managed for wall thinning due to erosion. For the AMR item that cites generic note E, the 

LRA credits the Open-Cycle Cooling Water System program to manage the wall thinning due to 

erosion for carbon steel piping exposed to raw water. The GALL Report, as revised by 

LR-ISG-2012-01, recommends GALL Report AMP XI.M17, “Flow-Accelerated Corrosion,” to 

ensure that this aging effect is adequately managed. GALL Report AMP XI.M17 recommends 

using periodic ultrasonic or radiographic examinations to monitor and trend wall thinning in order 

to manage aging. 

The staff’s evaluation of the applicant’s Open-Cycle Cooling Water System program is 

documented in SER Section 3.0.3.2.3. The staff noted that the Open-Cycle Cooling Water 

System program proposes to manage the aging of carbon steel piping through the use of 

ultrasonic testing inspections in conjunction with scans using low-frequency electromagnetic 

technique measurements. In its review of components associated with item 3.3.1-126 for which 

the applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using 

the Open-Cycle Cooling Water System program acceptable because it uses similar inspection 
AGING MANAGEMENT REVIEW RESULTS

3-399

techniques as those recommended by the Flow-Accelerated Corrosion program, and these 

techniques are capable of detecting wall thinning due to erosion.

The staff concludes that for LRA item 3.3.1-126, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.18 Hardening and Loss of Strength Due to Elastomer Degradation; and Loss of Material 

Due to Erosion

LRA Table 3.3-1, item 3.3.1-32a, as amended by letter dated February 14, 2014 (LRA 

Amendment 31), addresses elastomer seals and components exposed to raw water which will 

be managed for hardening, loss of strength, and loss of material. For the AMR items that cite 

generic note E, the LRA credits the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program to manage the aging effects for elastomer expansion joints 

exposed to raw water in the circulating water system. The GALL Report recommends GALL 

Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure these effects are 

adequately managed for safety-related service water system components, as defined by 

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment.” However, 

the staff noted that, because the subject components are safety-related service water system 

components, GALL Report AMP XI.M20 is not applicable.

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. The staff noted 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program proposes to manage the aging of elastomer expansion joints through the use of visual 

inspections augmented by physical manipulation, performed during surveillances and 

maintenance activities when the surfaces are made available. Also, at a minimum, in each 

10-year period during the period of extended operation, a representative sample of the 

inspection population is inspected. In its review of components associated with item 3.3.1-32a, 

for which the applicant cited generic note E, the staff finds the applicant’s proposal to manage 

aging using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the program proposed in the LRA visual examination 

and physical manipulation, which are capable of identifying hardening and loss of strength of 

elastomer components, consistent with GALL Report guidance.

3.3.2.1.19 Loss of Coating Integrity

LRA Table 3.3-1, item 3.3.1-128a, as amended by letter dated April 23, 2014, addresses carbon 

steel heat exchangers, strainers, piping, and tanks, (with coating or lining), exposed to raw 

water which will be managed for loss of coating integrity. For the AMR items that cite generic 

note E, the LRA credits the Open-Cycle Cooling Water System, Fire Water System, Fuel Oil 

Chemistry, or Inspection of Internal Surfaces in Miscellaneous Piping Ducting Components 

Programs to manage this aging effect.

The staff’s evaluation of the acceptability of using the Open-Cycle Cooling Water System, Fire 

Water System, Fuel Oil Chemistry, and Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Programs to manage loss of coating integrity is documented in SER 

Section 3.0.3.4. 
AGING MANAGEMENT REVIEW RESULTS

3-400

The staff concludes that for LRA item 3.3.1-128a 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).

3.3.2.1.20 Loss of Material due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, and Fouling that Leads to Corrosion

By letter dated August 2, 2013, the applicant amended LRA Table 3.3-1, item 3.3.1-64 to 

address steel and copper alloy, piping, piping components, and piping elements exposed to raw 

water which will be managed for loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion, and fouling that leads to corrosion. The amendment 

contains an AMR item that cites generic note E. The LRA amendment credits the External 

Surfaces Monitoring of Mechanical Components program to manage the aging effect for gray 

cast iron pumps exposed on the external surfaces to raw water. 

By letter dated February 14, 2014, the applicant amended the LRA to delete the fire water 

storage tank sump pump and the fire protection pumphouse valve pit pumps from the scope of 

license renewal as a part of the NFPA 805 changes to the fire protection program. Deleting 

these components resulted in deletion of the applicant’s corresponding alternative proposal to 

the GALL Report guidance. 

The staff concludes that for LRA Item 3.3.1-64, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.3.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the auxiliary systems components and provides information concerning 

how it will manage the following aging effects:

• cumulative fatigue damage

• cracking due to SCC and cyclic loading

• cracking due to SCC

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• QA for aging management of nonsafety-related components

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 it 

adequately addressed the issues further evaluated. In addition, the staff reviewed the 

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.3.2.2. The 

staff’s review of the applicant’s further evaluation follows.

3.3.2.2.1 Cumulative Fatigue Damage

LRA Section 3.3.2.2.1, associated with LRA Table 3.3-1, items 3.3.1-1 and 3.3.1-2, addresses 

how steel cranes structural girders exposed to air and steel and stainless steel piping, piping 
AGING MANAGEMENT REVIEW RESULTS

3-401

components, piping elements, and heat exchanger components exposed to air-indoor 

uncontrolled, treated borated water or treated water are being managed for cumulative fatigue 

damage. The applicant addressed the further evaluation criteria of the SRP-LR by stating that 

fatigue is a TLAA, as defined in 10 CFR 54.3, and is required to be evaluated in accordance 

with 10 CFR 54.21(c). The applicant stated that fatigue TLAA identified for ASME Code 

Section III, Class 2 and 3, and ANSI B31.1 piping are discussed in LRA Section 4.3, and the 

evaluation of crane load cycles as a TLAA is discussed in LRA Section 4.7.

The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR Section 3.3.2.2.1, which 

states that fatigue of these auxiliary system components is a TLAA as defined in 10 CFR 54.3, 

and that these TLAAs are to be evaluated in accordance with the TLAA acceptance criteria 

requirements in 10 CFR 54.21(c)(1). The staff reviewed the applicant’s AMR items and 

determined that the AMR results are consistent with the recommendations of the GALL Report 

and SRP-LR for managing cumulative fatigue damage in steel cranes structural girders exposed 

to air-indoor uncontrolled (external), and steel and stainless steel piping, piping components, 

piping elements, and heat exchanger components exposed to air-indoor uncontrolled, treated 

borated water or treated water, except as identified below.

The staff also identified that the applicant did not include the applicable AMR items in LRA 

Table 2s (Tables 3.x.2-y) for the TLAAs associated with fatigue of certain non-Class 1 piping 

such as those in the boron recycle system and condensate system. Therefore, by letter dated 

September 6, 2012, as part of RAI 4.3-10, the staff requested the applicant to justify this 

discrepancy. In its response dated October 11, 2012, the applicant revised LRA Section 3.3 to 

include additional AMR items for those SSCs subject to an AMR in accordance with 

10 CFR 54.21(a)(1), that were not identified previously. The details of RAI 4.3-10 and the staff’s 

evaluation of the applicant’s response are documented in SER Section 4.3.5.2. 

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.3.2.2.1 criteria. For those items that apply to LRA Section 3.3.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Sections 4.3 and 4.7 document the staff’s review of 

the applicant’s evaluation of the TLAA for these components.

3.3.2.2.2 Cracking Due to Stress Corrosion Cracking and Cyclic Loading

LRA Section 3.3.2.2.2, associated with LRA Table 3.3-1, item 3.3.1-3, addresses stainless steel 

components in the letdown heat exchanger that are exposed to treated borated water which will 

be managed for cracking due to SCC and cyclic loading by the Water Chemistry and One-Time 

Inspection Programs. The criteria in SRP-LR Section 3.3.2.2.2 states that cracking caused by 

SCC and cyclic loading could occur for stainless steel PWR non-regenerative heat exchanger 

components exposed to treated borated water greater than 60 °C (140°F) in the CVC system. 

The SRP-LR also states that the Water Chemistry Program relies on monitoring and control of 

water chemistry to manage aging effects of cracking due to SCC; however, control of water 

chemistry does not preclude cracking due to SCC and cyclic loading. The GALL Report 

recommends that a plant-specific AMP be evaluated to confirm that cracking does not occur, 

and that an acceptable confirmation program includes temperature and radioactivity monitoring 

of the shell side water and eddy current testing of the tubes. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that plant instrumentation continuously 

monitors temperature and radioactivity of the shell-side for the letdown (non-regenerative) heat 
AGING MANAGEMENT REVIEW RESULTS

3-402

exchanger. The applicant also stated that the sample selection for the One-Time Inspection 

Program will include heat exchanger tubes with similar materials, environment, and fluid 

temperatures, and that eddy current testing will be performed. 

The staff’s evaluations of the applicant’s Water Chemistry and One-Time Inspection Programs 

are documented in SER Sections 3.0.3.1.2 and 3.0.3.1.8, respectively. In its review of 

components associated with item 3.3.1-3, the staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the above programs is 

acceptable because the Water Chemistry Program maintains contaminants at a level to 

minimize cracking. In addition, the staff notes that the applicant’s sample selection for the 

One-Time Inspection Program, which will confirm the effectiveness of the Water Chemistry 

Program, will include comparable heat exchanger tubes and will perform eddy current testing 

which can detect cracking. The staff also notes that plant instrumentation continuously monitors 

temperature and radioactivity, which is consistent with the recommendations in the SRP-LR and 

GALL Report.

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 items associated with LRA Section 3.3.2.2.2, the 

staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately manages so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CRF 54.21(a)(3).

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking

LRA Section 3.3.2.2.3, which is associated with LRA Table 3.3-1, item 3.3.1-4, addresses 

stainless steel piping, piping components, piping elements and tanks exposed to air - outdoor. 

The applicant stated this item is not applicable because there are no in-scope stainless steel 

piping, piping components, piping elements or tanks exposed to air - outdoor in the auxiliary 

systems. The staff reviewed the applicant’s FSAR and LRA Sections 3.3 and 2.3.3 and finds 

that no in-scope stainless steel piping, piping components, piping elements or tanks exposed to 

air-outdoor are present in the auxiliary systems. Therefore, the staff finds the applicant’s 

determination acceptable.

3.3.2.2.4 Loss of Material Due to Cladding Breach

LRA Section 3.3.2.2-4, associated with LRA Table 3.3-1, item 3.3.1-5, addresses loss of 

material due to cladding breach in steel with stainless steel or nickel-alloy cladding pump 

casings exposed to treated borated water. The applicant stated that this item is not applicable 

because there are no in-scope steel with stainless steel or nickel-alloy cladding pump casings 

exposed to treated borated water in the CVC system. The staff reviewed LRA Sections 2.3.3 

and 3.3, and FSAR Section 9.0 SP and finds that no in-scope steel with stainless steel or 

nickel-alloy cladding pump casings exposed to treated borated water are present in the auxiliary 

systems. Therefore, the staff finds the applicant’s determination acceptable.

3.3.2.2.5 Loss of Material due to Pitting and Crevice Corrosion

LRA Section 3.3.2.2.5, associated with LRA Table 3.3-1, item 3.3.1-6, addresses stainless steel 

piping, piping components, piping elements or tanks exposed to air - outdoor. The applicant 

stated this item is not applicable because there are no in-scope stainless steel piping, piping 

components, piping elements or tanks exposed to air - outdoor in the auxiliary systems. The 

staff reviewed the applicant’s FSAR and LRA Sections 3.3 and 2.3.3 finds that no in-scope 
AGING MANAGEMENT REVIEW RESULTS

3-403

stainless steel piping, piping components, piping elements, or tanks exposed to air-outdoor are 

present in the auxiliary systems. Therefore, the staff finds the applicant’s determination 

acceptable.

3.3.2.2.6 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA Program.

3.3.2.2.7 Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of aging management 

programs.

3.3.2.2.8 Loss of Material Due to Recurring Internal Corrosion

LRA Section 3.3.2.2.8, as modified through LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation,” is 

associated with LRA Table 3.3-1, item 3.3.1-127, and addresses loss of material due to 

recurring internal corrosion in metallic piping, piping components, and tanks exposed to raw 

water or waste water. By letter dated October 7, 2013, the staff issued RAI 3.0.3-1 requesting 

the applicant to address issues related to recurring internal corrosion that are addressed by the 

new SRP-LR Section 3.3.2.2.8. In its response dated December 20, 2013, the applicant stated 

that the current Open-Cycle Cooling Water System program includes activities to address 

recurring internal corrosion due to microbiologically influenced corrosion (MIC) in the essential 

service water system. The applicant stated that the Open-Cycle Cooling Water System 

program uses a low-frequency electromagnetic technique to screen large areas to detect 

changes in piping wall thickness, then follows up with ultrasonic measurements to determine 

pipe wall thickness for any thinned areas. The applicant further stated that the Open-Cycle 

Cooling Water System program performs opportunistic visual inspections whenever the 

essential service water system is opened for maintenance. The response also includes a 

commitment to select an inspection technique to identify internal pipe wall degradation due to 

MIC for a one-time inspection of buried carbon steel piping, which is representative of other 

accessible carbon steel piping segments. Although not included in its discussion for this 

section, in the response to RAI 3.0.3-1, item a, the applicant reiterated the staff’s position that 

noted that SER Section 3.0.3.2.7 addresses how recurring internal corrosion due to MIC will be 

managed on the internal surfaces of the fire water system piping.

The staff finds the applicant’s response acceptable because, as documented in SER 

Sections 3.0.3.2.3 and 3.0.3.2.7, the staff evaluated the alternate examination methods, 

augmented inspections, and additional trending parameters in the existing Open-Cycle Cooling 

Water System and Fire Water System programs. Based on the above finding, in its review of 

components associated with item 3.3.1-127, the staff also finds that the applicant has met the

further evaluation criteria, and the applicant’s proposal to manage the effects of aging using the 

Open-Cycle Cooling Water System and Fire Water System programs is acceptable to address 

recurring internal corrosion due to MIC. The staff noted that its independent search of 

plant-specific operating experience during the AMP audit did not identify instances that 

warranted augmenting any other AMPs that manage components in auxiliary systems to 

address internal corrosion.
AGING MANAGEMENT REVIEW RESULTS

3-404

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.3.2-1 through 3.3.2-28, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.3.2-1 through 3.3.2-28, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an 

AMR item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the AMR item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the AMR 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 during the period of extended operation. 

The staff’s evaluation is discussed in the following sections.

3.3.2.3.1 Auxiliary Systems—Summary of Aging Management Evaluation—Fuel Storage and 

Handling System—LRA Table 3.3.2-1

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the 

fuel storage and handling system component groups.

Carbon Steel Crane Components Exposed to Plant Indoor Air (External). In LRA Table 3.3.2-1, 

the applicant stated that there is a TLAA for the carbon steel crane components exposed to 

plant indoor air (external), which cites generic note H. The staff confirmed that there is a TLAA, 

as documented in LRA Section 4.7.1, for this component and material. The staff’s evaluation of 

the TLAA for steel cranes components is documented in SER Section 4.7.1.

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).

3.3.2.3.2 Auxiliary Systems—Summary of Aging Management Evaluation—Fuel Pool Cooling 

and Cleanup System—LRA Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the 

fuel pool cooling and cleanup system component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the fuel pool cooling and cleanup system component groups are 

consistent with the GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-405

3.3.2.3.3 Auxiliary Systems—Summary of Aging Management Evaluation—Cranes, Hoists, and 

Elevators—LRA Table 3.3.2-3

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the 

cranes, hoists, and elevators component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the cranes, hoists, and elevators component groups are consistent 

with the GALL Report.

3.3.2.3.4 Auxiliary Systems—Summary of Aging Management Evaluation—Essential Service 

Water System—LRA Table 3.3.2-4 

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the 

ESW system component groups.

HDPE Piping Exposed to Plant Indoor Air. In LRA Table 3.3.2-4, the applicant stated that for 

HDPE piping exposed to plant indoor air, there is no aging effect and no AMP is proposed. The 

AMR item cites generic note G. The AMR item cites plant specific note 3 which states the 

following:

HDPE components in a plant indoor air environment are not exposed to an 

aggressive chemical environment that would concentrate contaminants and 

degrade HDPE chemical and mechanical properties. HDPE is not exposed to 

ozone, ionizing radiation or a UV source (sunlight or fluorescent light) that would 

result in aging. Operating temperatures do not exceed 140 °F. HDPE 

components in a plant indoor air environment have no aging effects requiring 

aging management.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material and environment combination. The staff finds the 

applicant’s proposal acceptable based on its review of GALL Report items AP-268 and SP-152, 

which state that polyvinyl chloride (PVC) piping exposed to uncontrolled indoor air has no 

AERM or recommended AMP. The HDPE piping’s resistance to aging effects is similar to that 

of PVC, except HDPE is more susceptible to sunlight UV exposure. Given that the applicant 

has stated that the piping is not exposed to ionizing radiation or a UV source (sunlight or 

fluorescent light), the staff finds the applicant’s determination that there are no AERM 

acceptable.

Cellulose Silica Cement Splash Panels Exposed to Raw Water (External). In LRA 

Table 3.3.2-4, the applicant stated that cellulose silica cement splash panels exposed to raw 

water (external) will be managed for cracking and changes in material properties by the External 

Surfaces Monitoring of Mechanical Components Program. The AMR item cites generic note F. 

The staff reviewed the associated item in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The GALL Report, in item VII.C1.AP-155, states that 

asbestos cement piping exposed to raw water is susceptible to cracking and changes in 

material properties. The staff noted that asbestos cement and cellulose silica cement are both 

cementitous materials that can be used in the same applications and can be expected to 

experience the same aging effects. Based on its review of the GALL Report, the staff finds that 

the applicant has identified all credible aging effects for this component, material, and 

environment combination.
AGING MANAGEMENT REVIEW RESULTS

3-406

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components Program is documented in SER Section 3.0.3.1.10. The staff finds the applicant’s 

proposal to manage aging using the External Surfaces Monitoring of Mechanical Components 

acceptable because the program includes visual inspections which are capable of detecting 

cracking and changes in material properties in cementitious materials.

HDPE Piping Exposed to an Underground Environment. In LRA Table 3.3.2-4, the applicant 

stated that HDPE piping in an underground vault and potentially exposed to an underground 

environment will be managed for cracking, blistering and change in color by the Buried and 

Underground Piping and Tanks Program. The AMR item originally cited generic note G. 

However, in its letter dated December 20, 2013, the applicant stated that use of the Buried and 

Underground Piping and Tanks Program in this instance is consistent with item 3.3.1-133 of the 

GALL Report, as revised by License Renewal Interim Staff Guidance LR-ISG-2012-02, “Aging 

Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation,” citing generic note A. The staff reviewed the associated items in 

the LRA, and the staff finds the applicant’s proposal acceptable because it is consistent with the 

GALL Report, as revised by LR-ISG-2012-02.

HDPE Piping Exposed to a Buried Environment. In LRA Table 3.3.2-4, the applicant stated 

there is a TLAA for HDPE piping exposed to a buried environment which cite generic note H. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.7, for this component 

and material. The staff’s evaluation of the TLAA for HDPE piping is documented in SER 

Section 4.7.8.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.5 Auxiliary Systems—Summary of Aging Management Evaluation—Service Water 

System—LRA Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the 

service water system component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the service water system component groups are consistent with the GALL 

Report.

3.3.2.3.6 Auxiliary Systems—Summary of Aging Management Evaluation—Reactor Makeup 

Water System—LRA Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the 

reactor makeup water system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the reactor makeup water system component groups are consistent 

with the GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-407

3.3.2.3.7 Auxiliary Systems—Summary of Aging Management Evaluation—Component Cooling 

Water System—LRA Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the 

CCW system component groups. The staff’s review did not identify any AMR items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for the CCW system component groups are consistent with the GALL Report.

3.3.2.3.8 Auxiliary Systems—Summary of Aging Management Evaluation—Compressed Air 

System—LRA Table 3.3.2-8`

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the 

compressed air system component groups. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the compressed air system component groups are consistent with 

the GALL Report.

3.3.2.3.9 Auxiliary Systems—Summary of Aging Management Evaluation—Nuclear Sampling 

System—LRA Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the 

nuclear sampling system component groups. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the nuclear sampling system component groups are consistent with 

the GALL Report.

3.3.2.3.10 Auxiliary Systems—Summary of Aging Management Evaluation—Chemical and 

Volume Control System—LRA Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for 

the CVC system component groups.

Carbon Steel Heat Exchangers Exposed to Closed Cycle Cooling Water. In LRA 

Table 3.3.2-10, the applicant stated there is a TLAA for carbon steel heat exchangers exposed 

to closed cycle cooling water which cite generic note H. The staff confirmed that there is a 

TLAA, as documented in LRA Section 4.3.8, for this component and material. The staff’s 

evaluation of the fatigue TLAA for ASME Code Class 2 heat exchangers is documented in SER 

Section 4.3.8.2.

Calcium Silicate Insulation Exposed to Plant Indoor Air. In LRA Tables 3.3.2-10 and 3.3.2-22, 

as amended by letter dated December 19, 2012, the applicant stated that for calcium silicate 

insulation exposed to plant indoor air, there is no aging effect and no AMP is proposed. The 

AMR items originally cited generic note J, indicating that neither the component nor the material 

and environment are evaluated in the GALL Report.

The staff noted that, subsequent to the applicant’s December 19, 2012, LRA amendment, 

License Renewal Interim Staff Guidance (LR-ISG) LR-ISG-2012-02, “Aging Management of 

Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under 

Insulation,” was issued, adding SRP-LR item 3.4.1-64 to manage reduced thermal insulation 

resistance for calcium silicate insulation exposed to plant air using GALL Report AMP XI.M36, 

“External Surfaces Monitoring of Mechanical Components.” In LRA Amendment 28, dated 

December 20, 2013, the applicant revised this item to manage reduced thermal insulation 
AGING MANAGEMENT REVIEW RESULTS

3-408

resistance with the External Surfaces Monitoring of Mechanical Components Program, 

consistent with LR-ISG-2012-02. Therefore, the staff finds the applicant’s proposal to manage 

aging acceptable. 

3.3.2.3.11 Auxiliary Systems—Summary of Aging Management Evaluation—Control Building 

HVAC System—LRA Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for 

the control building HVAC system component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the control building HVAC system component groups are 

consistent with the GALL Report.

3.3.2.3.12 Auxiliary Systems—Summary of Aging Management Evaluation—Essential Service 

Water Pumphouse HVAC System—LRA Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for 

the ESW pumphouse HVAC system component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the essential service water pumphouse HVAC system component 

groups are consistent with the GALL Report.

3.3.2.3.13 Auxiliary Systems—Summary of Aging Management Evaluation—Auxiliary Building 

HVAC System—LRA Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for 

the auxiliary building HVAC system component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the auxiliary building HVAC system component groups are 

consistent with the GALL Report.

3.3.2.3.14 Auxiliary Systems—Summary of Aging Management Evaluation—Fuel Building 

HVAC System—LRA Table 3.3.2-14 

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for 

the fuel building HVAC system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the fuel building HVAC system component groups are consistent 

with the GALL Report.

3.3.2.3.15 Auxiliary Systems—Summary of Aging Management Evaluation—Miscellaneous 

Building HVAC System—LRA Table 3.3.2-15

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for 

the miscellaneous building HVAC system component groups. The staff’s review did not identify 

any AMR items with notes F through J, indicating that the combinations of component type, 

material, environment, and AERM for the miscellaneous building HVAC system component 

groups are consistent with the GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-409

3.3.2.3.16 Auxiliary Systems—Summary of Aging Management Evaluation—Diesel Generator 

Building HVAC System—LRA Table 3.3.2-16

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for 

the diesel generator building HVAC system component groups. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the diesel generator building HVAC system 

component groups are consistent with the GALL Report.

3.3.2.3.17 Auxiliary Systems—Summary of Aging Management Evaluation—Radwaste Building 

HVAC System—LRA Table 3.3.2-17

The applicant removed this system from within the scope of license renewal by letter dated 

February 14, 2014. The staff reviewed this removal as discussed in SER Section 2.3.3.17 and 

finds it acceptable; therefore, no AMR items are associated with this system for review.

3.3.2.3.18 Auxiliary Systems—Summary of Aging Management Evaluation—Turbine Building 

HVAC System—LRA Table 3.3.2-18 

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for 

the turbine building HVAC system component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the turbine building HVAC system component groups are 

consistent with the GALL Report.

3.3.2.3.19 Auxiliary Systems—Summary of Aging Management Evaluation—Containment 

Cooling System—LRA Table 3.3.2-19

The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for 

the containment cooling system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the containment cooling system component groups are consistent 

with the GALL Report.

3.3.2.3.20 Auxiliary Systems—Summary of Aging Management Evaluation—Fire Protection 

System—LRA Table 3.3.2-20

The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for 

the fire protection system component groups.

PVC Piping Exposed to Waste Water. In LRA Table 3.3.2-20, the applicant stated that for PVC 

piping exposed to waste water, there is no aging effect and no AMP is proposed. The AMR 

item cites generic note G. The AMR item cites plant-specific note 2 which states, “PVC in a

wastewater environment is unaffected by water, concentrated alkalis, non-oxidizing acids, oils, 

ozone, or humidity changes. PVC in a waste water environment is not exposed to direct 

sunlight or ionizing radiation. Therefore PVC in a wastewater environment has no aging effect.”

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. The staff noted that 

PCV Pipe – Design and Installation – Manual of Water Supply Practices, M23, American Water 

Works Association, Second Edition, 2002, states, in part, the following:
AGING MANAGEMENT REVIEW RESULTS

3-410

PVC and PVCO pipes are resistant to almost all types of corrosion-both chemical 

and electrochemical-that are experienced in underground piping systems. 

Because PVC is a nonconductor, galvanic and electrochemical effects are 

nonexistent in PVC piping systems. PVC pipe cannot be damaged by 

aggressive waters or corrosive soils. ...

PVC pipe is nearly totally resistant to biological attack. Biological attack can be 

described as degradation or deterioration caused by the action of living 

microorganisms or macroorganisms. ...

PVC pipe is well suited to applications where abrasive conditions are anticipated. 

Appendix A, Chemical Resistance Tables of this document lists PVC as generally resistant to 

chemicals up to 140 °F, such as bleach (12.5 percent active chlorine), potassium hydroxide, 

sodium hydroxide, kerosene, hydrochloric acid, hydrogen peroxide (90 percent), sea water, 

soaps, and sulfuric acid (70 percent). The staff also noted that PVC Formulary, G Wypych, 

Chem Tec Publishing, 2009 states, “[a]s a general rule, PVC is not resistant to polar solvents 

but very resistant to acids, bases, salts, alcohols, esters, and hydrocarbons.” Based on its 

review of the LRA and the above documents, the staff finds the applicant’s proposal that there’s 

no AERM for PVC piping exposed to waste water acceptable because, (a) PVC is resistant to 

acids and bases which could be found in fire protection waste water piping, (b) polar solvents 

(e.g., toluene, turpentine, acetone) would not be expected to be present in this piping, and (c) 

PVC piping is not exposed to direct sunlight or ionizing radiation.

On the basis of its review, the staff concludes for items in LRA Table 3.3.2-20 with no AERMs, 

that the applicant has appropriately evaluated the material and environment combinations not 

addressed in the GALL Report, and 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).

3.3.2.3.21 Auxiliary Systems—Summary of Aging Management Evaluation—Emergency Diesel 

Engine Fuel Oil Storage and Transfer System—LRA Table 3.3.2-21

The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for 

the emergency diesel engine fuel oil storage and transfer system component groups. 

Carbon Steel Closure Bolting Exposed to an Underground Environment. In LRA Table 3.3.2-21, 

as amended by letter dated August 29, 2013, the applicant stated that carbon steel closure 

bolting exposed to an underground environment will be managed for loss of preload by the 

Bolting Integrity Program. The AMR item cites generic note G. 

The staff reviewed the associated item in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of

material for this component, material, and environment combination in another AMR item in LRA 

Table 3.3.2-21. Based on its review of the GALL Report, which recommends that steel bolting 

exposed to outdoor air (a similar environment to the underground environment due to having the 

potential for exposure to moisture) be managed for loss of material and loss of preload, the staff 

finds that the applicant has identified all credible aging effects for this component, material, and 

environment combination. The staff noted that high-strength carbon steel bolts (actual yield 

strengths of at least 150 ksi) can also be susceptible to cracking; however, LRA Section B2.1.8 

states that no high-strength bolting is used in pressure-retaining joints within the scope of the 

Bolting Integrity Program.
AGING MANAGEMENT REVIEW RESULTS

3-411

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.2. The staff noted that the program proposes to manage loss of preload by 

preventive actions, including the use of appropriate lubricants and sealants, selection of bolting 

material with appropriate yield strength, and application of appropriate preload. The staff finds 

the applicant’s proposal to manage aging using the Bolting Integrity Program acceptable 

because the preventive actions described above minimize the potential for loss of preload, 

consistent with the GALL Report guidance. 

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).

3.3.2.3.22 Auxiliary Systems—Summary of Aging Management Evaluation—Standby Diesel 

Generator Engine System—LRA Table 3.3.2-22

The staff reviewed LRA Table 3.3.2-22, which summarizes the results of AMR evaluations for 

the standby diesel generator engine system component groups.

Calcium Silicate Insulation Exposed to Plant Indoor Air. The staff’s evaluation for calcium 

silicate insulation exposed to plant indoor air, for which the applicant cited no aging effect and 

no proposed AMP, but subsequently revised to be consistent with the GALL Report, is 

documented in SER Section 3.3.2.3.10.

Carbon Steel Piping Exposed to Diesel Exhaust. In LRA Table 3.3.2-22, the applicant stated 

there is a TLAA for carbon steel piping exposed to diesel exhaust which cite generic note H. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.5, for this 

component and material. The staff’s evaluation of the fatigue TLAA for ANSI B31.1 and ASME 

Code Section III Class 2 and 3 piping is documented in SER Section 4.3.5.2.

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).

3.3.2.3.23 Auxiliary Systems—Summary of Aging Management Evaluation—EOF and TSC 

Diesels, Security Building System—LRA Table 3.3.2-23

The staff reviewed LRA Table 3.3.2-23, which summarizes the results of AMR evaluations for 

the EOF and TSC diesels, security building system component groups.

Elastomeric Flexible Hoses and Expansion Joints Exposed to Fuel Oil (Internal) and 

Demineralized Water (Internal). In LRA Tables 3.3.2-23 and 3.3.2-28, the applicant stated that 

the internal surfaces of elastomeric flexible hoses and expansion joints exposed to fuel oil and 

demineralized water will be managed for hardening and loss of strength by the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR items 

cite generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 
AGING MANAGEMENT REVIEW RESULTS

3-412

material, and environment description. The staff noted that the applicant’s identified aging 

effects and its aging management approach is consistent with the GALL Report guidance for 

elastomers exposed to wet environments. GALL Report item VII.C2.AP-259 recommends that 

elastomeric components exposed to closed-cycle cooling water be managed for hardening and 

loss of strength with GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components.” The staff also noted that another potential 

aging effect, loss of material due to wear or erosion, would not be expected to be applicable to 

the internal surfaces of the subject hoses and expansion joints. The internal surfaces of these 

components are not expected to experience relative motion contact that could lead to wear, and 

the fuel oil and demineralized water environments are controlled to minimize particulates. 

Based on its review of GALL Report Sections IX.E, “Selected Use of Terms for Describing and 

Standardizing Aging Effects,” and IX.F, “Significant Aging Mechanisms,” which identify 

hardening, loss of strength, and loss of material as the only applicable aging effects for 

elastomeric components, the staff finds that the applicant has identified all credible aging effects 

for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. 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 this program 

includes opportunistic visual and physical manipulation inspections of elastomeric materials that 

are capable of detecting hardening and loss of strength.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.24 Auxiliary Systems—Summary of Aging Management Evaluation—Liquid Radwaste 

System—LRA Table 3.3.2-24

The staff reviewed LRA Table 3.3.2-24, which summarizes the results of AMR evaluations for 

the liquid radwaste system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the liquid radwaste system component groups are consistent with 

the GALL Report.

3.3.2.3.25 Auxiliary Systems—Summary of Aging Management Evaluation—Decontamination 

System—LRA Table 3.3.2-25

The staff reviewed LRA Table 3.3.2-25, which summarizes the results of AMR evaluations for 

the decontamination system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the decontamination system component groups are consistent with 

the GALL Report.

3.3.2.3.26 Auxiliary Systems—Summary of Aging Management Evaluation—Oily Waste 

System—LRA Table 3.3.2-26

The staff reviewed LRA Table 3.3.2-26, which summarizes the results of AMR evaluations for 

the oily waste system component groups.
AGING MANAGEMENT REVIEW RESULTS

3-413

Carbon Steel and Stainless Steel Closure Bolting Exposed to Waste Water. In LRA Tables 

3.3.2-26 and 3.3.2-27, the applicant stated that carbon steel and stainless steel closure bolting 

exposed to waste water will be managed for loss of preload by the Bolting Integrity Program. 

The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of 

material for this component, material, and environment combination in other AMR items in LRA 

Tables 3.3.2-26 and 3.3.2-27. Based on its review of the GALL Report, which recommends that 

steel and stainless steel bolting exposed to raw water (a similar environment to waste water) be

managed for loss of material and loss of preload, the staff finds that the applicant has identified 

all credible aging effects for this component, material, and environment combination. The staff 

noted that high-strength carbon steel bolts (actual yield strengths of at least 150 ksi) can also be 

susceptible to cracking; however, LRA Section B2.1.8 states that no high-strength bolting is 

used in pressure-retaining joints within the scope of the Bolting Integrity Program.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.2. The staff noted that the program proposes to manage the aging of 

submerged bolting by preventive actions, including proper torqueing of bolts and checking for 

uniformity of gasket compression. In addition, the insights into loss of preload are obtained by 

(a) monitoring of the waste water sumps during operator rounds to confirm that they are being 

drained, which may detect bolt loosening that would be manifested in abnormal pump 

performance, and (b) visual inspections of the bolts when the pumps are dewatered, but at least 

once every four refueling outages. The staff finds the applicant’s proposal to manage aging 

using the Bolting Integrity Program acceptable because the preventive actions minimize the 

potential for loss of preload, and the pump performance monitoring and visual inspections are 

capable of detecting loss of preload prior to loss of intended functions. 

Gray Cast Iron Valves (Internally) and Pumps (Internally and Externally) Exposed to Waste 

Water. In LRA Table 3.3.2-26, the applicant stated that gray cast iron valves, internally 

exposed, and pumps internally and externally exposed to waste water will be managed for loss 

of material by the Selective Leaching Program. The AMR items previously cited generic note G 

and plant-specific note 3, which states that gray cast iron SSCs with surfaces exposed to waste 

water are subject to loss of material due to selective leaching. However, in a letter dated 

December 20, 2013, the applicant revised this section to state that the use of the Selective 

Leaching Program is consistent with item 3.3.1-72 of the GALL Report, as revised by License 

Renewal Interim Staff Guidance LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire 

Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,” citing generic 

note B. The staff reviewed the associated items in the LRA, and the staff finds the applicant’s 

proposal acceptable because it is consistent with the GALL Report, as revised by 

LR-ISG-2012-02.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).
AGING MANAGEMENT REVIEW RESULTS

3-414

3.3.2.3.27 Auxiliary Systems—Summary of Aging Management Evaluation—Floor and 

Equipment Drainage System—LRA Table 3.3.2-27

The staff reviewed LRA Table 3.3.2-27, which summarizes the results of AMR evaluations for 

the floor and equipment drainage system component groups. 

Carbon Steel and Stainless Steel Closure Bolting Exposed to Waste Water. In LRA 

Table 3.3.2-27, the applicant stated that carbon steel and stainless steel closure bolting 

exposed to waste water will be managed for loss of preload by the Bolting Integrity Program. 

The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of 

material for this component, material, and environment combination in other AMR items in LRA 

Tables 3.3.2-26 and 3.3.2-27. Based on its review of the GALL Report, which recommends that 

steel and stainless steel bolting exposed to raw water (a similar environment to waste water) be 

managed for loss of material and loss of preload, the staff finds that the applicant has identified 

all credible aging effects for this component, material, and environment combination. The staff 

noted that high-strength carbon steel bolts (actual yield strengths of at least 150 ksi) can also be 

susceptible to cracking; however, LRA Section B2.1.8 states that no high-strength bolting is 

used in pressure-retaining joints within the scope of the Bolting Integrity Program.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.2. The staff noted that the program proposes to manage the aging of 

submerged bolting by preventive actions, including proper torqueing of bolts and checking for 

uniformity of gasket compression. In addition, the insights into loss of preload are obtained by 

(a) monitoring of the waste water sumps during operator rounds to confirm that they are being 

drained, which may detect bolt loosening that would be manifested in abnormal pump 

performance, and (b) visual inspections of the bolts when the pumps are dewatered, but at least 

once every four refueling outages. The staff finds the applicant’s proposal to manage aging 

using the Bolting Integrity Program acceptable because the preventive actions minimize the 

potential for loss of preload, and the pump performance monitoring and visual inspections are 

capable of detecting loss of preload prior to loss of intended functions. 

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).

3.3.2.3.28 Auxiliary Systems—Summary of Aging Management Evaluation—Miscellaneous 

Systems in scope ONLY for Criterion 10 CFR 54.4(a)(2)—LRA Table 3.3.2-28

The staff reviewed LRA Table 3.3.2-28, which summarizes the results of AMR evaluations for 

the miscellaneous systems in scope only for criterion 10 CFR 54.4(a)(2) component groups.

Elastomeric Flexible Hoses Exposed to Demineralized Water (Internal). The staff’s evaluation 

for elastomeric flexible hoses exposed to demineralized water (internal), which will be managed 

for hardening and loss of strength by the Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program, is documented in SER Section 3.3.2.3.23.
AGING MANAGEMENT REVIEW RESULTS

3-415

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).

3.3.2.3.29 Auxiliary Systems—Summary of Aging Management Evaluation—Circulating Water 

System—LRA Table 3.3.2-29

The staff reviewed LRA Table 3.3.2-29, as amended by letter dated February 14, 2014, which 

summarizes the results of AMR evaluations for the circulating water system component groups. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the circulating water 

system component groups are consistent with the GALL Report.

3.3.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the auxiliary systems components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4 Aging Management of Steam and Power Conversion 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 

systems:

• main turbine system

• main steam supply system

• main feedwater system

• steam generator blowdown system

• auxiliary feedwater system

• condensate storage and transfer system

3.4.1 Summary of Technical Information in the Application

LRA Section 3.4 provides AMR results for the steam and power conversion systems 

components and component groups. In LRA Table 3.4-1, “Summary of Aging Management 

Programs in Chapter VIII of NUREG-1801 for Steam and Power Conversion System,” the 

applicant provided a summary comparison of its AMRs to those evaluated in the GALL Report 

for steam and power conversion systems components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. 

The applicant’s review of industry operating experience included a review of the GALL Report 

and operating experience issues identified since the issuance of the GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-416

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient information 

to demonstrate that the effects of aging for steam and power conversion system components 

within the scope of license renewal and subject to an AMR will be adequately managed so that 

the intended function(s) will remain 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 confirm 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 confirm that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. Details of the 

staff’s evaluation are discussed in SER Section 3.4.2.1.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff’s evaluations 

are documented in SER Section 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 

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 that the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR items and the plant’s operating experience to confirm 

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.

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 that the applicant indicated are consistent with the GALL 

Report and require no further evaluation. Another approach, documented in SER 

Section 3.4.2.2, discusses the staff’s review of AMR results for components that the applicant 

indicated are consistent with the GALL Report and for which further evaluation is recommended. 

A third approach, documented in SER Section 3.4.2.3, discusses the staff’s review of AMR 

results for components that the applicant indicated are not consistent with or not addressed in 

the GALL Report. The staff’s review of AMPs credited to manage or monitor aging effects of the 

steam and power conversion system components is documented in SER Section 3.0.3.
AGING MANAGEMENT REVIEW RESULTS

3-417

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

the GALL Report

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel Piping, piping 

components, and 

piping elements 

exposed to Steam or 

Treated water 

(3.4.1-1)

Cumulative 

fatigue damage 

caused by 

fatigue

Fatigue is a 

time-limited aging 

analysis (TLAA) to be 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1)).

Yes TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.2.1)

Stainless steel 

Piping, piping 

components, and 

piping elements; 

tanks exposed to 

Air – outdoor 

(3.4.1-2)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External 

Surfaces 

Monitoring of 

Mechanical 

Components 

Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.2.2)

Stainless steel 

Piping, piping 

components, and 

piping elements; 

tanks exposed to 

Air – outdoor 

(3.4.1-3)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External 

Surfaces 

Monitoring of 

Mechanical 

Components 

and 

Aboveground 

Metallic Tanks 

(for CST only)

Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.2.3)

Steel External 

surfaces, Bolting 

exposed to Air with 

borated water 

leakage (3.4.1-4)

Loss of material 

caused by boric 

acid corrosion

Chapter XI.M10, 

“Boric Acid Corrosion”

No Boric Acid 

Corrosion

Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.1.1)

Steel Piping, piping 

components, and 

piping elements 

exposed to Steam, 

Treated water 

(3.4.1-5)

Wall thinning 

caused by 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerat

ed Corrosion

Consistent with the 

GALL Report

Steel, Stainless 

Steel Bolting 

exposed to Soil 

(3.4.1-6)

Loss of preload Chapter XI.M18, 

“Bolting Integrity “

No Not applicable Not applicable to 

Callaway(see SER 

Section 3.4.2.1.1)

High-strength steel 

Closure bolting 

exposed to Air with 

steam or water 

leakage (3.4.1-7)

Cracking 

caused by cyclic 

loading, stress 

corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-418

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel; stainless steel 

Bolting, Closure 

bolting exposed to 

Air – outdoor 

(External), Air –

indoor, uncontrolled 

(External) (3.4.1-8)

Loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting 

Integrity

Consistent with the 

GALL Report

Steel Closure bolting 

exposed to Air with 

steam or water 

leakage (3.4.1-9)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Copper alloy, Nickel 

alloy, Steel; stainless 

steel, Steel; 

stainless steel 

Bolting, Closure 

bolting exposed to 

Any environment, Air 

– outdoor (External), 

Air – indoor, 

uncontrolled 

(External) (3.4.1-10)

Loss of preload 

caused by 

thermal effects, 

gasket creep, 

and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting 

Integrity

Consistent with the 

GALL Report

Stainless steel 

Piping, piping 

components, and 

piping elements, 

Tanks, Heat 

exchanger 

components 

exposed to Steam, 

Treated water 

>60 °C (>140 °F) 

(3.4.1-11)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel; stainless steel 

Tanks exposed to 

Treated water 

(3.4.1-12)

Loss of material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1) 

Steel Piping, piping 

components, and 

piping elements 

exposed to Treated 

water (3.4.1-13)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements, 

PWR heat 

exchanger 

components 

exposed to Steam, 

Treated water 

(3.4.1-14)

Loss of material 

caused by 

general, pitting, 

and crevice

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-419

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel Heat 

exchanger 

components 

exposed to Treated 

water (3.4.1-15)

Loss of material 

caused by 

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1) 

Copper-alloy, 

Stainless steel, 

Nickel alloy, 

Aluminum Piping, 

piping components, 

and piping elements, 

Heat exchanger 

components and 

tubes, PWR heat 

exchanger 

components 

exposed to Treated 

water, Steam 

(3.4.1-16)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper-alloy Heat 

exchanger tubes 

exposed to Treated 

water (3.4.1-17)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.4.2.1.1)

Copper alloy, 

Stainless steel Heat 

exchanger tubes 

exposed to Treated 

water (3.4.1-18)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel, Steel 

Heat exchanger 

components 

exposed to Raw 

water (3.4.1-19)

Loss of material 

caused by 

general, pitting, 

crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Copper-alloy, 

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to Raw 

water (3.4.1-20)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-420

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel Heat 

exchanger 

components 

exposed to Raw 

water (3.4.1-21)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Stainless steel, 

Copper alloy, Steel 

Heat exchanger 

tubes, Heat 

exchanger 

components 

exposed to Raw 

water (3.4.1-22)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to 

Closed-cycle cooling 

water >60 °C 

(>140 °F) (3.4.1-23)

Cracking 

caused by 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Steel Heat 

exchanger 

components 

exposed to 

Closed-cycle cooling 

water (3.4.1-24)

Loss of material 

caused by 

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Steel Heat 

exchanger 

components 

exposed to 

Closed-cycle cooling 

water (3.4.1-25)

Loss of material 

caused by 

general, pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Stainless steel Heat 

exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to 

Closed-cycle cooling 

water (3.4.1-26)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Copper-alloy Piping, 

piping components, 

and piping elements 

exposed to 

Closed-cycle cooling 

water (3.4.1-27)

Loss of material 

caused by 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-421

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel, Stainless 

steel, Copper alloy 

Heat exchanger 

components and 

tubes, Heat 

exchanger tubes 

exposed to 

Closed-cycle cooling 

water (3.4.1-28)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Steel Tanks exposed 

to Air – outdoor 

(External) (3.4.1-29)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Steel, Stainless 

Steel, Aluminum 

Tanks (within the 

scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to Soil or 

Concrete, or the 

following external 

environments 

air-outdoor, 

air-indoor 

uncontrolled, moist 

air, condensation 

(3.4.1-30)

Loss of material 

due to general

(steel only), 

pitting, and 

crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only)

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

Stainless steel, 

Aluminum Tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to Soil or 

Concrete or the 

following external 

environments 

air-outdoor, 

air-indoor 

uncontrolled, moist 

air, condensation 

(3.4.1-31)

Loss of material 

caused by 

pitting, and 

crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

Gray cast iron 

Piping, piping 

components, and 

piping elements 

exposed to Soil 

(3.4.1-32)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-422

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Gray cast iron, 

Copper-alloy (>15% 

Zn or >8% Al) 

Piping, piping 

components, and 

piping elements 

exposed to Treated 

water, Raw water, 

Closed-cycle cooling 

water (3.4.1-33)

Loss of material 

caused by 

selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Steel External 

surfaces exposed to 

Air – indoor, 

uncontrolled

(External), Air –

outdoor (External), 

Condensation 

(External) (3.4.1-34)

Loss of material 

caused by 

general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Air –

outdoor (3.4.1-35)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to Air –

outdoor (Internal) 

(3.4.1-36)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, 

"Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components"

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to 

Condensation 

(Internal) (3.4.1-37)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel Piping, piping 

components, and 

piping elements 

exposed to Raw 

water (3.4.1-38)

Loss of material 

caused by 

general, pitting, 

crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to 

Condensation 

(Internal) (3.4.1-39)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-423

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel Piping, piping 

components, and 

piping elements 

exposed to 

Lubricating oil 

(3.4.1-40)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel Heat 

exchanger 

components 

exposed to 

Lubricating oil 

(3.4.1-41)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Aluminum Piping, 

piping components, 

and piping elements 

exposed to 

Lubricating oil 

(3.4.1-42)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Copper-alloy Piping, 

piping components, 

and piping elements 

exposed to 

Lubricating oil 

(3.4.1-43)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Stainless steel 

Piping, piping 

components, and 

piping elements, 

Heat exchanger 

components 

exposed to 

Lubricating oil 

(3.4.1-44)

Loss of material 

caused by 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Aluminum Heat 

exchanger 

components and 

tubes exposed to 

Lubricating oil 

(3.4.1-45)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Stainless steel, 

Steel, Copper alloy 

Heat exchanger 

tubes exposed to 

Lubricating oil 

(3.4.1-46)

Reduction of 

heat transfer 

caused by 

fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Lubricating Oil 

Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel (with coating or 

wrapping), nickel 

alloy, Piping, piping 

components, and 

piping elements; 

tanks exposed to 

Soil or Concrete 

(3.4.1-47)

Loss of material 

caused by 

general, pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried and 

Underground 

Piping and 

Tanks

Consistent with the 

GALL Report 
AGING MANAGEMENT REVIEW RESULTS

3-424

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless Steel, 

nickel alloy, Bolting 

exposed to Soil 

(3.4.1-48)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Stainless steel, 

nickel alloy, Piping, 

piping components, 

and piping elements 

exposed to Soil or 

Concrete (3.4.1-49)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Steel Bolting 

exposed to Soil 

(3.4.1-50)

Loss of material 

caused by 

general, pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Underground 

Stainless Steel, 

nickel alloy and 

Steel Piping, piping 

components, and 

piping elements 

(3.4.1-50a)

Loss of material 

caused by 

general (steel 

only), pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicaple to 

Callaway (see SER 

Section 3.4.2.1.1)

Steel Piping, piping 

components, and 

piping elements 

exposed to Concrete 

(3.4.1-51)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, and 

2) plant OE indicates 

no degradation of the 

concrete

No, if 

conditions 

are met.

Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Aluminum Piping, 

piping components, 

and piping elements 

exposed to Gas, Air 

– indoor, 

uncontrolled 

(Internal/External) 

(3.4.1-52)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Copper-alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.4.1-53)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-425

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to gas, air –

indoor, uncontrolled 

(external) (3.4.1-54)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Glass piping 

elements exposed to 

lubricating oil, air –

outdoor, 

condensation 

(internal/external), 

raw water, treated 

water, air with 

borated water 

leakage, gas, 

closed-cycle cooling 

water, air – indoor, 

uncontrolled 

(external) (3.4.1-55)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Nickel alloy Piping, 

piping components, 

and piping elements 

exposed to Air –

indoor, uncontrolled 

(External) (3.4.1-56)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Nickel alloy, PVC 

Piping, piping 

components, and 

piping elements 

exposed to Air with 

borated water 

leakage, Air –

indoor, uncontrolled, 

Condensation 

(Internal) (3.4.1-57)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external), concrete, 

gas, air – indoor, 

uncontrolled 

(internal) (3.4.1-58)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to air –

indoor controlled 

(external), gas 

(3.4.1-59)

None None NA - No 

AEM or 

AMP

None Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-426

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Any material, piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.4.1-60)

Wall thinning

due to erosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.1.1)

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

waste water 

(3.4.1-61)

Loss of material 

due to recurring 

internal 

corrosion

A plant-specific aging 

management program 

is to be evaluated to 

address recurring 

internal corrosion

Yes, plantspecific 

(see 

subsection 

3.4.2.2.6)

Not applicable Not applicable to 

Callaway (see SER 

Section 3.4.2.2.6)

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water (3.4.1-62)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

Metallic piping, 

piping components, 

heat exchangers, 

tanks with Service 

Level III 

(augmented) internal 

coatings exposed to 

closed-cycle cooling 

water, raw water, 

treated water, 

treated borated 

water, or lubricating 

oil (3.4.1-62a)

Loss of coating 

integrity due to 

blistering, 

cracking, 

flaking, peeling, 

or physical 

damage

Chapter XI.M42, 

“Service Level III 

(augmented) 

Coatings Monitoring 

and Maintenance 

Program”

No Not applicable Consistent with the 

GALL Report (see 

SER 

Section 3.4.2.1.1)

Insulated steel, 

stainless steel, 

copper alloy, 

aluminum, or copper 

alloy (>15% Zn) 

piping, piping 

components, and 

tanks exposed to 

condensation,

air-outdoor 

(3.4.1-63)

Loss of material 

due to general 

(steel, and 

copper alloy), 

pitting, or 

crevice 

corrosion, and 

cracking due to 

stress corrosion 

cracking 

(aluminum, 

stainless steel 

and copper alloy 

(>15% Zn) only)

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” (for 

tanks only)

No External 

Surfaces 

Monitoring of 

Mechanical 

Components or 

Aboveground 

Metallic Tanks 

(for tanks only)

Consistent with the 

GALL Report

Jacketed calcium 

silicate or fiberglass 

insulation in an 

air-indoor 

uncontrolled or 

air-outdoor 

environment 

(3.4.1-64)

Reduced 

thermal 

insulation 

resistance due 

to moisture 

intrusion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring of 

Mechanical 

Components

Consistent with the 

GALL Report (see 

SER 

Sections 3.2.2.3.6, 

3.3.2.3.10, and 

3.4.2.3.2)
AGING MANAGEMENT REVIEW RESULTS

3-427

Component Group 

(SRP-LR Item No.)

Aging Effect or 

Mechanism

Recommended AMP 

in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Jacketed 

Foamglas® (glass 

dust) insulation in an

air-indoor 

uncontrolled or 

air-outdoor 

environment 

(3.4.1-65)

Reduced 

thermal 

insulation 

resistance due 

to moisture 

intrusion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report (see 

SER 

Section 3.4.2.1.2)

3.4.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the steam and power conversion systems components:

• Aboveground Metallic Tanks

• Bolting Integrity

• Buried and Underground Piping and Tanks

• External Surfaces Monitoring of Mechanical Components

• Flow-Accelerated Corrosion

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

• Lubricating Oil Analysis

• One-Time Inspection

• Water Chemistry

LRA Tables 3.4.2-1 through 3.4.2-6 summarize the AMRs for the steam and power conversion 

systems components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine if the plant-specific components in these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR item. 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–E, which indicate how the AMR was consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these items to confirm consistency with the GALL Report and the validity of 

the AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these items to confirm consistency with the 

GALL Report and confirmed that it had reviewed and accepted the identified exceptions to the 

GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report and whether the AMR was valid for the 

site-specific conditions.
AGING MANAGEMENT REVIEW RESULTS

3-428

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff audited these 

items to confirm consistency with the GALL Report and determined whether the AMR item of 

the different component applied to the component under review and whether the AMR was valid 

for the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the AMP identified in the GALL Report. The staff audited these items to 

confirm consistency with the GALL Report and confirmed whether the AMR item of the different 

component was applicable to the component under review. The staff confirmed whether it had 

reviewed and accepted the exceptions to the GALL Report AMPs. 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 item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff audited these AMR 

items to confirm consistency with the GALL Report and determined whether the identified AMP 

would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions.

The staff 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 confirm that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs. The staff’s evaluation follows.

3.4.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.4-1, items 3.4.1-6, 3.4.1-7, 3.4.1-12, 3.4.1-15, 3.4.1-17, 3.4.1-19 through 

3.4.1-29, 3.4.1-32, 3.4.1-33, 3.4.1-42, 3.4.1-43, 3.4.1-45, 3.4.1-48, 3.4.1-49, 3.4.1-50, 3.4.1-51, 

3.4.1-56, 3.4.1-57, and 3.4.1-62a, the applicant claimed that the corresponding items in the 

GALL Report are not applicable because the component, material, and environment 

combination described in the SRP-LR does not exist for in-scope SCs at Callaway. The staff 

reviewed the LRA and FSAR and confirmed that the applicant’s LRA does not have any AMR 

results applicable for these items.

For LRA Table 3.4-1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable; however, the staff non-applicability verification of 

these items required the review of sources beyond the LRA and FSAR, and/or the issuance of 

RAIs.

LRA Table 3.4-1, item 3.4.1-4 addresses steel external surfaces and bolting exposed to air with 

borated water leakage. The GALL Report recommends GALL Report AMP XI.M10, “Boric Acid 

Corrosion,” to manage loss of material caused by boric acid corrosion for this component group. 

In the original LRA, the applicant stated that this item was not applicable; however, in LRA 

Amendment No. 1 dated April 25, 2012, the applicant revised the LRA to state that the item was 

applicable and consistent with the GALL Report guidance. The applicant also added 
AGING MANAGEMENT REVIEW RESULTS

3-429

AMR items that reference LRA item 3.4.1-4. The staff reviewed the associated AMR items, 

which cite generic note A, and confirmed the applicant’s claim of consistency with the GALL 

Report.

LRA Table 3.4-1, item 3.4.1-9 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity” 

to manage loss of material caused by general corrosion for this component group. The 

applicant stated that this item is not applicable because closure bolting was evaluated using 

plant indoor air as the external environment and SRP-LR Table 3.4-1, item 3.4.1-8 for steel 

closure bolting exposed to an air-indoor uncontrolled environment instead of item 3.4.1-9. The 

staff evaluated the applicant’s claim and finds it acceptable because the component group is 

being managed for the loss of material aging effect by the Bolting Integrity Program, consistent 

with the GALL Report recommendations.

LRA Table 3.4-1, item 3.4.1-50a addresses underground stainless steel and steel piping, piping 

components, and piping elements exposed to an underground environment. The GALL Report 

recommends GALL Report AMP XI.M41 “Buried and Underground Piping and Tanks” to 

manage loss of material caused by general (steel only), pitting and crevice corrosion for this 

component group. The applicant stated that this item is not applicable because it has no 

stainless steel and steel piping, piping components, and piping elements in the steam and 

power conversion system exposed to an underground environment. The staff noted that LRA 

drawing, LR-CW-AP-M-22AP01, shows piping located in a tunnel. The staff finds the 

applicant’s statement acceptable because during the audit, the staff confirmed that this tunnel is 

normally accessible to plant staff, and therefore, the area is not considered an underground 

environment in accordance with the GALL Report Section IX.D definition of the buried and 

underground environment.

LRA Table 3.4-1, item 3.4.1-53 addresses copper alloy (less than or equal to 15 percent zinc 

and less than or equal to 8 percent aluminum) piping, piping components, and piping elements 

exposed to air with borated water leakage. The applicant stated that this item is not applicable 

because there are no in-scope components associated with this item and there are no aging 

effects, aging mechanisms or AMPs for this component group. SRP-LR item 3.4.1-53 

recommends that there is no aging effect or aging mechanism and that no AMP is 

recommended for this component group exposed to this environment; therefore, the staff finds 

the applicant’s determination acceptable.

LRA Table 3.4-1, item 3.4.1-55 addresses glass piping elements exposed to lubricating oil, 

outdoor air, condensation, raw water, treated water, air with borated water leakage, gas, 

closed-cycle cooling water, and uncontrolled indoor air. The applicant stated that the item is not 

applicable because there are no in-scope components associated with this item. SRP-LR 

item 3.4.1-55 states that there is no aging effect or aging mechanism and that no AMP is 

recommended for this component group exposed to these environments; therefore, the staff 

finds the applicant’s determination acceptable.

LRA Table 3.4-1, item 3.4.1-60, addresses piping, piping components, and piping elements 

made from any material exposed to treated water. The GALL Report recommends GALL 

Report AMP XI.M17, “Flow-Accelerated Corrosion,” to manage wall thinning due to erosion for 

this component group. The applicant stated that this item is not applicable because it has not 

experienced this aging effect in any ESF systems. The staff notes that item 3.4.1-60 was 

generated as part of LR-ISG-2012-01, “Wall Thinning Due to Erosion Mechanisms,” which 

applies to management of erosion mechanisms that had been identified but where the 
AGING MANAGEMENT REVIEW RESULTS

3-430

underlying design issue had not been corrected. The staff evaluated the applicant’s claim and 

finds it acceptable because, during its independent review of the applicant’s operating 

experience database, the staff did not identify any issues with wall thinning due to erosion in any 

steam and power conversion systems at Callaway Unit 1. 

3.4.2.1.2 Reduced Thermal Insulation Resistance Due to Moisture Intrusion

LRA Table 3.4-1, item 3.4.1-65, addresses jacketed Foamglas® (glass dust) insulation exposed 

to atmosphere/weather which will be managed for reduced thermal insulation resistance due to 

moisture intrusion. For the AMR item that cites generic note E, the LRA credits the 

Aboveground Metallic Tanks Program to manage the aging effect for jacketed Foamglas® 

(glass dust) insulation exposed to atmosphere/weather (external) on the condensate storage 

tank. The GALL Report recommends GALL Report AMP XI.M36, “External Surfaces Monitoring 

of Mechanical Components,” to ensure that this aging effect is adequately managed. GALL 

Report AMP XI.M36 recommends using periodic visual inspections of the external surfaces of 

components to ensure that there is no damage to the jacketing that would permit in-leakage of 

moisture. 

The staff’s evaluation of the applicant’s Aboveground Metallic Tanks Program is documented in 

SER Section 3.0.3.2.8. The staff noted that Aboveground Metallic Tanks Program proposes to 

manage the aging of jacketed Foamglas® (glass dust) insulation through the use of periodic 

visual examinations conducted each refueling outage interval. In its review of components 

associated with item 3.4.1-65, for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the Aboveground Metallic Tanks Program 

acceptable because the periodic visual inspections are capable of identifying jacket damage 

that could allow moisture instruction, which is consistent with aging management approach 

recommended in GALL Report AMP XI.M36. 

The staff concludes that for LRA item 3.4.1-65, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended

In LRA Section 3.4.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the steam and power conversion systems components and provides 

information concerning how it will manage the following aging effects:

• cumulative fatigue damage

• cracking due to SCC

• loss of material due to pitting and crevice corrosion

• QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which the GALL Report recommends further 

evaluation, the staff audited and reviewed the applicant’s evaluations to determine whether it 

adequately addressed the issues further evaluated. In addition, the staff reviewed the 

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The 

staff’s review of the applicant’s further evaluation follows.
AGING MANAGEMENT REVIEW RESULTS

3-431

3.4.2.2.1 Cumulative Fatigue Damage

LRA Section 3.4.2.2.1, associated with LRA Table 3.4-1, item 3.4.1-1, addresses steel piping, 

piping components, and piping elements exposed to steam or treated water in the steam and 

power conversion system and being managed for cumulative fatigue damage. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that fatigue is a TLAA, as 

defined in 10 CFR 54.3, and is required to be evaluated in accordance with 10 CFR 54.21(c). 

The applicant stated that the TLAA identified for the steam and power conversion systems is 

addressed separately in LRA Section 4.3. 

The staff reviewed LRA Section 3.4.2.2.1 against the criteria in SRP-LR Section 3.4.2.2.1 which 

states that fatigue of steam and power conversion system components is a TLAA as defined in 

10 CFR 54.3, and that these TLAAs are to be evaluated in accordance with the TLAA 

acceptance criteria requirements in 10 CFR 54.21(c)(1). The staff reviewed the applicant’s 

AMR items and determined that the AMR results are consistent with the recommendations of 

the GALL Report and SRP-LR for managing cumulative fatigue damage in steel piping, piping 

components, and piping elements exposed to steam or treated water, except as identified 

below.

In its review of the applicant’s metal fatigue AMR assessment (item 3.4.1-1) in the steam and 

power conversion systems, the staff also identified that the applicant did not include the 

applicable AMR items in LRA Table 2s (Tables 3.x.2-y) for the TLAAs associated with fatigue of 

certain non-Class 1 piping such as those in the main feedwater system. Therefore, by letter 

dated September 6, 2012, as part of the RAI 4.3-10, the staff requested the applicant to justify 

this discrepancy. In its response dated October 11, 2012, the applicant revised LRA Section 3.4 

to include an additional AMR item for those SSCs subject to an AMR in accordance with 

10 CFR 54.21(a)(1), that was not identified previously. The details of RAI 4.3-10 and the staff’s 

evaluation of the applicant’s response are documented in SER Section 4.3.5.2.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.4.2.2.1 criteria. For those items associated with LRA Section 3.4.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that it will adequately manage the effects of aging so that the intended function(s) 

will be maintained consistent with the CLB during the period of extended operation, as required 

by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the applicant’s 

evaluation of the TLAA for these components.

3.4.2.2.2. Cracking due to Stress Corrosion Cracking

LRA Section 3.4.2.2.2, associated with LRA Table 3.4-1, item 3.4.1-2, addresses stainless steel 

piping, piping components, piping elements, insulation fasteners, and tanks exposed to outdoor 

air, which will be managed for cracking due to SCC by the External Surfaces Monitoring of 

Mechanical Components and Aboveground Metallic Tanks Programs. The criteria in SRP-LR 

Section 3.4.2.2.2 states that cracking due to SCC could occur for stainless steel piping, piping 

components, piping elements and tanks exposed to outdoor air. The SRP-LR also states that 

GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” is an 

acceptable method to manage this aging effect. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that the External Surfaces Monitoring of Mechanical 

Components Program manages cracking due to SCC for stainless steel external surfaces 

exposed to an outdoor air environment. The staff noted that the LRA also originally associated 

item 3.4.1-2 with the condensate storage tank, for which loss of material and cracking were 

being managed with the Aboveground Metallic Tanks Program. However, in a letter dated 
AGING MANAGEMENT REVIEW RESULTS

3-432

December 20, 2013, the applicant revised the condensate storage tank AMR item to cite 

item 3.4.1-30, consistent with the guidance in the GALL Report, as revised by LR-ISG-2012-02, 

“Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation.”

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components Program is documented in SER Section 3.0.3.1.10. In its review of components 

associated with item 3.4.1-2 for which the applicant credited the External Surfaces Monitoring of 

Mechanical Components Program to manage aging, the staff finds that the applicant has met 

the further evaluation criteria, and the applicant’s proposal is acceptable because: (a) the 

program includes periodic visual inspections that will occur at least every RFO, which are 

capable of detecting SCC; and (b) the inspection technique and frequency are consistent with 

the GALL Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2 criteria. For those items associated with LRA Section 3.4.2.2.2, the 

staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.4.2.2.3 Loss of Material due to Pitting and Crevice Corrosion

LRA Section 3.4.2.2.3, associated with LRA Table 3.4-1, item 3.4.1-3, addresses stainless steel 

piping, piping components, piping elements, insulation fasteners, and tanks exposed to air 

outdoor, which will be managed for loss of material due to pitting and crevice corrosion by the 

External Surfaces Monitoring of Mechanical Components and Aboveground Metallic Tanks 

Programs. The criteria in SRP-LR Section 3.4.2.2.3 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 outdoor air. The SRP-LR also states that GALL Report AMP XI.M36, 

“External Surfaces Monitoring of Mechanical Components,” is an acceptable method to manage 

this aging effect. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that, with the exception of the CST, the External Surfaces Monitoring of Mechanical 

Components Program manages the loss of material from pitting and crevice corrosion for 

stainless steel external surfaces exposed to an air outdoor environment. The applicant also 

stated that the CST external surfaces are managed by the Aboveground Metallic Tanks 

Program. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components Program is documented in SER Section 3.0.3.1.10. In its review of components 

associated with item 3.4.1-3, for which the applicant credited the External Surfaces Monitoring 

of Mechanical Components Program to manage aging, the staff finds that the applicant has met 

the further evaluation criteria, and the applicant’s proposal is acceptable because: (a) the 

program includes periodic visual inspections that will occur at least every RFO, which are 

capable of detecting loss of material; and (b) the inspection technique and frequency are 

consistent with the GALL Report.

The staff’s evaluation of the applicant’s Aboveground Metallic Tanks Program is documented in 

SER Section 3.0.3.2.8. The staff finds that the applicant has met the further evaluation criteria, 

and the applicant’s proposal to manage aging using the Aboveground Metallic Tanks Program is 

acceptable because: (a) the program uses external visual inspections of the surface of the tank 

to manage loss of material, including at least once within the 5-year period prior to the period of 
AGING MANAGEMENT REVIEW RESULTS

3-433

extended operation; (b) 25 one-square-foot sections of insulation will be removed to inspect the 

external surfaces of the tank; and (c) bottom thickness measurements will be performed. The 

staff finds that these inspections are capable of detecting loss of material, and the inspection 

technique and frequency are consistent with the GALL Report.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.3 criteria. For those items associated with LRA Section 3.4.2.2.3, the 

staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.4.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA Program.

3.4.2.2.5 Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of aging management 

programs.

3.4.2.2.6 Loss of Material Due to Recurring Internal Corrosion

LRA Section 3.4.2.2.6, as modified through LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation,” is 

associated with LRA Table 3.4-1, item 3.4.1-61, and addresses loss of material due to recurring 

internal corrosion in metallic piping, piping components, and tanks exposed to raw water or 

waste water. By letter dated October 7, 2013, the staff issued RAI 3.0.3-1 requesting the 

applicant to address issues related to recurring internal corrosion. In its response dated 

December 20, 2013, the applicant stated that this item is not applicable because operating 

experience associated with the steam and power conversion systems does not meet the 

threshold for significance or frequency of occurrence of the aging effect to be considered as 

recurring internal corrosion.

The staff evaluated the applicant’s claim and finds it acceptable because the applicant’s reviews 

of past operating experience did not identify instances of recurring internal corrosion in the 

steam and power conversion systems. The staff notes that its independent search of 

plant-specific operating experience during the AMP audit did not identify instances that 

warranted augmenting any AMPs that manage components in steam and power conversion 

systems to address internal corrosion.

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.4.2-1 through 3.4.2-6, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.4.2-1 through 3.4.2-6, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an 

AMR item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item 
AGING MANAGEMENT REVIEW RESULTS

3-434

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the AMR item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the AMR 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 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 Systems—Summary of Aging Management 

Evaluation—Main Turbine System—LRA Table 3.4.2-1

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the 

main turbine system component groups. The staff’s review did not identify any AMR items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for the main turbine system component groups are consistent with the GALL Report.

3.4.2.3.2 Steam and Power Conversion Systems—Summary of Aging Management 

Evaluation—Main Steam Supply System—LRA Table 3.4.2-2

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the 

main steam supply system component groups.

Calcium Silicate Insulation Exposed to Plant Indoor Air. In LRA Tables 3.4.2-2, 3.4.2-3, and 

3.4.2-5, as amended by letter dated December 19, 2012, the applicant stated that for calcium 

silicate insulation exposed to plant indoor air, there is no aging effect and no AMP is proposed. 

The AMR items originally cited generic note J, indicating that neither the component nor the 

material and environment are evaluated in the GALL Report. 

The staff noted that, subsequent to the applicant’s December 19, 2012, LRA amendment, 

License Renewal Interim Staff Guidance (LR-ISG) LR-ISG-2012-02, “Aging Management of 

Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under 

Insulation,” was issued, adding SRP-LR item 3.4.1-64 to manage reduced thermal insulation 

resistance for calcium silicate insulation exposed to plant air using GALL Report AMP XI.M36, 

“External Surfaces Monitoring of Mechanical Components.” In LRA Amendment 28, dated 

December 20, 2013, the applicant revised this item to manage reduced thermal insulation 

resistance with the External Surfaces Monitoring of Mechanical Components Program, 

consistent with LR-ISG-2012-02. Therefore, the staff finds the applicant’s proposal to manage 

aging acceptable.

3.4.2.3.3 Steam and Power Conversion Systems—Summary of Aging Management 

Evaluation—Main Feedwater System—LRA Table 3.4.2-3

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the 

main feedwater system component groups.
AGING MANAGEMENT REVIEW RESULTS

3-435

Calcium Silicate Insulation Exposed to Plant Indoor Air. The staff’s evaluation for calcium 

silicate insulation exposed to plant indoor air, for which the applicant cited no aging effect and 

no proposed AMP, but subsequently revised to be consistent with the GALL Report, is 

documented in SER Section 3.4.2.3.2. 

3.4.2.3.4 Steam and Power Conversion Systems—Summary of Aging Management 

Evaluation—Steam Generator Blowdown System—LRA Table 3.4.2-1

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the 

steam generator blowdown system component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the steam generator blowdown system component groups are 

consistent with the GALL Report.

3.4.2.3.5 Steam and Power Conversion Systems—Summary of Aging Management 

Evaluation—Auxiliary Feedwater System—LRA Table 3.4.2-5

The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for the 

auxiliary feedwater system component groups.

Calcium Silicate Insulation Exposed to Plant Indoor Air. The staff’s evaluation for calcium 

silicate insulation exposed to plant indoor air, for which the applicant cited no aging effect and 

no proposed AMP, but subsequently revised to be consistent with the GALL Report, is 

documented in SER Section 3.4.2.3.2.

Elastomeric Flexible Hoses Exposed to Condensation (Internal). In LRA Table 3.4.2-5, as 

amended by letter dated September 6, 2012, the applicant stated that elastomeric flexible hoses 

exposed to condensation (internal) will be managed for hardening and loss of strength by the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

AMR item cites generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that loss of material due to wear is not 

an applicable aging effect for elastomeric flexible hoses exposed to condensation (internal) 

since the presence of contaminants or hard abrasive particles is extremely unlikely as stated in 

the applicant response to RAI 3.3.2.28-1. The staff’s evaluation of the applicant’s response to 

RAI 3.3.2.28-1 is documented in SER Sections 3.3.2.1.7 and 3.3.2.1.10. Furthermore, the staff 

noted that the applicant manages other aging effects of the elastomeric flexible hoses in other 

AMR items in LRA Table 3.4 2-5. Based on its review of GALL Report Sections IX.E, “Selected 

Use of Terms for Describing and Standardizing Aging Effects,” and IX.F. “Significant Aging 

Mechanisms,” which indicate that loss of material and hardening and loss of strength are the 

only applicable aging effects for elastomeric components, the staff finds that the applicant has 

identified all credible aging effects for this component, material, and environment combination. 

Elastomeric Flexible Hoses Exposed to Condensation. In LRA Table 3.4.2-5, the applicant 

stated that the internal surfaces of elastomeric flexible hoses exposed to condensation will be 

managed for hardening and loss of strength by the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program. The AMR item cites generic note G.

The staff reviewed the associated item in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 
AGING MANAGEMENT REVIEW RESULTS

3-436

material, and environment description. The staff noted that the applicant’s identified aging 

effects and its aging management approach is consistent with GALL Report guidance for 

elastomers exposed to wet environments. GALL Report item VII.C2.AP-259 recommends that 

elastomeric components exposed to closed-cycle cooling water be managed for hardening and 

loss of strength with GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components.” The staff also noted that another potential 

aging effect, loss of material due to wear, would not be expected to be applicable to the internal 

surfaces of the subject hoses. The internal surfaces of these components are not expected to 

experience relative motion contact that could lead to wear, nor would condensation include 

continuous flow of hard abrasive particles. Based on its review of GALL Report Sections IX.E, 

“Selected Use of Terms for Describing and Standardizing Aging Effects,” and IX.F, “Significant 

Aging Mechanisms,” which identify hardening, loss of strength, and loss of material as the only 

applicable aging effects for elastomeric components, the staff finds that the applicant has 

identified all credible aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program is documented in SER Section 3.0.3.2.12. 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 this program 

includes opportunistic visual and physical manipulation inspections of elastomeric materials that 

are capable of detecting hardening and loss of strength.

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).

3.4.2.3.6 Steam and Power Conversion Systems—Summary of Aging Management 

Evaluation—Condensate Storage and Transfer System—LRA Table 3.4.2-6

The staff reviewed LRA Table 3.4.2-6, which summarizes the results of AMR evaluations for the 

condensate storage and transfer system component groups.

Acrylic or Urethane Insulation Exposed to Atmosphere or Weather (External). In LRA 

Table 3.4.2-6, the applicant stated that acrylic/urethane insulation exposed to 

atmosphere/weather will be managed for cracking, blistering, and change in color by the 

Aboveground Metallic Tanks Program. The AMR item cites generic note J. The AMR item cites 

plant-specific note 3, which states the following: 

Acrylic/Urethane in an Atmosphere/Weather (Ext.) environment is subjected to 

UV radiation, moisture, and thermal exposure. The acrylic rubber sealant coating 

provides UV radiation protection for the urethane foam tank insulation. The 

dome of the stainless steel tank is prepped with a low halogen (less than 

200 ppm) primer prior to the application of the foam urethane. The Aboveground 

Metallic Tanks Program (B2.1.15) manages cracking blistering or changes in 

color of the acrylic/urethane insulation. The acrylic rubber sealant is inspected 

for aging and damage as an indicator for the urethane foam underneath it.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. During the audit, the staff walked down the tank on 
AGING MANAGEMENT REVIEW RESULTS

3-437

which the insulation is used. The acrylic or urethane insulation is located on the dome of the 

tank. The sides of the tank are insulated with foamglas insulation which, as discussed below, 

has no AERM and no recommended AMP if jacketed. The insulation on the sides of the tank is 

jacketed. Based on a review of several manufacturing supplier websites, which offer urethane 

insulation as a foam that can be sprayed, injected, or in sheets of cured material (i.e., rigid 

boards), cracking, and blistering and change in color are the only applicable aging effects. 

Therefore, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Aboveground Metallic Tanks Program is documented in 

SER Section 3.0.3.2.8. The staff finds the applicant’s proposal to manage aging using the 

Aboveground Metallic Tanks Program acceptable because the periodic visual inspections 

conducted are capable of detecting cracking, blistering, and change in color.

Foamglas Insulation (Glass Dust) Exposed to Atmosphere or Weather (External). In LRA 

Table 3.4.2-6, the applicant stated that for foamglas insulation (glass dust) exposed to external 

atmosphere/weather, there is no aging effect and no AMP is proposed. The AMR item cites 

generic note J. The AMR item also cites plant specific note 2 which states, “[t]he mechanical 

properties FOAMGLAS (glass dust) are consistent with other glass materials and is evaluated 

consistent with other glass-like materials in an atmosphere/weather environment in 

NUREG-1801.” The staff reviewed the manufacturer’s website and discussed the 

characteristics of this material with the equipment manufacturer, Pittsburgh Corning Corporation 

(www.foamglas.com). Based on input from the manufacturer, if this insulation is protected by 

jacketing material, there are no aging effects. If the material is not jacketed, rain water or heavy 

dew layers can cause crazing of the surface of the material. During the audit, the staff 

confirmed that the applicant’s insulation procedures require installation of metallic jacketing over 

all insulation and the procedures provide appropriate requirements for positioning and overlap of 

the jacketing so as to exclude water entry. The staff finds the applicant’s proposal acceptable 

because: (a) GALL Report items EP-87, AP-167, and SP-108 state that glass exposed to 

outdoor air has no AERM or recommended AMP, (b) the insulation is composed of glass, and 

(c) the insulation is covered by metal jacketing, and therefore, moisture would not be expected 

to allow moisture to reach the surface of the insulation.

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).

3.4.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the steam and power conversion systems components within the scope 

of license renewal and subject to an AMR will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.5 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 the following SCs:
AGING MANAGEMENT REVIEW RESULTS

3-438

• reactor building

• control building 

• auxiliary building 

• turbine building 

• diesel generator building 

• miscellaneous in-scope structures

• in-scope tank foundations and structures

• electrical foundations and structures

• radwaste building

• fuel building

• ESW structures

• supports

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 Programs in Chapters II and III of 

NUREG-1801 for Containments, 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 if the applicant provided sufficient information 

to demonstrate that the effects of aging for the structures and component supports within the 

scope of license renewal and subject to an AMR will be adequately managed so that the 

intended function(s) will remain 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 confirm 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 confirm that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. Details of the 

staff’s evaluation are discussed in SER Sections 3.5.2.1.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff’s evaluations 

are documented in SER Section 3.5.2.2.
AGING MANAGEMENT REVIEW RESULTS

3-439

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.5.2.3.

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to confirm 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 Containment, Structures, and Component Supports 

Components in the GALL Report

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

PWR Concrete (Reinforced and Prestressed) and Steel Containments

Concrete: dome; 

wall; basemat; ring 

girders; buttresses, 

concrete elements, 

all (3.5.1-1)

Cracking and 

distortion 

caused by 

increased 

stress levels 

from 

settlement

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” or 

Chapter XI.S6, 

“Structure 

Monitoring” If a 

de-watering system 

is relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a 

de-watering 

system is 

relied upon to 

control 

settlement 

ASME 

Section XI, 

Subsection IWL 

or Structures 

Monitoring

Consistent with the 

GALL Report 

(see SER Section 

3.5.2.2.1.1)

Concrete: 

foundation; 

subfoundation 

(3.5.1-2)

Reduction of 

foundation 

strength and 

cracking 

caused by 

differential 

settlement and 

erosion of 

porous 

concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring” If a 

de-watering system 

is relied upon for 

control of erosion, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a 

de-watering 

system is 

relied upon to 

control 

settlement 

Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.1.1)

Concrete: dome; 

wall; basemat; ring 

girders; buttresses; 

Concrete: 

containment; wall; 

basemat; Concrete: 

basemat, concrete 

fill-in annulus 

(3.5.1-3)

Reduction of 

strength and 

modulus 

caused by 

elevated 

temperature 

(>150 °F 

general; 

>200 °F local)

A plant-specific 

aging management 

program is to be 

evaluated.

Yes, if 

temperature 

limits are 

exceeded 

Not applicable Not applicable to 

Callaway 

(see SER Section

3.5.2.2.1.2)
AGING MANAGEMENT REVIEW RESULTS

3-440

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements 

(inaccessible 

areas): drywell 

shell; drywell head; 

and drywell shell 

(3.5.1-4)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50,

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations 

Not applicable Not applicable to 

PWRs 

(see SER Section 

3.5.2.2.1.3(1))

Steel elements 

(inaccessible 

areas): liner; liner 

anchors; integral 

attachments; Steel 

elements 

(inaccessible 

areas): suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable) 

(3.5.1-5)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations 

ASME 

Section XI, 

Subsection IWE 

and 10 CFR 

Part 50, 

Appendix J

Consistent with 

GALL Report 

(see SER Section 

3.5.2.2.1.3(1))

Steel elements: 

torus shell (3.5.1-6)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

significant; 

recoating of 

the torus is 

recommende

d

Not applicable Not applicable to 

PWRs 

(see SER Section

3.5.2.2.1.3 (2))

Steel elements: 

torus ring girders; 

downcomers; Steel 

elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-7)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

Yes, if 

corrosion is 

significant 

Not applicable Not applicable to 

PWRs 

(see SER Section 

3.5.2.2.1.3(3))

Pre-stressing 

system: tendons 

(3.5.1-8)

Loss of 

prestress 

caused by 

relaxation; 

shrinkage; 

creep; elevated 

temperature

Yes, TLAA Yes TLAA Consistent with the 

GALL Report (see 

SER Section

3.5.2.2.1.4)
AGING MANAGEMENT REVIEW RESULTS

3-441

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Penetration 

sleeves; 

penetration bellows 

Steel elements: 

torus; vent line; 

vent header; vent 

line bellows; 

downcomers, 

Suppression pool 

shell; unbraced 

downcomers, Steel 

elements: vent 

header; 

downcomers 

(3.5.1-9)

Cumulative 

fatigue 

damage 

caused by 

fatigue (Only if 

CLB fatigue 

analysis exists)

Yes, TLAA Yes TLAA Consistent with the 

GALL Report 

(see SER Section

3.5.2.2.1.5)

Penetration 

sleeves; 

penetration bellows 

(3.5.1-10)

Cracking 

caused by 

stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME 

Section XI, 

Subsection IWE 

and 10 CFR 

Part 50, 

Appendix J

Consistent with the 

GALL Report 

(see SER Section

3.5.2.2.1.6)

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete 

(inaccessible 

areas): basemat, 

Concrete 

(inaccessible 

areas): dome; wall; 

basemat (3.5.1-11)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by 

freeze-thaw

Further evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557).

Yes Not applicable Not applicable to 

Callaway 

(see SER Section

3.5.2.2.1.7)

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(inaccessible 

areas): basemat, 

concrete 

(inaccessible 

areas): 

containment; wall; 

basemat, concrete 

(inaccessible 

areas): basemat, 

concrete fill-in 

annulus (3.5.1-12)

Cracking 

caused by 

expansion from 

reaction with 

aggregates

Further evaluation is 

required to 

determine if a 

plant-specific aging 

management 

program is needed. 

Yes Not applicable Not applicable to 

Callaway 

(see SER Section

3.5.2.2.1.8)
AGING MANAGEMENT REVIEW RESULTS

3-442

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(inaccessible 

areas): basemat, 

concrete 

(inaccessible 

areas): dome; wall; 

basemat (3.5.1-13)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific aging 

management 

program is needed. 

Yes Not applicable Not applicable to 

PWRs 

(see SER Section

3.5.2.2.1.9)

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(inaccessible 

areas): 

containment; wall; 

basemat (3.5.1-14)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific aging 

management 

program is needed. 

Yes Not applicable Not applicable to 

PWRs 

(see SER Section

3.5.2.2.1.9)

Concrete 

(accessible areas): 

basemat (3.5.1-15)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

PWRs 

(see SER Section 

3.5.2.1.1)

Concrete 

(accessible areas): 

basemat, concrete: 

containment; wall; 

basemat (3.5.1-16)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) 

caused by 

aggressive 

chemical 

attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

PWRs 

(see SER Section 

3.5.2.1.1)

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses 

(3.5.1-17)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) 

caused by 

aggressive 

chemical 

attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-443

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(accessible areas): 

basemat (3.5.1-18)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by 

freeze-thaw

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(accessible areas): 

basemat, Concrete 

(accessible areas): 

containment; wall; 

basemat, concrete 

(accessible areas): 

basemat, concrete 

fill-in annulus 

(3.5.1-19)

Cracking 

caused by 

expansion from 

reaction with 

aggregates

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(accessible areas): 

containment; wall; 

basemat (3.5.1-20)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses; 

reinforcing steel, 

concrete 

(accessible areas): 

basemat; 

reinforcing steel, 

concrete 

(accessible areas): 

dome; wall; 

basemat; 

reinforcing steel 

(3.5.1-21)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) 

caused by 

corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-444

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(inaccessible 

areas): basemat; 

reinforcing steel 

(3.5.1-22)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) 

caused by 

corrosion of 

embedded 

steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.5.2.1.1)

Concrete 

(inaccessible 

areas): basemat; 

reinforcing steel, 

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; 

reinforcing steel 

(3.5.1-23)

Cracking; loss

of bond; and 

loss of material 

(spalling, 

scaling) 

caused by 

corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable 

Callaway 

(see SER 

Section 3.5.2.1.1)

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete 

(inaccessible 

areas): basemat, 

Concrete 

(accessible areas): 

dome; wall; 

basemat (3.5.1-24)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) 

caused by 

aggressive 

chemical 

attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No ASME 

Section XI, 

Subsection IWL 

or Structures 

Monitoring

Consistent with the 

GALL Report

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses; 

reinforcing steel 

(3.5.1-25)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) 

caused by 

corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.1)

Moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-26)

Loss of sealing 

caused by 

wear, damage, 

erosion, tear, 

surface cracks, 

or other 

defects

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No ASME 

Section XI, 

Subsection IWE 

or Structures 

Monitoring

Not applicable to 

Callaway (see SER 

Section 3.0.3.2.17)
AGING MANAGEMENT REVIEW RESULTS

3-445

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Penetration 

sleeves; 

penetration 

bellows, steel 

elements: torus; 

vent line; vent 

header; vent line 

bellows; 

downcomers, 

suppression pool 

shell (3.5.1-27)

Cracking 

caused by 

cyclic loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)

Personnel airlock, 

equipment hatch, 

CRD hatch 

(3.5.1-28)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME 

Section XI, 

Subsection IWE 

and 10 CFR 

Part 50, 

Appendix J

Consistent with the 

GALL Report

Personnel airlock, 

equipment hatch, 

CRD hatch: locks, 

hinges, and closure 

mechanisms 

(3.5.1-29)

Loss of leak 

tightness 

caused by

mechanical 

wear of locks, 

hinges and 

closure 

mechanisms

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME 

Section XI, 

Subsection IWE 

and 10 CFR 

Part 50, 

Appendix J

Consistent with the 

GALL Report

Pressure-retaining 

bolting (3.5.1-30)

Loss of preload 

caused by 

self-loosening

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME 

Section XI, 

Subsection IWE 

and 10 CFR 

Part 50, 

Appendix J

Consistent with the 

GALL Report

Pressure-retaining 

bolting, steel 

elements: 

downcomer pipes 

(3.5.1-31)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No ASME 

Section XI, 

Subsection IWE

Consistent with the 

GALL Report

Prestressing 

system: tendons; 

anchorage 

components 

(3.5.1-32)

Loss of 

material 

caused by 

corrosion

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report

Seals and gaskets 

(3.5.1-33)

Loss of sealing 

caused by 

wear, damage, 

erosion, tear, 

surface cracks, 

or other 

defects

Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J “

No 10 CFR Part 50, 

Appendix J

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-446

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Service Level I 

coatings (3.5.1-34)

Loss of coating 

integrity 

caused by 

blistering, 

cracking, 

flaking, 

peeling, or 

physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No Protective 

Coating 

Monitoring and 

Maintenance

Consistent with the 

GALL Report

Steel elements 

(accessible areas): 

liner; liner anchors; 

integral 

attachments, 

penetration 

sleeves, steel 

elements 

(accessible areas): 

drywell shell; 

drywell head; 

drywell shell in 

sand pocket 

regions;, steel 

elements 

(accessible areas): 

suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable), steel 

elements 

(accessible areas): 

drywell shell; 

drywell head 

(3.5.1-35)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No ASME 

Section XI, 

Subsection IWE 

and 10 CFR 

Part 50, 

Appendix J

Consistent with the 

GALL Report

Steel elements: 

drywell head; 

downcomers 

(3.5.1-36)

Fretting or 

lockup caused 

by mechanical 

wear

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.5.2.1.1)

Steel elements: 

suppression 

chamber (torus) 

liner (interior 

surface) (3.5.1-37)

Loss of 

material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.5.2.1.1)

Steel elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-38)

Cracking 

caused by 

stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.5.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-447

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements: 

vent line bellows 

(3.5.1-39)

Cracking 

caused by 

stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.5.2.1.1)

Unbraced 

downcomers, Steel 

elements: vent 

header; 

downcomers 

(3.5.1-40)

Cracking 

caused by 

cyclic loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.5.2.1.1)

Steel elements: 

drywell support 

skirt, steel elements 

(inaccessible 

areas): support skirt 

(3.5.1-41)

None None NA - No AEM 

or AMP

Not applicable Not applicable to 

PWRs 

(see SER 

Section 3.5.2.1.1)

Safety-Related and Other Structures; and Component Supports

Groups 1-3, 5, 

7-9:concrete 

(inaccessible 

areas): foundation 

(3.5.1-42)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by 

freeze-thaw

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions

(weathering index 

>100 day-inch/yr) 

(NUREG-1557)

Yes Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.1(1))

All groups except 

Group 6:concrete 

(inaccessible 

areas): all 

(3.5.1-43)

Cracking 

caused by 

expansion from 

reaction with 

aggregates

Further evaluation is 

required to 

determine if a 

plant-specific aging 

management 

program is needed.

Yes Not applicable Not applicable to 

Callaway

(see SER Section 

3.5.2.2.2.1(2))

All Groups: 

concrete: all 

(3.5.1-44)

Cracking and 

distortion 

caused by 

increased 

stress levels 

from 

settlement

Chapter XI.S6, 

“Structures 

Monitoring,” if a 

de-watering system 

is relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes Structures 

Monitoring or 

ASME 

Section XI, 

Subsection IWL

Consistent with the 

GALL Report 

(see SER Section 

3.5.2.2.2.1(3))
AGING MANAGEMENT REVIEW RESULTS

3-448

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 1-3, 5-9: 

concrete: 

foundation; 

subfoundation 

(3.5.1-45)

Reduction in 

foundation 

strength, 

cracking 

caused by 

differential 

settlement, 

erosion of 

porous 

concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring,” if a 

de-watering system 

is relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes Not applicable Not applicable to 

PWRs (see SER 

Section 3.5.2.1.1)

Groups 1-3, 5-9: 

concrete: 

foundation; 

subfoundation 

(3.5.1-46)

Reduction of 

foundation 

strength and 

cracking 

caused by 

differential 

settlement and 

erosion of 

porous 

concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring,” if a 

de-watering system 

is relied upon for 

control of settlement, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.1(3))

Groups 1-5, 7-9: 

concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation 

(3.5.1-47)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific aging 

management 

program is needed.

Yes, Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.1(4))

Groups 1-5: 

concrete: all 

(3.5.1-48)

Reduction of 

strength and 

modulus 

caused by 

elevated 

temperature 

(>150 °F 

general; 

>200 °F local)

A plant-specific 

aging management 

program is to be 

evaluated.

Yes Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.2)

Groups 6 - concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-49)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by 

freeze-thaw

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557)

Yes Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.3(1))
AGING MANAGEMENT REVIEW RESULTS

3-449

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 6: concrete 

(inaccessible 

areas): all 

(3.5.1-50)

Cracking 

caused by 

expansion from 

reaction with 

aggregates

Further evaluation is 

required to 

determine if a 

plant-specific aging 

management 

program is needed.

Yes Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.3(2))

Groups 6: concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-51)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific aging 

management 

program is needed.

Yes Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.3(3))

Groups 7, 8 - steel 

components: tank 

liner (3.5.1-52)

Cracking 

caused by 

stress 

corrosion 

cracking; Loss 

of material 

caused by 

pitting and 

crevice 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated.

Yes Not applicable Not applicable to 

Callaway 

(see SER Section 

3.5.2.2.2.4)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-53)

Cumulative 

fatigue 

damage 

caused by 

fatigue (Only if 

CLB fatigue 

analysis exists)

Yes, TLAA Yes, TLAA Consistent with 

GALL Report 

(see SER Section 

3.5.2.2.2.5)

All groups except 6: 

concrete 

(accessible areas): 

all (3.5.1-54)

Cracking 

caused by 

expansion from 

reaction with 

aggregates

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Building concrete at 

locations of 

expansion and 

grouted anchors; 

grout pads for 

support base plates 

(3.5.1-55)

Reduction in 

concrete 

anchor 

capacity 

caused by 

local concrete 

degradation/ 

service-induce

d cracking or 

other concrete 

aging 

mechanisms

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-450

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete: exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-56)

Loss of 

material 

caused by 

abrasion; 

cavitation

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Constant and 

variable load spring 

hangers; guides; 

stops (3.5.1-57)

Loss of 

mechanical 

function 

caused by 

corrosion, 

distortion, dirt, 

overload, 

fatigue caused 

by vibratory 

and cyclic 

thermal loads

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Earthen 

water-control 

structures: dams; 

embankments; 

reservoirs; 

channels; canals 

and ponds 

(3.5.1-58)

Loss of 

material; loss 

of form caused 

by erosion, 

settlement, 

sedimentation, 

frost action, 

waves, 

currents, 

surface runoff, 

seepage

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: concrete 

(accessible areas): 

all (3.5.1-59)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) 

caused by 

corrosion of 

embedded 

steel

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-451

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-60)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by 

freeze-thaw

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-61)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: wooden 

piles; sheeting 

(3.5.1-62)

Loss of 

material; 

change in 

material 

properties 

caused by 

weathering, 

chemical 

degradation, 

and insect 

infestation 

repeated 

wetting and 

drying, fungal 

decay

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-63)

Increase in 

porosity and 

permeability; 

loss of strength 

caused by 

leaching of 

calcium 

hydroxide and 

carbonation

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-452

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-64)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by 

freeze-thaw

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-3, 5, 7-9: 

concrete 

(inaccessible 

areas): 

below-grade 

exterior; foundation, 

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

below-grade 

exterior; foundation, 

Groups 6: concrete 

(inaccessible 

areas): all 

(3.5.1-65)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) 

caused by 

corrosion of 

embedded 

steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-5, 7, 9: 

concrete 

(accessible areas): 

interior and 

above-grade 

exterior (3.5.1-66)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) 

caused by 

corrosion of 

embedded 

steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-5, 7, 9: 

concrete: interior; 

above-grade 

exterior, groups 

1-3, 5, 

7-9 - concrete 

(inaccessible 

areas): 

below-grade 

exterior; foundation, 

group 6: concrete 

(inaccessible 

areas): all 

(3.5.1-67)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) 

caused by 

aggressive 

chemical 

attack

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

High-strength 

structural bolting 

(3.5.1-68)

Cracking 

caused by 

stress 

corrosion 

cracking

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-453

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

High-strength 

structural bolting 

(3.5.1-69)

Cracking 

caused by 

stress 

corrosion 

cracking

Chapter XI.S6, 

“Structures 

Monitoring” Note: 

ASTM A 325, F 

1852, and ASTM A 

490 bolts used in 

civil structures have 

not shown to be 

prone to SCC. SCC 

potential need not be 

evaluated for these 

bolts.

No Structures 

Monitoring

Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)

Masonry walls: all 

(3.5.1-70)

Cracking 

caused by 

restraint 

shrinkage, 

creep, and 

aggressive 

environment

Chapter XI.S5, 

“Masonry Walls”

No Masonry Walls 

and Fire 

Protection

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.2)

Masonry walls: all 

(3.5.1-71)

Loss of 

material 

(spalling, 

scaling) and 

cracking 

caused by 

freeze-thaw

Chapter XI.S5, 

“Masonry Walls”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)

Seals; gasket; 

moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-72)

Loss of sealing 

caused by 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Service Level I 

coatings (3.5.1-73)

Loss of coating 

integrity 

caused by 

blistering, 

cracking, 

flaking, 

peeling, 

physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No Protective 

Coating 

Monitoring and 

Maintenance

Consistent with the 

GALL Report

Sliding support 

bearings; sliding 

support surfaces 

(3.5.1-74)

Loss of 

mechanical 

function 

caused by 

corrosion, 

distortion, dirt, 

debris, 

overload, wear

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-454

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Sliding surfaces 

(3.5.1-75)

Loss of 

mechanical 

function 

caused by 

corrosion, 

distortion, dirt, 

debris, 

overload, wear

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Sliding surfaces: 

radial beam seats 

in BWR drywell 

(3.5.1-76)

Loss of 

mechanical 

function 

caused by 

corrosion, 

distortion, dirt, 

overload, wear

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Not applicable to 

PWRs (see SER 

Section 3.5.2.1.1)

Steel components: 

all structural steel 

(3.5.1-77)

Loss of 

material 

caused by 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring” If 

protective coatings 

are relied upon to 

manage the effects 

of aging, the 

structures monitoring 

program is to include 

provisions to 

address protective 

coating monitoring 

and maintenance.

No Structures 

Monitoring

Consistent with the 

GALL Report

Steel components: 

fuel pool liner 

(3.5.1-78)

Cracking 

caused by 

stress 

corrosion 

cracking; Loss 

of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Monitoring of 

the spent fuel pool 

water level in 

accordance with 

technical 

specifications and 

leakage from the 

leak chase channels.

No, unless 

leakages 

have been 

detected 

through the 

SFP liner that 

cannot be 

accounted for 

from the leak 

chase 

channels

Water

Chemistry

Consistent with the 

GALL Report

Steel components: 

piles (3.5.1-79)

Loss of 

material 

caused by 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-80)

Loss of 

material 

caused by 

general, pitting 

and crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Inspection of 

Overhead 

Heavy Load and 

Light Load 

(Related to 

Refueling) 

Handling 

Systems

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.3)
AGING MANAGEMENT REVIEW RESULTS

3-455

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Structural bolting 

(3.5.1-81)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-82)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-83)

Loss of 

material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants and 

Structures 

Monitoring

Consistent with 

GALL Report 

(see SER 

Section 3.5.2.1.4)

Structural bolting 

(3.5.1-84)

Loss of 

material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

PWRs (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-85)

Loss of 

material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-86)

Loss of 

material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-87)

Loss of preload 

caused by 

self-loosening

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-456

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Structural bolting 

(3.5.1-88)

Loss of preload 

caused by 

self-loosening

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring and 

Inspection of 

Overhead 

Heavy Load and 

Light Load 

(Related to 

Refueling) 

Handling 

Systems

Consistent with 

GALL Report 

(see SER 

Section 3.5.2.1.5)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-89)

Loss of 

material 

caused by 

boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Boric Acid 

Corrosion

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-90)

Loss of 

material 

caused by 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,” 

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-91)

Loss of 

material 

caused by 

general and 

pitting 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No ASME 

Section XI, 

Subsection IWF

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-92)

Loss of 

material 

caused by 

general and 

pitting 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-93)

Loss of 

material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring and 

ASME 

Section XI, 

Subsection IWF

Consistent with 

GALL Report 

(see SER 

Section 3.5.2.1.6)

Vibration isolation 

elements (3.5.1-94)

Reduction or 

loss of isolation 

function 

caused by 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory 

loading

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

Callaway (see SER 

Section 3.5.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-457

Component Group 

(SRP-LR Item No.)

Aging Effect 

or Mechanism

Recommended 

AMP in SRP-LR 

Further 

Evaluation in 

SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Aluminum, 

galvanized steel 

and stainless steel 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

exposed to air –

indoor, uncontrolled 

(3.5.1-95)

None None NA - No AEM 

or AMP

None Consistent with 

GALL Report 

(see SER 

Section 3.5.2.1.7)

3.5.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the containments, structures, and structural components and their 

commodity groups:

• 10 CFR Part 50, Appendix J

• ASME Section XI, Subsection IWE

• ASME Section XI, Subsection IWF

• ASME Section XI, Subsection IWL

• Boric Acid Corrosion

• Fire Protection

• Masonry Walls

• Regulatory Guide (RG) 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants

• Protective Coating Monitoring and Maintenance

• Structures Monitoring

• Water Chemistry

Although not identified directly in LRA Section 3.5.2.1, LRA Table 3.5-1 identifies the TLAA 

Program under the discussion column that manages aging effects for the structures and 

structural components and their commodity groups for specified conditions.

LRA Tables 3.5.2-1 through 3.5.2-12 summarize AMRs for the containments, structures, and 

component supports component groups and indicate AMRs claimed to be consistent with the 

GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with theGALL Report and for which it does not recommend further evaluation, the 

staff’s audit and review determined whether the plant-specific components of these GALL 

Report component groups were bounded by the GALL Report evaluation.
AGING MANAGEMENT REVIEW RESULTS

3-458

The applicant noted for each AMR item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with notes A–E, indicating how 

the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these items to confirm consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff reviewed these items to confirm consistency with the GALL Report and 

confirmed that the identified exceptions to the GALL Report AMPs have been reviewed and 

accepted. The staff also determined whether the applicant’s AMP was consistent with the GALL 

Report AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL Report AMP. This note indicates that the applicant was unable to find 

a listing of some system components in the GALL Report; however, the applicant identified in 

the GALL Report a different component with the same material, environment, aging effect, and 

AMP as the component under review. The staff reviewed these items to confirm consistency 

with the GALL Report. The staff also determined whether the AMR item of the different 

component was applicable to the component under review and whether the AMR was valid for 

the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL Report AMP. The staff reviewed these items to confirm 

consistency with the GALL Report. The staff confirmed whether the AMR item of the different 

component was applicable to the component under review and whether the identified 

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also 

determined whether the applicant’s AMP was consistent with the GALL Report AMP and 

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect but credits a different AMP. The staff reviewed these items to 

confirm 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 confirm that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows.

3.5.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.5-1, items 3.5.1-15, 3.5.1-16, 3.5.1-22, 3.5.1-36 through 3.5.1-41, 3.5.1-45, 

3.5.1-76, and 3.5.1-84, the applicant claimed that the corresponding AMR items in the GALL 

Report are not applicable because the associated items are only applicable to BWRs. The staff 
AGING MANAGEMENT REVIEW RESULTS

3-459

reviewed the SRP-LR, confirmed these items only apply to BWRs, and finds that these items 

are not applicable to Callaway, which is a PWR.

For LRA Table 3.5-1, items 3.5.1-23, 3.5.1-27, 3.5.1-62, 3.5.1-71, 3.5.1-79, 3.5.1-85, and 

3.5.1-94, the applicant claimed that the corresponding items in the GALL Report are not 

applicable because the component, material, and environment combination described in the 

SRP-LR does not exist for in-scope SCs at Callaway. The staff reviewed the LRA and FSAR 

and confirmed that the applicant’s LRA does not have any AMR results applicable for these 

items.

For LRA Table 3.5-1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable; however, the staff non-applicability verification of 

these items required the review of sources beyond the LRA and FSAR, and/or the issuance of 

RAIs.

LRA Table 3.5-1, item 3.5.1-25 addresses inaccessible concrete exposed to air. The GALL 

Report recommends GALL Report AMP XI.S2, “ASME Section XI, Subsection IWL,” or XI.S6, 

“Structures Monitoring,” to manage cracking, loss of bond, and loss of material caused by 

corrosion of embedded steel for this component group. The applicant stated that this item is not 

applicable because there is no inaccessible containment concrete exposed to an air 

environment. The staff evaluated the applicant’s claim and does not agree that all containment 

concrete exposed to air is accessible for inspection. For example, during a walkdown on 

May 2, 2012, the staff observed external containment concrete that appeared to be obstructed 

by the containment vent duct. In addition, it is not clear to the staff how inaccessible 

containment concrete exposed to other environments will be managed during the period of 

extended operation. Therefore, by letter dated August 6, 2012, the staff issued RAI 3.5.1.25-1 

requesting that the applicant confirm that all containment concrete exposed to air is accessible 

for inspection, and to explain how containment concrete exposed to other environments will be 

managed for aging during the period of extended operation.

In its response dated September 6, 2012, the applicant revised Table 3.5-1, item 3.5.1-25, to be 

consistent with the GALL Report and noted that inspections of inaccessible areas would be 

conducted in accordance with the guidance in the GALL Report. The applicant further stated 

that normally inaccessible structural components are examined when scheduled maintenance 

work and planned plant modifications permit access.

The staff finds the applicant’s response acceptable because the response identifies that 

inaccessible containment concrete does exist and it aligns the aging management of the 

commodity with the GALL Report recommended aging management approach. As part of its 

response the applicant also revised item 3.5.1-25 to be consistent with the GALL Report. The 

staff’s concern described in RAI 3.5.1.25-1 is resolved. Additional information on inaccessible 

containment concrete can be found in the staff’s review of the applicant’s ASME Section XI, 

Subsection IWL Program and RAI B2.1.27-3, in SER Section 3.0.3.1.12. In its review of 

components associated with items 3.5.1-25, the staff finds the applicant’s proposal to manage 

aging using the ASME Section XI, Subsection IWL Program acceptable because it is the GALL 

Report recommended AMP for this component, environment, and aging effect.

LRA Table 3.5-1, item 3.5.1-69, as amended by letter dated August 9, 2012, addresses 

high-strength structural bolting exposed to air-indoor, uncontrolled or air-outdoor. The GALL 

Report recommends GALL Report AMP XI.S6, “Structures Monitoring” to manage cracking 

caused by SCC for this component group. The applicant stated that this item is not applicable 
AGING MANAGEMENT REVIEW RESULTS

3-460

because Callaway has no in-scope high-strength structural bolting susceptible to cracking 

caused by SCC. The staff evaluated the applicant’s claim and finds it acceptable because in its 

August 9, 2012, response to RAI B2.1.28-1, the applicant stated that it reviewed drawings, plant 

specifications, vendor specifications, and procurement documents, and performed key word 

searches of plant databases and concluded that there are no structural bolts within the scope of 

license renewal for which augmented volumetric examinations are required. The staff’s review 

of RAI B2.1.28-1 is documented in SER Section 3.0.3.2.16.

LRA Table 3.5.1, item 3.5.1-90 addresses steel and stainless steel Class 1 support members 

exposed to treated water with a temperature less than 60 °C (140 °F). The GALL Report 

recommends GALL Report AMP XI.M2, “Water Chemistry,” for BWR water, and XI.S3, “ASME 

Section XI, Subsection IWF,” to manage loss of material caused by general, pitting, and crevice 

corrosion for this component group. The applicant stated that this item is not applicable 

because it only applies to BWR plants. The staff reviewed the corresponding item in the 

SRP-LR, and the associated items in the GALL Report, and noted that the items apply to 

Class 1 supports, regardless of the plant design. Therefore, by letter dated August 6, 2012, the 

staff issued RAI 3.5.1.90-1 requesting the applicant explain why this item is not applicable, or 

provide an acceptable AMP to manage loss of material caused by general, pitting, and crevice 

corrosion of steel and stainless steel support members exposed to treated water with a 

temperature less than 60 °C (140 °F).

In its response dated September 6, 2012, the applicant stated that item 3.5.1-90 is not 

applicable because there are no steel or stainless steel ASME Code Class 1 support members 

submerged in treated water. As part of its response the applicant revised LRA Table 3.5.1, 

item 3.5.1-90 to state that the item is not applicable because Callaway has no steel or stainless 

steel ASME Class 1 support members submerged in treated water.

The staff reviewed the applicant’s response and finds it acceptable because the applicant 

clearly stated that the component, material and environment combination discussed in 

item 3.5.1-90 does not exist at Callaway. Therefore, the not applicable determination is 

acceptable. The staff’s concern described in RAI 3.5.1.90-1 is resolved. The staff reviewed the 

LRA and FSAR and confirmed that the applicant’s LRA does not have any AMR results that are 

applicable for these items.

3.5.2.1.2 Cracking Due to Restraint Shrinkage, Creep, and Aggressive Environment

LRA Table 3.5-1, item 3.5.1-70 addresses masonry walls exposed to indoor or outdoor air which 

will be managed for cracking due to restraint shrinkage, creep, and aggressive environment. 

For the AMR items that cite generic note E, the LRA credits the Masonry Walls and Fire 

Protection Programs to manage this aging effect for concrete block masonry walls. In a letter 

dated February 14, 2014, the applicant revised one of the subject AMR items in Table 3.5.2-4 to 

credit only the Masonry Walls Program because the fire barrier intended function of this 

component was removed per the applicant’s transition to a risk-informed, performance-based 

fire protection plan that incorporates NFPA-805. The remaining AMR items cite both the 

Masonry Walls and Fire Protection Programs. The GALL Report recommends GALL Report 

AMP XI.S5 “Masonry Walls,” to ensure that these aging effects are adequately managed. GALL 

Report AMP XI.S5 recommends using visual inspections with a 5-year frequency to manage 

aging.

The staff’s evaluation of the applicant’s Masonry Wall and Fire Protection Programs is 

documented in SER Sections 3.0.3.1.14 and 3.0.3.2.6, respectively. The staff noted that the 
AGING MANAGEMENT REVIEW RESULTS

3-461

Masonry Wall and Fire Protection Programs both propose to manage the aging of concrete 

block masonry walls through the use of visual inspections. The staff further noted that the GALL 

Report recommended program, the Masonry Wall Program, is being credited for all of the 

masonry walls, and the Fire Protection Program is being credited in addition to the Masonry 

Wall Program for walls that provide a fire barrier function. In its review of components 

associated with item 3.5.1-70 for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the Masonry Wall and Fire Protection Programs 

acceptable because the recommended GALL Report AMP XI.S5 “Masonry Walls,” is being 

credited, and Fire Protection Program is also being credited in addition to the recommended 

GALL Report AMP XI.S5.

The staff concludes that for LRA item 3.5.1-70, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.3 Loss of Material Due to General, Pitting and Crevice Corrosion

LRA Table 3.5-1, item 3.5.1-80 addresses carbon steel structural bolting exposed to plant 

indoor air which will be managed for loss of material caused by general, pitting, and crevice 

corrosion. For the AMR items that cite generic note E, the LRA credits the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program to 

manage the aging effect for carbon steel structural bolting. The GALL Report recommends 

GALL Report AMP XI.S6, “Structures Monitoring,” to ensure that these aging effects are 

adequately managed. GALL Report AMP XI.S6 recommends visual inspection of structural 

bolting, at a frequency not to exceed 5 years, to manage aging.

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 3.0.3.2.5. 

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 structural 

bolting through the use of visual inspections. In its review of components associated with 

item 3.5.1-80 for which the applicant cited generic note E, the staff finds the applicant’s proposal 

to manage aging using the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program acceptable because visual inspections for cranes are 

performed in accordance with ASME Code B30 standards, which require inspections more 

frequently than the 5-year interval recommended in GALL Report AMP XI.S6.

The staff concludes that for LRA item 3.5.1-80, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.4 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.5-1, item 3.5.1-83 addresses structural steel exposed to a submerged 

environment, which will be managed for loss of material due to general, pitting, and crevice 

corrosion. For the AMR item that cites generic note E, the LRA credits the Structures 

Monitoring Program to manage the aging effect for carbon steel structural steel. The GALL 

Report recommends GALL Report AMP XI.S7, “RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants,” or the FERC/US Army Corp of Engineers 

dam inspections and maintenance programs to ensure that these aging effects are adequately 
AGING MANAGEMENT REVIEW RESULTS

3-462

managed. GALL Report AMP XI.S7 recommends using periodic visual inspections at least 

once every 5 years to manage aging. 

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in 

SER Section 3.0.3.2.17. The staff notes that the Structures Monitoring Program proposes to 

manage the aging of carbon structural steel through the use of periodic visual inspections, by 

personnel qualified in accordance with ACI 349.3R, at a frequency not to exceed 5 years. The 

staff also notes that although the GALL Report does not provide a line to evaluate carbon 

structural steel in a submerged environment for components in Group 3 structures, the 

Structures Monitoring Program would be capable of managing these aging effects. In its review 

of components associated with item 3.5.1-83 for which the applicant cited generic note E, the 

staff finds the applicant’s proposal to manage aging using the Structures Monitoring Program 

acceptable because personnel performing inspections are qualified in accordance with 

ACI 349.3R, and inspections are performed at a frequency not to exceed 5 years, which is 

consistent with the recommendations in GALL Report AMP XI.S7 for structural steel exposed to 

a submerged environment.

During its review of components associated with item 3.5.1-83 for which the applicant cited 

generic note C, the staff noted that the LRA credits the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program to manage the aging effect for 

carbon steel ASME Code Class 2 and 3 supports. The staff noted that ASME Code Class 2 and 

3 supports should be within the scope of the ASME Section XI, Subsection IWF Program. The 

scope, frequency, and inspection criteria as specified in GALL Report AMP XI.S3, “ASME 

Section XI, Subsection IWF,” for ASME Code Class 2 and 3 supports is different from that 

specified in GALL Report AMP XI.S7 for non-ASME steel components monitored for loss of 

material caused by corrosion. GALL Report AMP XI.S3 recommends that a sample of ASME 

Code Class 1, 2, and 3 component supports that are not exempt from examination and 

100 percent of MC component supports be examined as specified in Table IWF-2500-1. The 

sample size examined for ASME Code Class 1, 2, and 3 component supports is as specified in

Table IWF-2410-2. The detailed acceptance standards for ASME Code Class 1, 2, and 3 

component supports are delineated in IWF-3400. GALL Report AMP XI.S7 recommends 

inspection of structures and components at a frequency of 5 years in accordance with 

ACI 349.3R. Therefore, by letter dated July 9, 2012, the staff issued RAI 3.5.2.12-1 requesting 

the applicant to explain why the RG 1.127, Inspection of Water-Control Structures Associated 

with Nuclear Power Plants Program, instead of the ASME Section XI, Subsection IWF Program, 

is being used to monitor ASME Code Class 2 and 3 supports that are submerged in water. The 

staff also requested the applicant to include a discussion on how the scope, frequency, and 

acceptance criteria specified in ASME Code Section XI, Subsection IWF can be implemented by 

the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program for ASME Code Class 2 and 3 carbon steel supports that are submerged in water.

In its response dated August 9, 2012, the applicant stated that the ASME Code Class 2 and 3 

carbon steel supports submerged in water were included in LRA Table 3.5.2-12 as supports for 

the ESW discharge pipe located in the UHS cooling tower sump. The applicant further stated 

that as shown in FSAR-SA Figure 3.8-9, this 36-inch diameter pipe is supported within the 

concrete wall and does not require an additional support structure inside the sump. Therefore, 

as part of its response, the applicant revised the LRA to indicate the absence of submerged 

ASME Code Class 2 and 3 supports.

The staff reviewed the applicant’s response and finds it acceptable because the staff confirmed 

in its review of FSAR-SA Figure 3.8-9, that there are no ASME Code Class 2 and 3 carbon steel 
AGING MANAGEMENT REVIEW RESULTS

3-463

supports for the ESW discharge pipe located in the UHS cooling tower sump. The staff’s 

concern described in RAI 3.5.2.12-1 is resolved.

The staff concludes that for LRA item 3.5.1-83, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.5 Loss of Preload due to Self-Loosening

LRA Table 3.5-1, item 3.5.1-88 addresses carbon steel structural bolting exposed to plant 

indoor air or borated water leakage which will be managed for loss of preload due to 

self-loosening. For the AMR items that cite generic note E, the LRA credits the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program to 

manage the aging effect for carbon steel structural bolting. The GALL Report recommends 

GALL Report AMP XI.S6, “Structures Monitoring,” to ensure that these aging effects are 

adequately managed. GALL Report AMP XI.S6 recommends visual inspection of structural 

bolting, at a frequency not to exceed 5 years, to manage aging.

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 3.0.3.2.5. 

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 structural 

bolting through the use of visual inspections. In its review of components associated with 

item 3.5.1-88 for which the applicant cited generic note E, the staff finds the applicant’s proposal 

to manage aging using the Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems Program acceptable because visual inspections for cranes are 

performed in accordance with ASME Code B30 standards, which require inspections more 

frequently than the 5-year interval recommended in GALL Report AMP XI.S6.

The staff concludes that for LRA item 3.5.1-88, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.6 Loss of Material due to Pitting and Crevice Corrosion

LRA Table 3.5-1, item 3.5.1-93 addresses stainless steel and aluminum support members, 

welds, bolted connections, and support anchorage to building structures exposed to 

atmosphere/weather which will be managed for loss of material due to pitting and crevice 

corrosion. For the AMR items that cite generic note E, the LRA credits the ASME Section XI, 

Subsection IWF Program to manage the aging effect for stainless steel bolting and ASME Code 

Class 2 and 3 supports. The GALL Report recommends GALL Report AMP XI.S6, “Structures 

Monitoring,” to ensure that these aging effects are adequately managed. However, the staff 

notes that SRP-LR Table 3.5-1, item 3.5.1-91 also addresses steel support members, welds, 

bolted connections, and support anchorage to building structures exposed to 

atmosphere/weather which will be managed for loss of material caused by pitting and crevice 

corrosion. Although the referenced GALL Report items in SRP-LR Table 3.5.1, item 3.5.1-91 do 

not include stainless steel as a material for the identified aging effect, the staff agrees that the 

ASME Section XI, Subsection IWF Program would be an acceptable program to manage this 

aging effect for stainless steel bolting and ASME Code Class 2 and 3 supports.
AGING MANAGEMENT REVIEW RESULTS

3-464

The staff’s evaluation of the applicant’s ASME Section XI, Subsection IWF Program is 

documented in SER Section 3.0.3.2.16. The staff notes that the ASME Section XI, 

Subsection IWF Program proposes to manage the aging of supports for Class 1, 2, and 3 piping 

and components through the use of periodic visual examinations. The staff also notes that the 

ASME Section XI, Subsection IWF Program will be enhanced to specify that whenever 

replacement of bolting is required, bolting material, installation torque or tension, and use of 

lubricants and sealants are in accordance with the applicable EPRI guidelines, ASTM 

standards, AISC specifications, and NUREG recommendations to prevent or mitigate 

degradation and failure of safety-related bolting caused by SCC.

In its review of components associated with item 3.5.1-93 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the ASME Section XI, 

Subsection IWF Program acceptable because, although the GALL Report doesn’t list stainless 

steel as a material in the evaluation of components associated with item 3.5.1-93, the staff 

would expect ASME Code Class 2 and 3 supports to be managed by the ASME Section XI, 

Subsection IWF Program.

The staff concludes that for LRA item 3.5.1-93, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.7 No Aging Effects Requiring Management

LRA Table 3.5-1, item 3.5.1-95 addresses aluminum, galvanized steel and stainless steel 

support members, welds, bolted connections, and support anchorage to building structure 

exposed to air-indoor uncontrolled and states that there are no AERM and no AMP is proposed. 

The GALL Report states that there are no AERM and no AMP is proposed for this component 

group. 

During its review of components associated with item 3.5.1-95, for which the applicant cited 

generic note A, the staff noted that the LRA cites this item for stainless steel components 

exposed to borated water leakage in addition to uncontrolled indoor air. The staff also noted 

that there are items in other sections of the GALL Report, such as items EP-19 or AP-18, which 

state that stainless steel components exposed to air with borated water leakage have no AERM. 

Although item 3.5.1-95 is for stainless steel components exposed to uncontrolled indoor air, the 

staff finds the applicant’s use of this item for stainless steel components exposed to borated 

water leakage acceptable because the conclusion that there are no AERM for this component 

group is consistent with the GALL Report recommendations documented in other items.

The staff noted that there are stainless steel ASME Code Class 1, 2, and 3 supports and 

mechanical equipment supports exposed to uncontrolled indoor air or borated water leakage in 

LRA Table 3.5.2-12, which cite item 3.5.1-95 and state that there are no AERM and no AMP is 

proposed. However, GALL Report AMP XI.S3, “ASME Section XI, Subsection IWF,” covers the 

inspection criteria for ASME Code Class 1, 2, and 3 component supports for license renewal 

and recommends visual inspection of a sample of supports. It was unclear to the staff why 

these ASME Code Class 1, 2, and 3 supports have no AERM, given that they appear to be 

within the scope of the ASME Section XI, Subsection IWF Program. By letter dated 

August 16, 2012, the staff issued RAI 3.5.1.095-1 requesting that the applicant provide 

justification for why the supports are not being managed using the ASME Section XI, 

Subsection IWF Program; or provide an appropriate program to manage the aging effects.
AGING MANAGEMENT REVIEW RESULTS

3-465

In its response dated September 20, 2012, the applicant stated that a single support may be 

constructed of more than one material and, therefore, have multiple entries in LRA 

Table 3.5.2-12. The applicant stated that the scope of the ASME Code Section XI, 

Subsection IWF Program and samples selected for inspection are based on individual 

component supports. The applicant also stated that even though part of a support may not 

require aging management, the entire support is within the program. The applicant confirmed 

that all ASME Code Class 1, 2, and 3 supports are within the scope of license renewal and are 

being managed by the ASME Section XI, Subsection IWF Program. The staff finds the 

applicant’s response acceptable because all ASME Code Class 1, 2, and 3 supports are being 

managed by the ASME Section XI, Subsection IWF Program. The staff’s concern described in 

RAI 3.5.1.095-1 is resolved.

The staff concludes that for LRA item 3.5.1-95, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.5.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the containments, structures, and component supports components and 

provides information concerning how it will manage the following aging effects:

(1) PWR and BWR containments:

 • cracking and distortion due to increased stress levels from settlement; reduction of 

foundation strength and cracking due to differential settlement and erosion of porous 

concrete subfoundations

 • reduction of strength and modulus due to elevated temperature

 • loss of material due to general, pitting, and crevice corrosion

 • loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

 • cumulative fatigue damage

 • cracking due to SCC

 • cracking due to cyclic loading

 • loss of material (scaling, cracking, and spalling) due to freeze-thaw

 • cracking due to expansion and reaction with aggregates

(2) safety-related and other structures and component supports:

 • aging management of inaccessible areas

 • reduction of strength and modulus due to elevated temperature 

 • aging management of inaccessible areas for Group 6 structures 

 • cracking due to SCC and loss of material due to pitting and crevice corrosion

 • cumulative fatigue damage due to fatigue

(3) QA for aging management of nonsafety-related components
AGING MANAGEMENT REVIEW RESULTS

3-466

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 it 

adequately addressed the issues further evaluated. In addition, the staff reviewed the 

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. The 

staff’s review of the applicant’s further evaluation follows.

3.5.2.2.1 PWR and BWR Containments 

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1, which 

address several areas:

Cracking and Distortion Due to Increased Stress Levels from Settlement; Reduction of 

Foundation Strength, and Cracking Due to Differential Settlement and Erosion of Porous 

Concrete Subfoundations. LRA Section 3.5.2.2.1.1, associated with LRA Table 3.5-1, 

items 3.5.1-1 and 3.5.1-2, addresses concrete exposed to soil or water which will be managed 

for cracking due to settlement or cracking and loss of foundation strength due to erosion of 

porous concrete subfoundations by the Structures Monitoring Program or the ASME Section XI, 

Subsection IWL Program. The criteria in SRP-LR Section 3.5.2.2.1.1 states that cracking and 

distortion and reduction of foundation strength could occur for concrete and steel containments 

exposed to soil or water, and if a dewatering system is used to control settlement further 

evaluation is necessary. The applicant addressed the further evaluation criteria of the SRP-LR 

by stating that there are no porous subfoundations on the site and no permanent dewatering 

systems are installed or planned.

The staff’s evaluation of the applicant’s Structures Monitoring and ASME Section XI, 

Subsection IWL Programs is documented in SER Sections 3.0.3.2.17 and 3.0.3.1.12, 

respectively. The staff reviewed FSAR-SP Section 3.4.1.2 and FSAR-SA Section 2.4.13.5 and 

noted that no dewatering system was installed or planned. In its review of components 

associated with items 3.5.1-1 and 3.5.1-2, the staff finds that the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the Structures 

Monitoring and ASME Section XI, Subsection IWL Programs is acceptable because these 

programs are the GALL Report recommended programs, and additional further evaluation is 

unnecessary since no permanent dewatering system is used on site.

Based on the programs identified, the staff concludes that the applicant meets the SRP-LR 

Section 3.5.2.2.1.1 criteria. For those items associated with LRA Section 3.5.2.2.1.1, the staff 

determined 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(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

Reduction of Strength and Modulus Due to Elevated Temperature. LRA Section 3.5.2.2.1.2, 

associated with LRA Table 3.5-1, item 3.5.1-3, addresses reduction of strength and modulus 

due to elevated temperatures in concrete exposed to indoor or outdoor air. The applicant stated 

that this item is not applicable because containment concrete temperatures are maintained 

below the GALL Report limits of 66 °C (150 °F) for general areas and 93 °C (200 °F) for local 

areas. The staff reviewed LRA Sections 2.4.1 and 3.5, and the FSAR and finds that no in-scope 

containment concrete is exposed to elevated temperatures beyond the GALL Report limits; 

therefore, a plant-specific aging management program is not required and further evaluation of 

this aging effect is not necessary.
AGING MANAGEMENT REVIEW RESULTS

3-467

Loss of Material Due to General, Pitting and Crevice Corrosion. LRA Section 3.5.2.2.1.3, 

associated with LRA Table 3.5.1, items 3.5.1-4 through 3.5.1-7, addresses the following: 

(1) Steel Elements of Inaccessible Areas for all types of PWR and BWR Containments. 

LRA Section 3.5.2.2.1.3.1, associated with LRA Table 3.5-1, item 3.5.1-4, addresses 

loss of material due to general, pitting ,and crevice corrosion in the steel elements 

(inaccessible areas). The applicant stated that this item is not applicable because 

Callaway is a PWR. The staff evaluated the applicant's claim by reviewing the LRA, 

SRP-LR and FSAR and finds the applicant’s claim acceptable because this item is only 

applicable to BWRs.

LRA Section 3.5.2.2.1.3.1 associated with LRA Table 3.5.1 items 3.5.1-5, addresses 

steel elements (inaccessible areas): liner, liner anchors, and integral attachments 

exposed to plant indoor air which will be managed for loss of material by the ASME 

Section XI, Subsection IWE and 10 CFR Part 50, Appendix J Programs. The criteria in 

SRP-LR Section 3.5.2.2.1.3, item 1 states that loss of material due to general, pitting, 

and crevice corrosion could occur for steel elements of inaccessible areas for all types of 

PWR and BWR containments exposed to plant indoor air. The SRP-LR recommends 

further evaluation of plant-specific programs to manage this aging effect if corrosion is 

indicated by ASME Code Section XI, Subsection IWE examinations. GALL Report 

item II.A1.CP-98 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: 

(i) 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.

(ii) 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.

(iii) 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.

(iv) Borated water spills and water ponding on the containment concrete floor is not 

common and, when detected, is cleaned up in a timely manner.

The applicant addressed the further evaluation criteria of the SRP-LR by stating that 

reinforced concrete structures were designed, constructed, and inspected in accordance 

with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and 

low permeability concrete. The applicant stated that the mix proportions were 

established in accordance with ACI 301 and the mix designs contain an air-entraining 

admixture in accordance with ASTM C260, and maximum water content was controlled 

by placing the concrete at specified slumps. The staff reviewed the applicant’s FSAR 

Section 3.8.1.6.1 and confirmed the properties of the concrete mix. The staff also noted 

that conveying and placement of the concrete was done in accordance with ACI 318 

code, which meets many of the recommendations of ACI 201.2R by providing low 

permeability concrete using a low water-cement ratio based on minimum slump. The 

ACI 318 code provides requirements for concrete placement and curing to ensure the 

required concrete quality, durability, and strength are attained (concrete used in the 

construction of the reactor building shell and dome has a compressive strength of 6,000 

psi at 90 days and the structural concrete used in the construction of the reactor building 

base slab, reactor cavity, instrumentation tunnel, and tendon access gallery has a 
AGING MANAGEMENT REVIEW RESULTS

3-468

compressive strength of 5,000 psi at 90 days). Therefore, the staff finds that the 

applicant adequately addressed condition (i) above.

The applicant stated that the ASME Section XI, Subsection IWL Program identifies and 

manages any cracks in the containment concrete that could potentially provide a 

pathway for water to reach inaccessible portions of the steel containment liner. The 

applicant also stated that crack control was achieved through proper sizing, spacing, and 

distribution of reinforcing steel in accordance with ACI 318-71. The staff confirmed the 

applicant’s statements by reviewing FSAR Section 3.8.1.2.2 and the ASME Section XI, 

Subsection IWL Program and finds that the applicant adequately addressed condition (ii) 

above, by ensuring that the concrete is monitored to ensure that it is free of cracks that 

may allow water to penetrate and seep onto the steel liner. 

The LRA states that the applicant manages aging of the moisture barrier at the interface 

between the liner and the concrete with the ASME Section XI, Subsection IWE Program. 

However, by letter dated August 9, 2012, in response to RAI B2.1.26-1, the applicant 

stated that there is no moisture barrier seal at the interface between the containment 

liner and the internal concrete floor. The applicant revised the LRA to remove the 

statement that the ASME Section XI, Subsection IWE program manages aging of the 

moisture barrier between the liner and the concrete.

The applicant stated that its procedural controls ensure that borated water spills are not 

common, and when detected are cleaned up in a timely manner. This is consistent with 

the criteria recommended in the GALL Report. The staff finds that the applicant 

adequately addressed conditions (iii) and (iv) above.

The staff reviewed the applicant’s operating experience associated with the ASME 

Section XI, Subsection IWE Program to determine if the examinations have discovered 

corrosion. The staff’s independent review and the applicant’s internal review did not find 

operating experience that indicated there was a corrosion issue, therefore a 

plant-specific program to manage loss of material caused by general, pitting, and crevice 

corrosion is not necessary. 

The staff’s evaluation of the applicant’s ASME Section XI, Subsection IWE and 10 CFR 

Part 50, Appendix J Programs are documented in SER Sections 3.0.3.2.15 and 

3.0.3.1.13, respectively. In its review of components associated with item 3.5.1-5 the 

staff finds that the applicant has met the further evaluation criteria, and the applicant’s 

proposal to manage aging using the ASME Section XI, Subsection IWE and 10 CFR 

Part 50, Appendix J Programs is acceptable because the applicant proposes to manage 

the aging of inaccessible areas of steel elements using the GALL Report recommended 

programs, and the applicant has satisfied the four conditions identified in GALL Report 

item II.A1.CP-98.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1.3, item 1 criteria. For those items associated with LRA 

Section 3.5.2.2.1.3.1, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

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

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) Steel Torus Shell of Mark I Containments. LRA Section 3.5.2.2.1.3.2, associated with 

LRA Table 3.5-1, item 3.5.1-6, addresses loss of material due to general, pitting and 

crevice corrosion in the steel torus shell of Mark I BWR containments exposed to either 

an air-indoor uncontrolled or treated water environment. The GALL Report recommends 
AGING MANAGEMENT REVIEW RESULTS

3-469

GALL Report AMP XI.S1, "ASME Section XI, Subsection IWE," and GALL Report 

AMP XI.S4, "10 CFR Part 50, Appendix J," to manage for loss of material due to

general, pitting, and crevice corrosion for this component group. The applicant stated 

that this item is not applicable because Callaway is a PWR with a prestressed concrete 

containment that does not use a steel torus shell. The staff evaluated the applicant's 

claim by reviewing LRA Sections 2.4.1 and 3.5 and finds it acceptable because Callaway 

is a PWR.

(3) Steel Torus Ring Girders and Downcomers of Mark I Containments, Downcomers of 

Mark II Containments, and Interior Surface of Suppression Chamber Shell of Mark III 

Containments. LRA Section 3.5.2.2.1.3.3, associated with LRA Table 3.5-1, 

item 3.5.1-7, addresses loss of material due to general, pitting and crevice corrosion in 

steel elements: torus ring girders; downcomers; suppression chamber shell (inner 

surface) of Mark I and Mark II BWR containments exposed to either an air-indoor 

uncontrolled or treated water environment. The GALL Report recommends GALL 

Report AMP XI.S1, "ASME Section XI, Subsection IWE," and GALL Report AMP XI.S4, 

"10 CFR Part 50, Appendix J," to manage for loss of material caused by general, pitting, 

and crevice corrosion for this component group. The applicant stated that this item is 

not applicable because Callaway is a PWR with a prestressed concrete containment that 

does not use these steel components. The staff evaluated the applicant's claim by 

reviewing LRA Sections 2.4.1 and 3.5 and finds it acceptable because Callaway is a 

PWR.

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA

Section 3.5.2.2.1.4, associated with LRA Table 3.5-1, item 3.5.1-8, addresses steel prestressing

tendons exposed to either an air-indoor uncontrolled or air-outdoor environment. LRA 

Section 3.5.2.2.1.4 states that loss prestress forces caused by relaxation, shrinkage, creep, and 

elevated temperature for prestressed concrete containments is a TLAA and that the evaluation 

of this TLAA is addressed in LRA Section 4.5. This is consistent with SRP-LR Section 

3.5.2.2.1.4 and is, therefore, acceptable.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.5.2.2.1.4 criteria. For those items that apply to LRA Section 3.5.2.2.1.4, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Section 4.5 documents the staff’s review of the 

applicant’s evaluation of the TLAAs for these components.

Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.5, associated with LRA Table 3.5-1, 

item 3.5.1-9, addresses the TLAAs (if CLB fatigue analyses exist) of suppression pool steel 

shells (including welded joints) and penetrations (including penetration sleeves, dissimilar metal 

welds, and penetration bellows) for all types of PWR and BWR containments and BWR vent 

header, vent line bellows, and downcomers exposed to either an uncontrolled indoor air, treated 

water, or outdoor air environment that will be managed for cumulative fatigue damage due to 

cyclic loading by a TLAA.

LRA Section 3.5.2.2.1.5 states that this analysis is associated with a TLAA and that the 

evaluation of this TLAA is addressed in Section 4.6.1 and 4.6.2. This is consistent with SRP-LR 

Section 3.5.2.2.1.5 and is, therefore, acceptable. 
AGING MANAGEMENT REVIEW RESULTS

3-470

Based on its review, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.1.5 

criteria. For those items that apply to LRA Section 3.5.2.2.1.5, the staff determined that the LRA 

is consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). SER 

Section 4.6 documents the staff’s review of the applicant’s evaluation of the TLAAs for these 

components.

Cracking Due to Stress Corrosion Cracking. LRA Section 3.5.2.2.1.6, associated with LRA 

Table 3.5-1, item 3.5.1-10, addresses steel penetration sleeves, penetration bellows, exposed 

to air-indoor uncontrolled which will be managed for cracking by the 10 CFR Part 50 Appendix J 

and ASME Section XI, Subsection IWE Programs.

The applicant stated that it does not have any stainless steel penetration bellows in scope as 

part of the containment pressure boundary. The applicant also stated that stainless steel high 

energy pipes that penetrate the containment are connected to carbon steel penetration sleeves 

with dissimilar metal welds. The applicant further stated that plant operating experience has not 

identified any SCC associated with these welds. 

The criteria in SRP-LR Section 3.5.2.2.1.6 states that cracking due to SCC of stainless steel 

penetration bellows and dissimilar metal welds could occur in all types of PWR and BWR 

containments. The SRP-LR also states that the existing program relies on ASME Section XI, 

Subsection IWE and 10 CFR Part 50, Appendix J Programs to manage this aging effect. The 

SRP-LR further states that the GALL Report recommends further evaluation of additional 

appropriate examinations/evaluations implemented to detect these aging effects for stainless 

steel penetration bellows and dissimilar metal welds.

The staff’s review of the applicant’s ASME Section XI, Subsection IWE and 10 CFR Part 50, 

Appendix J Programs and its evaluations are documented in SER Sections 3.0.3.2.15 and 

3.0.3.1.13, respectively. The staff finds that the credited programs are adequate to manage the 

aging effect because: (a) the applicant’s use of the programs to manage the aging effect is 

consistent with the recommendation in the GALL Report and (b) the applicant’s operating 

experience review results indicate that there have been no occurrences of SCC in the 

components which supports the applicant’s claim that no augmented or additional inspections 

are required to manage the aging effect for the components. On the basis of its review, the staff 

finds that the applicant’s AMR results are consistent with the GALL Report, and the applicant 

has met the further evaluation criteria in SRP-LR Section 3.5.2.2.1.6.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.5.2.2.1.6 criteria. For those items associated with LRA Section 3.5.2.2.1.6, 

the staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw. LRA 

Section 3.5.2.2.1.7, associated with LRA Table 3.5-1, item 3.5.1-11, addresses loss of material 

and cracking due to freeze-thaw for inaccessible concrete exposed to outdoor-air, soil, or water. 

The criteria in SRP-LR Section 3.5.2.2.1.7 states that loss of material and cracking caused by 

freeze-thaw could occur for concrete exposed to outdoor-air, soil, or water and that evaluation is 

recommended for plants located in moderate to severe weathering conditions. The SRP-LR 

also states that a plant-specific program is not required if documented evidence confirms the 
AGING MANAGEMENT REVIEW RESULTS

3-471

existing concrete had air content between three and eight percent, and subsequent inspection 

of accessible areas did not exhibit degradation related to freeze-thaw. The applicant addressed 

the further evaluation criteria of the SRP-LR by stating that a plant-specific AMP is not required 

and the aging effect is not applicable because the concrete mix designs contained an 

air-entraining admixture capable of entraining three to six percent air and plant operating 

experience has not identified any aging effects related to freeze-thaw in accessible areas.

The staff reviewed FSAR-SP Section 3.8.1.6.1.1 and confirmed that appropriate air-entrainment 

was used in the concrete mix design. The staff also conducted an independent review of the 

applicant’s operating experience and did not identify any freeze-thaw related concrete 

degradation. In its review of components associated with item 3.5.1-11, the staff finds the 

applicant’s determination that this aging effect is not applicable acceptable because the 

appropriate air content was used in the concrete and there is no site-specific operating 

experience with freeze-thaw degradation.

Cracking Due to Expansion from Reaction with Aggregates. LRA Section 3.5.2.2.1.8, 

associated with LRA Table 3.5-1, item 3.5.1-12, addresses cracking caused by expansion from 

reaction with aggregates for inaccessible concrete exposed to any environment. The criteria in 

SRP-LR Section 3.5.2.2.1.8 states that further evaluation is recommended to determine if a 

plant-specific AMP is required to manage this aging effect. The SRP-LR also states that a 

plant-specific program is not required if: (1) investigations, tests, and petrographic examinations 

of aggregates performed in accordance with ASTM C295 and other ASTM reactivity tests can 

demonstrate the aggregates do not adversely react with concrete, or (2) for potentially reactive 

aggregates, the structure was constructed in accordance with ACI 318. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that a plant-specific AMP is 

not required because a petrographic examination of the aggregates was conducted in 

accordance with ASTM C295 and the concrete was constructed in accordance with applicable 

ACI and ASTM standards.

The staff reviewed FSAR-SP Section 3.8.1.2.2 and Table 3.2-1 and confirmed that the 

aggregates were tested for reactivity in accordance with ASTM C289, a petrographic analysis 

was conducted per ASTM C295, and the structures were constructed in accordance with 

ACI 318. In its review of components associated with item 3.5.1-12, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s determination that a 

plant-specific program is not necessary is acceptable because the appropriate ASTM standards 

were followed and the concrete was constructed in accordance with ACI 318.

Based on its review, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.1.8 

criteria. For those items associated with LRA Section 3.5.2.2.1.8, the staff determined 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(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide and Carbonation. 

LRA Section 3.5.2.2.1.9, associated with LRA Table 3.5-1, items 3.5.1-13 and 3.5.1-14, 

addresses increase in porosity and permeability caused by leaching of calcium hydroxide and 

carbonation of inaccessible concrete exposed to flowing water. The criteria in SRP-LR 

Section 3.5.2.2.1.9 states that further evaluation is recommended if leaching is observed in 

accessible areas. The SRP-LR also states that a plant-specific program is not required if: 

(1) there is evidence in the accessible areas that the flowing water has not caused leaching and 

carbonation, or (2) evaluation determined that the observed leaching of calcium hydroxide and 
AGING MANAGEMENT REVIEW RESULTS

3-472

carbonation in accessible areas has no impact on the intended function of the concrete 

structure. The applicant addressed the further evaluation criteria of the SRP-LR by stating that 

the concrete structures were designed, constructed, and inspected in accordance with ACI and 

ASTM standards, which provide for a good quality, dense well-cured and low permeability 

concrete. However, no discussion was provided about operating experience with leaching of 

accessible concrete. Therefore, by letter dated July 9, 2012, the staff issued RAI 3.5.2.2.1.9-1 

requesting that the applicant provide a summary of any operating experience with concrete 

leaching and an appropriate AMP or evaluation to address any concrete leaching.

In its response dated August 9, 2012, the applicant stated that no significant leaching has 

occurred in structures within the scope of license renewal. The applicant stated that the only 

identified leaching has been minor, with any significant water in-leakage occurring through 

degraded elastomeric seals, which have been evaluated. The applicant also stated that an 

engineering evaluation was conducted on the minor leaching identified in the tendon gallery. 

The applicant stated that the substance was analyzed and found to be composed of sodium and 

potassium carbonate with no calcium or iron. In addition, the applicant stated that a visual 

inspection of the wall did not identify concrete cracking or any signs of rust or corrosion. The 

applicant further stated that the tendon gallery is included in the scope of the Structures 

Monitoring Program and that the program will continue to monitor structures within the scope of 

license renewal for leaching during the period of extended operation.

The staff reviewed the applicant’s response and noted that only minor indications of leaching 

have been identified. The staff also noted that the Structures Monitoring Program inspects for 

indications of leaching. The staff finds the applicant’s response acceptable because it explains 

that the identified tendon gallery leaching was reviewed, evaluated, and found to have no 

impact on the function of the structure. The response further explains that the Structures 

Monitoring Program, which is the GALL Report recommended program, will monitor for this 

aging effect during the period of extended operation. The staff’s concern described in 

RAI 3.5.2.2.1.9-1 is resolved.

In its review of components associated with items 3.5.1-13 and 3.5.1-14, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage aging 

using the Structures Monitoring Program is acceptable because this program is the GALL 

Report recommended program, and because the applicant stated that it does not have any 

operating experience with significant leaching that would impact the intended function of a 

structure. The staff finds that an additional plant-specific program is unnecessary for 

inaccessible concrete since an evaluation determined that the observed minor leaching in 

accessible areas has no impact on the intended function of the concrete structure.

Based on its review, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.1.9 

criteria. For those items associated with LRA Section 3.5.2.2.1.9, the staff concludes that the 

LRA is consistent with the GALL Report and the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.2.2. Safety-Related and Other Structures and Component Supports

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2, which 

address several areas:
AGING MANAGEMENT REVIEW RESULTS

3-473

Aging Management of Inaccessible Areas. 

(1) Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thawin Below-Grade.

Inaccessible Concrete Areas of Groups 1-3, 5, and 7-9 Structures. LRA 

Section 3.5.2.2.2.1.1, associated with LRA Table 3.5-1, item 3.5.1-42, addresses loss of 

material and cracking due to freeze-thaw for inaccessible concrete exposed to 

outdoor-air. The criteria in SRP-LR Section 3.5.2.2.2.1, item 1 states that loss of 

material and cracking caused by freeze-thaw could occur in below-grade inaccessible 

concrete areas and that evaluation is recommended for plants located in moderate to 

severe weathering conditions. The SRP-LR also states that a plant-specific program is 

not required if documented evidence confirms the existing concrete had air content 

between three and eight percent, and subsequent inspection of accessible areas did not 

exhibit degradation related to freeze-thaw. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that a plant-specific AMP is not required 

because the concrete mix designs contained an air-entraining admixture capable of 

entraining three to six percent air and plant operating experience has not identified any 

aging effects related to freeze-thaw in accessible areas.

The staff reviewed FSAR-SP Section 3.8.1.6.1 and confirmed that appropriate 

air-entrainment was used in the concrete mix design. The staff also conducted an 

independent review of the applicant’s operating experience and did not identify any 

freeze-thaw related concrete degradation. In its review of components associated with 

item 3.5.1-42, the staff finds that the applicant has met the further evaluation criteria, and 

the applicant’s determination that a plant-specific program is not necessary is acceptable 

because the appropriate air content was used in the concrete and there is no 

site-specific operating experience with freeze-thaw degradation.

Based on its review, the staff concludes that the applicant meets SRP-LR 

Section 3.5.2.2.2.1, item 1 criteria. For those items associated with LRA 

Section 3.5.2.2.2.1.1, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) Cracking Due to Expansion and Reaction with Aggregates of Groups 1-5 and 7-9 

Structures. LRA Section 3.5.2.2.2.1.2, associated with LRA Table 3.5-1, item 3.5.1-43, 

addresses cracking due to expansion from reaction with aggregates for inaccessible 

concrete exposed to any environment. The criteria in SRP-LR Section 3.5.2.2.2.1, 

item 2 states further evaluation is recommended to determine if a plant-specific AMP is 

required to manage this aging effect. The SRP-LR also states that a plant-specific 

program is not required if: (1) investigations, tests, and petrographic examinations of 

aggregates performed in accordance with ASTM C295 and other ASTM reactivity tests 

can demonstrate the aggregates do not adversely react with concrete, or (2) for 

potentially reactive aggregates, the structure was constructed in accordance with 

ACI 318. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that a plant-specific AMP is not required because a petrographic examination of 

the aggregates was conducted in accordance with ASTM C295 and the concrete was 

constructed in accordance with applicable ACI and ASTM standards.

The staff reviewed FSAR-SP Section 3.8.1.2.2 and Table 3.2-1 and confirmed that the 

aggregates were tested for reactivity in accordance with ASTM C289, a petrographic 

analysis was conducted per ASTM C295, and the structures were constructed in 
AGING MANAGEMENT REVIEW RESULTS

3-474

accordance with ACI 318. In its review of components associated with item 3.5.1-43, the 

staff finds that the applicant has met the further evaluation criteria, and the applicant’s 

determination that a plant-specific program is not necessary is acceptable because the 

appropriate ASTM standards were followed and the concrete was constructed in 

accordance with ACI 318.

Based on its review, the staff concludes that the applicant meets SRP-LR 

Section 3.5.2.2.2.1, item 2 criteria. For those items associated with LRA 

Section 3.5.2.2.2.1.2, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(3) Cracking and Distortion Due to Increased Stress Levels from Settlement for 

Below-Grade Inaccessible Concrete Areas of Structures for all Groups and Reduction in 

Foundation Strength and Cracking Due to Differential Settlement and Erosion of Porous 

Concrete Subfoundations in Below-Grade Inaccessible Concrete Areas for Groups 1-3, 

and 5-9 Structures. LRA Section 3.5.2.2.2.1.3, associated with LRA Table 3.5-1, 

items 3.5.1-44 and 3.5.1-46, addresses concrete exposed to soil or water which will be 

managed for cracking caused by settlement or cracking and loss of foundation strength 

caused by erosion of porous concrete subfoundations by the Structures Monitoring 

Program. The criteria in SRP-LR Section 3.5.2.2.2.1, item 3 states that cracking and 

distortion and reduction of foundation strength could occur for concrete structures 

exposed to soil or water, and if a dewatering system is used to control settlement further 

evaluation is necessary. The applicant addressed the further evaluation criteria of the 

SRP-LR by stating that Callaway is a PWR and there are no porous subfoundations on 

the site and no permanent dewatering systems are installed or planned.

The staff evaluations of the applicant’s Structures Monitoring is documented in SER 

Sections 3.0.3.2.17. The staff reviewed FSAR-SP Section 3.4.1.2 and FSAR-SA 

Section 2.4.13.5 and noted that no dewatering system was installed or planned. The 

staff also noted that Callaway is a PWR and has no porous concrete foundations; 

therefore, items 3.5.1-45 and 3.5.1-46 are not applicable. In its review of components 

associated with items 3.5.1-44 and 3.5.1-46, the staff finds that the applicant has met the 

further evaluation criteria, and the applicant’s proposal to manage aging using the 

Structures Monitoring Program is acceptable because the program is the GALL Report 

recommended program. Additional further evaluation is unnecessary since no 

permanent dewatering system is used on site.

Based on the programs identified, the staff concludes that the applicant meets SRP-LR 

Section 3.5.2.2.2.1, item 3 criteria. For those items associated with LRA 

Section 3.5.2.2.2.1.3, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

(4) Increase in Porosity and Permeability, and Loss of Strength Due to Leaching of Calcium 

Hydroxide and Carbonation for Groups 1-5 and 7-9 structures. LRA 

Section 3.5.2.2.2.1.4, associated with LRA Table 3.5-1, item 3.5.1-47, addresses 

increase in porosity and permeability due to leaching of calcium hydroxide and 

carbonation of inaccessible concrete exposed to flowing water. The criteria in SRP-LR 

Section 3.5.2.2.2.1, item 4 states that further evaluation is recommended if leaching is 

observed in accessible areas. The SRP-LR also states that a plant-specific program is 
AGING MANAGEMENT REVIEW RESULTS

3-475

not required if: (1) there is evidence in the accessible areas that the flowing water has 

not caused leaching and carbonation, or (2) evaluation determined that the observed 

leaching of calcium hydroxide and carbonation in accessible areas has no impact on the 

intended function of the concrete structure. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the concrete structures were designed, 

constructed, and inspected in accordance with ACI and ASTM standards, which provide 

for a good quality, dense, well-cured, and low permeability concrete. However, no 

discussion was provided about operating experience associated with leaching of 

accessible concrete. Therefore, by letter dated July 9, 2012, the staff issued 

RAI 3.5.2.2.1.9-1 requesting that the applicant provide a summary of any operating 

experience associated with concrete leaching and an appropriate AMP or evaluation to 

address any concrete leaching.

In its response dated August 9, 2012, the applicant stated that no significant leaching

has occurred in structures within the scope of license renewal. The applicant stated that 

the only identified leaching has been minor, with any significant water in-leakage 

occurring through degraded elastomeric seals, which have been evaluated. The 

applicant also stated that an engineering evaluation was conducted on the minor 

leaching identified in the tendon gallery and the substance was analyzed and found to 

be composed of sodium and potassium carbonate with no calcium or iron. The applicant 

further stated that a visual inspection of the wall did not identify concrete cracking or any 

signs of rust or corrosion. The applicant also stated that the tendon gallery is included in 

the scope of the Structures Monitoring Program and that the program will continue to 

monitor structures within the scope of license renewal for leaching during the period of 

extended operation.

The staff reviewed the applicant’s response and noted that only minor indications of 

leaching have been identified. The staff also noted that the Structures Monitoring 

Program inspects for indications of leaching. The staff finds the applicant’s response 

acceptable because it explains that the identified tendon gallery leaching was reviewed, 

evaluated, and found to have no impact on the function of the structure. The response 

further explains that the Structures Monitoring Program, which is the GALL Report 

recommended program, will monitor for this aging effect during the period of extended 

operation. The staff’s concern described in RAI 3.5.2.2.1.9-1 is resolved.

In its review of components associated with items 3.5.1-47, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Structures Monitoring Program is acceptable because this program is 

the GALL Report recommended program, and because the applicant stated that it does 

not have any operating experience with significant leaching that would impact the 

intended function of a structure. An additional plant-specific program is unnecessary for 

inaccessible concrete since an evaluation determined that the observed minor leaching 

in accessible areas has no impact on the intended function of the concrete structure.

Based on its review, the staff concludes that the applicant meets SRP-LR 

Section 3.5.2.2.2.1, item 4 criteria. For those items associated with LRA 

Section 3.5.2.2.2.1.4, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Reduction of Strength and Modulus Due to Elevated Temperature. LRA Section 3.5.2.2.2.2, 

associated with LRA Table 3.5-1, item 3.5.1-48, addresses reduction of strength and modulus 
AGING MANAGEMENT REVIEW RESULTS

3-476

caused by elevated temperatures in concrete exposed to indoor air. The criteria in SRP-LR 

Section 3.5.2.2.2.2 states that further evaluation is recommended for any concrete elements 

that exceed specified temperature limits. The GALL Report provides the temperature limits as 

66 °C (150 °F) for general areas and 93 °C (200 °F) for local areas. The SRP-LR also states 

that higher temperatures may be allowed if tests or calculations are provided to evaluate the 

reduction in strength and modulus of elasticity and these reductions are applied to the design 

calculations. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that concrete structures in the plant have been designed, or provided with appropriate cooling, 

to keep concrete temperatures below the specified limits, except for the area directly below the 

seal ring support, which is limited to 300 °F. The applicant further stated that an engineering 

evaluation was performed to ensure that the elevated temperature in the seal ring support 

concrete would not be detrimental to the ability of the concrete to perform its intended functions.

The staff reviewed the FSAR and noted that the concrete was maintained below the 

temperature limits identified in the GALL Report except for the seal ring support concrete. The 

staff reviewed FSAR-SP Section 3.8.3.4.2 and noted that the concrete temperature for the seal 

ring support is limited to 300 °F; however, the staff did not find any discussion of the possible 

reduction in strength and modulus caused by the higher temperatures. Therefore, by letter 

dated August 6, 2012, the staff issued RAI 3.5.2.2.2.2-1 requesting that the applicant provide 

information on how the high temperature was accounted for in the analysis of the seal ring 

support concrete.

In its response dated September 6, 2012, the applicant stated that an engineering calculation 

was performed to address the effects of the elevated temperature. The evaluation showed that 

the elevated temperatures could reduce the strength of the concrete to approximately 

60 percent of the original design strength. The applicant explained that this reduced strength 

value was used to calculate allowable stresses, which were compared to the maximum design 

loads, and found to be acceptable.

The staff finds the applicant’s response acceptable because the applicant identified an 

appropriate reduction in the strength of the concrete caused by the high temperatures and 

designed the structures accordingly. The staff’s concern described in RAI 3.5.2.2.2.2-1 is 

resolved.

In its review of components associated with items 3.5.1-48, the staff finds that the applicant has 

met the further evaluation criteria, and the applicant’s analysis is acceptable because concrete 

structures exposed to temperatures above the GALL Report limits have been analyzed and the 

proper strength reductions have been applied to the design calculations.

Based on its review, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.2.2 

criteria. For those items associated with LRA Section 3.5.2.2.2.2, the staff determined that the 

LRA is consistent with the GALL Report and that the applicant has demonstrated that the effects 

of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

Aging Management of Inaccessible Areas for Group 6 Structures. SRP-LR Section 3.5.2.2.2.3 

addresses aging management of inaccessible areas for Group 6 structures (below-grade 

inaccessible concrete areas) and recommends further evaluation for inaccessible areas of 

certain Group 6 structure/aging effect combinations as identified below whether they are 

covered by inspections in accordance with the GALL Report AMP XI.S7, “RG 1.127, Inspection 
AGING MANAGEMENT REVIEW RESULTS

3-477

of Water-Control Structures Associated with Nuclear Power Plants,” or FERC/US Army Corps of 

Engineers dam inspection and maintenance procedures.

(1) Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw That Could Occur 

in Below-Grade Inaccessible Concrete Areas of Group 6 Structures. LRA 

Section 3.5.2.2.2.3.1, associated with LRA Table 3.5-1, item 3.5.1-49, addresses loss of 

material and cracking due to freeze-thaw for inaccessible concrete exposed to 

outdoor-air. The criteria in SRP-LR Section 3.5.2.2.2.3, item 1 states that loss of 

material and cracking due to freeze-thaw could occur in below-grade inaccessible 

concrete areas and that further evaluation is recommended for plants located in 

moderate to severe weathering conditions. The SRP-LR also states that a plant-specific 

program is not required if documented evidence confirms the existing concrete had air 

content between three and eight percent, and subsequent inspection of accessible areas 

did not exhibit degradation related to freeze-thaw. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that a plant-specific aging management 

program is not required because the concrete mix designs contained an air-entraining 

admixture capable of entraining three to six percent air and plant operating experience 

has not identified any aging effects related to freeze-thaw in accessible areas.

The staff reviewed FSAR-SP Section 3.8.1.6.1 and confirmed that appropriate 

air-entrainment was used in the concrete mix design. The staff also conducted an 

independent review of the applicant’s operating experience and did not identify any 

freeze-thaw related concrete degradation. In its review of components associated with 

item 3.5.1-49, the staff finds that the applicant has met the further evaluation criteria, and 

the applicant’s determination that a plant-specific program is not necessary is acceptable 

because the appropriate air content was used in the concrete and there is no 

site-specific operating experience with freeze-thaw degradation.

Based on its review, the staff concludes that the applicant meets SRP-LR 

Section 3.5.2.2.2.3, item 1 criteria. For those items associated with LRA 

Section 3.5.2.2.2.3.1, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) Cracking Due to Expansion and Reaction with Aggregates That Could Occur in 

Below-Grade Inaccessible Concrete Areas of Group 6 Structures. LRA 

Section 3.5.2.2.2.3.2, associated with LRA Table 3.5-1, item 3.5.1-50, addresses 

cracking due to expansion from reaction with aggregates for inaccessible concrete 

exposed to any environment. The criteria in SRP-LR Section 3.5.2.2.2.3, item 2 states 

that further evaluation is recommended to determine if a plant-specific aging 

management program is required to manage this aging effect. The SRP-LR also states 

that a plant-specific program is not required if: (1) investigations, tests, and petrographic 

examinations of aggregates performed in accordance with ASTM C295 and other ASTM 

reactivity tests can demonstrate the aggregates do not adversely react with concrete, or 

(2) for potentially reactive aggregates, the structure was constructed in accordance with 

ACI 318. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that a plant-specific aging management program is not required because a 

petrographic examination of the aggregates was conducted in accordance with 

ASTM C295 and the concrete was constructed in accordance with applicable ACI and 

ASTM standards.
AGING MANAGEMENT REVIEW RESULTS

3-478

The staff reviewed FSAR-SP Section 3.8.1.2.2 and Table 3.2-1 and confirmed the 

aggregates were tested for reactivity in accordance with ASTM C289, a petrographic 

analysis was conducted per ASTM C295, and the structures were constructed in 

accordance with ACI 318. In its review of components associated with item 3.5.1-50, the 

staff finds that the applicant has met the further evaluation criteria, and the applicant’s 

determination that a plant-specific program is not necessary is acceptable because the 

appropriate ASTM standards were followed and the concrete was constructed in 

accordance with ACI 318.

Based on its review, the staff concludes that the applicant meets SRP-LR 

Section 3.5.2.2.2.3, item 2 criteria. For those items associated with LRA 

Section 3.5.2.2.2.3.2, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(3) Increase in Porosity and Permeability and Loss of Strength Due to Leaching of Calcium 

Hydroxide and Carbonation That Could Occur in Below-Grade Inaccessible Concrete 

Areas of Group 6 Structures. LRA Section 3.5.2.2.2.3.3, associated with LRA 

Table 3.5-1, item 3.5.1-51, addresses increase in porosity and permeability due to 

leaching of calcium hydroxide and carbonation of inaccessible concrete elements of 

Group 6 structures exposed to flowing water. The criteria in SRP-LR 

Section 3.5.2.2.2.3, item 3 states that further evaluation is recommended if leaching is 

observed in accessible areas. The SRP-LR also states that a plant-specific program is 

not required if: (1) there is evidence in the accessible areas that the flowing water has 

not caused leaching and carbonation, or (2) evaluation determined that the observed 

leaching of calcium hydroxide and carbonation in accessible areas has no impact on the 

intended function of the concrete structure. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the concrete structures were designed, 

constructed, and inspected in accordance with ACI and ASTM standards, which provide 

for a good quality, dense well-cured and low permeability concrete. However, no 

discussion was provided about operating experience with leaching of accessible 

concrete. Therefore, by letter dated July 9, 2012, the staff issued RAI 3.5.2.2.1.9-1 

requesting that the applicant provide a summary of any operating experience with 

concrete leaching and provide an appropriate AMP or evaluation to address any 

concrete leaching.

In its response dated August 9, 2012, the applicant stated that no significant leaching 

has occurred in structures within the scope of license renewal. The applicant stated that 

the only identified leaching has been minor, with any significant water in-leakage 

occurring through degraded elastomeric seals, which have been evaluated. The 

applicant also stated that an engineering evaluation was conducted on the minor 

leaching identified in the tendon gallery and the substance was analyzed and found to 

be composed of sodium and potassium carbonate with no calcium or iron. The applicant 

further stated that a visual inspection of the wall did not identify concrete cracking or any 

signs of rust or corrosion. The applicant also stated that the tendon gallery is included in 

the scope of the Structures Monitoring Program and that the program will continue to 

monitor structures within the scope of license renewal for leaching during the period of 

extended operation.

The staff reviewed the applicant’s response and noted that only minor indications of 

leaching have been identified. The staff also noted that the Structures Monitoring 

Program inspects for indications of leaching. The staff finds the applicant’s response 
AGING MANAGEMENT REVIEW RESULTS

3-479

acceptable because it explains that the identified tendon gallery leaching was reviewed, 

evaluated, and found to have no impact on the function of the structure. The response 

further explains that the Structures Monitoring Program, which is the GALL Report 

recommended program, will monitor for this aging effect during the period of extended 

operation. The staff’s concern described in RAI 3.5.2.2.1.9-1 is resolved.

In its review of components associated with item 3.5.1-51, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Structures Monitoring Program is acceptable because this program is 

the GALL Report recommended program, and because the applicant stated that it does 

not have any operating experience with significant leaching that would impact the 

intended function of a structure. The staff finds that an additional plant-specific program 

is unnecessary since an evaluation determined that the observed minor leaching in 

accessible areas has no impact on the intended function of the concrete structure.

Based on its review, the staff concludes that the applicant meets SRP-LR 

Section 3.5.2.2.2.3, item 3 criteria. For those items associated with LRA 

Section 3.5.2.2.2.3.3, the staff determined that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Cracking Due to Stress Corrosion Cracking, and Loss of Material Due to Pitting and Crevice 

Corrosion. LRA Section 3.5.2.2.2.4, associated with LRA Table 3.5-1, item 3.5.1-52, addresses 

cracking due to SCC and loss of material caused by pitting and crevice corrosion for Group 7 

and 8 steel tank liners exposed to standing water. The applicant stated that this item is not 

applicable because the in-scope tank liners were evaluated as tanks with their mechanical 

systems and assigned GALL Report lines from Chapters VII and VIII; therefore, the GALL 

Report lines from Chapter III were not used. In its review, the staff noted that the in-scope tank 

liners were evaluated as tanks with their mechanical systems and assigned GALL Report lines 

from Chapters VII and VIII. The staff finds the applicant’s claim acceptable because the 

applicant evaluated those items and will manage aging for tank liners. 

Cumulative Fatigue Damage Due to Fatigue. LRA Section 3.5.2.2.2.5, associated with LRA 

Table 3.5-1, item 3.5.1-53, addresses cumulative fatigue damage due to cyclic loading in 

component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 

component supports exposed to air-indoor uncontrolled. The applicant stated these fatigue 

analyses are TLAAs identified for Class 1E electrical raceway supports which are described in 

LRA Section 4.3. 

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 fatigue of these structural components is a TLAA as defined in 10 CFR 54.3, 

and that these TLAAs are to be evaluated in accordance with the acceptance criteria in 

10 CFR 54.21(c)(1). The staff reviewed the applicant’s AMR items and determined that the 

AMR results are consistent with the recommendations in the GALL Report and SRP-LR for 

managing cumulative fatigue damage for these structural components.

The applicant also stated that based on its reviews to identify TLAAs in the CLB, there are no 

other fatigue analyses for component support members for Groups B1.1, B1.2, and B1.3. The 

staff reviewed the applicant’s FSAR and confirmed that the applicant’s CLB does not contain 

fatigue analyses for component support members, anchor bolts, and welds for Groups B1.1, 
AGING MANAGEMENT REVIEW RESULTS

3-480

B1.2, and B1.3 that are required to be identified as TLAAs in accordance with 

10 CFR 54.21(c)(1). Therefore, the staff finds the applicant’s claim acceptable.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.5.2.2.2.5 criteria. For those items associated with LRA Section 3.5.2.2.2.5, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these structural components.

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA Program.

3.5.2.2.4 Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of aging management 

programs.

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.5.2-1 through 3.5.2-12, 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 3.5.2-12, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an 

AMR item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR item component, material, and environment combination is not 

evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the AMR item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the AMR 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 during the period of extended operation. 

The staff’s evaluation is discussed in the following sections.

3.5.2.3.1 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Reactor Building—LRA Table 3.5.2-1

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the 

reactor building component groups.
AGING MANAGEMENT REVIEW RESULTS

3-481

Cementitious and Ceramic Fiber Fire Barrier Coatings and Wraps Exposed to Plant Indoor Air. 

In LRA Tables 3.5.2-1, 3.5.2-2, 3.5.2-3, 3.5.2-5, and 3.5.2-10, the applicant stated that 

cementitious and ceramic fiber fire barrier coatings and wraps exposed to plant indoor air will be 

managed for cracking and loss of material by the Fire Protection Program. The AMR items cite 

generic note J.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Although the GALL Report does not have any AMR 

items for non-metallic fire barriers, the staff noted that GALL Report AMP XI.M26, “Fire 

Protection,” does include aging management of fire resistant materials, including fire wrapping 

and spray-on fireproofing, within the scope of the AMP. GALL Report AMP XI.M26 

recommends that these materials be managed for cracking and loss of material. Based on its 

review of the GALL Report, the staff finds that the applicant has identified all credible aging 

effects for this component, material, and environment combination.

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.6. The staff finds the applicant’s proposal to manage aging using the Fire 

Protection Program acceptable because the program includes visual inspections of fire barriers 

of various material types which are capable of detecting degradation of the fire barrier 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 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 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Control Building—LRA Table 3.5.2-2

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the 

control building component groups.

Cementitious and Ceramic Fiber Fire Barrier Coatings and Wraps Exposed to Plant Indoor Air. 

The staff’s evaluation for cementitious and ceramic fiber fire barrier coatings and wraps exposed 

to plant indoor air which will be managed for cracking and loss of material by the Fire Protection 

Program and cite generic note J, 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).

3.5.2.3.3 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Auxiliary Building—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 component groups.
AGING MANAGEMENT REVIEW RESULTS

3-482

Cementitious and Ceramic Fiber Fire Barrier Coatings and Wraps Exposed to Plant Indoor Air. 

The staff’s evaluation for cementitious and ceramic fiber fire barrier coatings and wraps exposed 

to plant indoor air which will be managed for cracking and loss of material by the Fire Protection 

Program and cite generic note J, 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).

3.5.2.3.4 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Turbine Building—LRA Table 3.5.2-4

The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the 

turbine building component groups.

Cementitious Fire Barrier Coatings and Wraps Exposed to Plant Indoor Air. In LRA 

Table 3.5.2-4, the applicant stated that, for cementitious fire barrier coatings exposed to plant 

indoor air, there is no aging effect and no AMP is proposed. However, in a letter dated 

February 14, 2014, the applicant removed this AMR item from the LRA because it no longer has 

a fire barrier intended function, per the applicant’s transition to a risk-informed, 

performance-based fire protection plan that incorporates NFPA-805. As a result, the staff’s 

review did not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the turbine building component groups 

are consistent with the GALL Report.

3.5.2.3.5 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Diesel Generator Building—LRA Table 3.5.2-5

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the 

diesel generator building component groups.

Cementitious and Ceramic Fiber Fire Barrier Coatings and Wraps Exposed to Plant Indoor Air. 

The staff’s evaluation for cementitious and ceramic fiber fire barrier coatings and wraps exposed 

to plant indoor air which will be managed for cracking and loss of material by the Fire Protection 

Program and cite generic note J, 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 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Miscellaneous In-Scope Structures—LRA Table 3.5.2-6

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the 

miscellaneous in-scope structures component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the miscellaneous in-scope structures component groups are 

consistent with the GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-483

3.5.2.3.7 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—In-Scope Tank Foundations and Structures—LRA 

Table 3.5.2-7

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the 

in-scope tank foundations and structures component groups. The staff’s review did not identify 

any AMR items with notes F through J, indicating that the combinations of component type, 

material, environment, and AERM for the in-scope tank foundations and structures component 

groups are consistent with the GALL Report.

3.5.2.3.8 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Electrical Foundations and Structures—LRA Table 3.5.2-8

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the 

electrical foundations and structures component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the electrical foundations and structures component groups are 

consistent with the GALL Report.

3.5.2.3.9 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Radwaste Building—LRA Table 3.5.2-9

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the 

radwaste building component groups.

Cementitious Fire Barrier Coatings and Wraps Exposed to Plant Indoor Air. In LRA 

Table 3.5.2-9, the applicant stated that, for cementitious fire barrier coatings exposed to plant 

indoor air, there is no aging effect and no AMP is proposed. However, in a letter dated 

February 14, 2014, the applicant removed this AMR item from the LRA because it no longer has 

a fire barrier intended function, per the applicant’s transition to a risk-informed, 

performance-based fire protection plan that incorporates NFPA-805. As a result, the staff’s 

review did not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the radwaste building component groups 

are consistent with the GALL Report.

3.5.2.3.10 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Fuel Building—LRA Table 3.5.2-10

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for 

the fuel building component groups.

Cementitious and Ceramic Fiber Fire Barrier Coatings and Wraps Exposed to Plant Indoor Air. 

The staff’s evaluation for cementitious and ceramic fiber fire barrier coatings and wraps exposed 

to plant indoor air which will be managed for cracking and loss of material by the Fire Protection 

Program and cite generic note J, 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).
AGING MANAGEMENT REVIEW RESULTS

3-484

3.5.2.3.11 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Essential Service Water Structures—LRA Table 3.5.2-11

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the ESW structures component groups.

Fiber Glass Reinforced Plastic Fan Stack Exposed to Atmosphere or Weather. In LRA 

Table 3.5.2-11, the applicant stated that fiberglass reinforced plastic fan stack exposed to 

atmosphere/weather will be managed for cracking, blistering, and change in color by the 

Structures Monitoring Program. The AMR item cites generic note F.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff notes that the GALL Report does not identify 

any applicable aging effects for glass; however, the polymers that are used to bind the glass 

material into the fiberglass matrix may be susceptible to aging. Based on its review of the 

Polymer Blends Handbook, Section 14.5, “Weathering of Polymer Blends,” which states that the 

standard methods of assessing the performance of polymers exposed to UV radiation are gloss 

loss, chalking, color retention, cracking and crazing, and dirt retention, the staff finds that the 

applicant has identified all credible aging effects for this component, material, and environment 

combination. However, the applicant’s Structures Monitoring Program does not include specific 

guidance for monitoring or acceptance criteria of fiberglass reinforced plastic material. 

Therefore, by letter dated July 9, 2012, the staff issued RAI 3.5.2.11-2 requesting that the

applicant explain what parameters will be monitored, and acceptance criteria will be used, for 

the aging management of fiberglass reinforced plastic components exposed to 

atmosphere/weather.

In its response dated August 9, 2012, the applicant stated that LRA Appendices A1.31 and 

B2.1.31 list cracking, blistering, and change in color as aging effects that are managed by the 

Structures Monitoring Program. The applicant further stated that plant procedures have been 

revised to specify that fiberglass reinforced plastic will be inspected, and any indication of 

cracking, blistering, or change in color will be evaluated for inclusion into Callaway’s CAP.

Based on its review, the staff finds the applicant’s response acceptable because the applicant 

has identified all applicable aging effects for the component, material, and environment 

combination, and has revised plant procedures to specify that any indication of cracking, 

blistering, or change in color be evaluated for inclusion into Callaway’s CAP. The staff’s

concern described in RAI 3.5.2.11-2 is resolved.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.17. The staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because: (a) the program description lists cracking, 

blistering, and change in color as aging effects that will be managed; (b) visual inspections will 

be completed at a period not to exceed 5 years; and (c) any indication of these listed aging 

effects will be evaluated for inclusion into Callaway’s CAP.

Stainless Steel Structural Steel Exposed to a Submerged Environment. In LRA Table 3.5.2-11, 

the applicant stated that stainless steel structural steel exposed to a submerged environment 

will be managed for loss of material by the Structures Monitoring Program. The AMR item cites 

generic note G.
AGING MANAGEMENT REVIEW RESULTS

3-485

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Based on its review of the definition in GALL Report 

Chapter IX, which states that stainless steel is susceptible to loss of material and cracking, the 

staff determined the need for additional information. Therefore, by letter dated July 9, 2012, the 

staff issued RAI 3.5.2.11-1 requesting that the applicant describe the type, condition, and 

temperature of the water in which the stainless steel supports are submerged, explain why 

cracking is not an applicable aging effect, and explain how the Structures Monitoring Program 

will manage aging effects caused by loss of material. If it is determined that cracking needs to 

be managed, the staff also requested that the applicant identify an AMP and provide the 

technical justification for that AMP (i.e., inspection method, frequency, and acceptance criteria).

In its response dated August 9, 2012, the applicant stated that the submerged stainless steel 

components are embedded in the surface of the concrete in the ESW structures, and are 

exposed to raw water that passes through the pumphouse from the retention pond at ambient 

temperatures. The applicant also stated that the water in which these components are 

submerged is not heated above atmospheric temperatures, and it is refreshed on a regular 

basis; therefore, cracking is not an aging effect requiring management for these components. 

The applicant further stated that these components are monitored by the Structures Monitoring 

Program. In addition, the applicant stated that the pumphouse bays are dewatered on a 

frequency of approximately every 5 years, timed to coincide with plant outages, at which time a 

visual examination of the structural components is performed.

Based on its review, the staff finds the applicant’s response acceptable because the submerged 

environment, for which these stainless steel structural steel components are exposed, would not 

be conducive to cracking of stainless steel components, and the applicant has identified all 

credible aging effects for this component, material, and environment combination. The staff 

also finds the applicants response acceptable because visual examination of the structural 

components is performed in a dewatered state, at a frequency consistent with the 

recommendations in GALL Report AMP XI.S6. The staff’s concern described in RAI 3.5.2.11-1 

is resolved.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.17. The staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because the pumphouse bays are dewatered every 

5 years and visually examined at a frequency consistent with recommendations in the GALL 

Report.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.12 Containments, Structures, and Component Supports—Summary of Aging 

Management Evaluation—Supports—LRA Table 3.5.2-12

The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for 

the supports component groups. The staff’s review did not identify any AMR items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for the supports component groups are consistent with the GALL Report.
AGING MANAGEMENT REVIEW RESULTS

3-486

3.5.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the structures and component supports within the scope of license 

renewal and subject to an AMR will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.6 Aging Management of Electrical and Instrumentation and Controls

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

electrical and instrumentation and control (I&C) components of:

• cable connections (metallic parts)

• connectors

• high voltage insulators

• insulated cable and connections

• switchyard bus and connections

• terminal blocks

• transmission conductors

• transmission connections

• electrical equipment subject to 10 CFR 50.49 EQ requirements

• metal enclosed bus

3.6.1 Summary of Technical Information in the Application

LRA Section 3.6 provides AMR results for the electrical and I&C components. LRA Table 3.6-1, 

“Summary of Aging Management Programs in Chapter VI of NUREG-1801 for Electrical 

Components,” is a summary comparison of the applicant’s AMRs with those evaluated in the 

GALL Report for the electrical and I&C components.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine if the applicant provided sufficient information 

to demonstrate that the effects of aging for the electrical and I&C components within the scope 

of license renewal and subject to an AMR will be adequately managed so that the intended 

function(s) will remain consistent with the CLB for the period of extended operation, as required 

by 10 CFR 54.21(a)(3).

The staff 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 confirm 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.
AGING MANAGEMENT REVIEW RESULTS

3-487

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 confirm that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. Details of the 

staff’s evaluation are discussed in SER Section 3.6.2.1.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff’s evaluations 

are documented in SER Section 3.6.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.6.2.3.

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to confirm the applicant’s 

claims.

Table 3.6-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.6 and addressed in the GALL Report.

The staff’s review of the electrical and I&C component groups followed any one of several 

approaches. One approach, documented in SER Section 3.6.2.1, reviewed AMR results for 

components that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.6.2.2, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER 

Section 3.6.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with or not addressed in the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the electrical and I&C components is documented in SER 

Section 3.0.3.
AGING MANAGEMENT REVIEW RESULTS

3-488

Table 3.6-1 Staff Evaluation for Electrical and I&C in the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Electrical equipment 

subject to 

10 CFR 50.49 EQ 

requirements 

composed of 

Various polymeric 

and metallic 

materials exposed to 

Adverse localized 

environment caused 

by heat, radiation, 

oxygen, moisture, or 

voltage (3.6.1-1)

Various aging 

effects caused 

by various 

mechanisms in 

accordance with 

10 CFR 50.49

EQ is a time-limited 

aging analysis (TLAA) 

to be evaluated for the 

period of extended 

operation. See the 

Standard Review Plan, 

Section 4.4, 

“Environmental 

Qualification (EQ) of 

Electrical Equipment,” 

for acceptable 

methods for meeting 

the requirements of 

10 CFR 54.21(c)(1)(i) 

and (ii). See Chapter 

X.E1, “Environmental 

Qualification (EQ) of 

Electric Components,” 

of this report for 

meeting the 

requirements of 

10 CFR 54.21(c)(1)(iii).

Yes TLAA Consistent with 

the GALL Report 

(see SER 

Section 3.6.2.2.1)

High-voltage 

insulators composed 

of Porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

Air – outdoor 

(3.6.1-2)

Loss of material 

caused by 

mechanical 

wear caused by 

wind blowing on 

transmission 

conductors

A plant-specific aging 

management program 

is to be evaluated

Yes Not applicable Not applicable to 

Callaway 

(see SER 

Section 3.6.2.2.2)

High-voltage 

insulators composed 

of Porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

Air – outdoor 

(3.6.1-3)

Reduced 

insulation 

resistance 

caused by 

presence of salt 

deposits or 

surface 

contamination

A plant-specific aging 

management program 

is to be evaluated for 

plants located such 

that the potential exists 

for salt deposits or 

surface contamination 

(e.g., in the vicinity of 

salt water bodies or 

industrial pollution)

Yes Not applicable Not applicable to 

Callaway 

(see SER 

Section 3.6.2.2.2)

Transmission 

conductors 

composed of 

Aluminum; steel 

exposed to Air –

outdoor (3.6.1-4)

Loss of 

conductor 

strength caused 

by corrosion

A plant-specific aging 

management program 

is to be evaluated for 

ACSR

Yes Not applicable Not applicable to 

Callaway

(see SER 

Section 3.6.2.2.3)

Transmission 

connectors 

composed of 

Aluminum; steel 

exposed to Air –

outdoor (3.6.1-5)

Increased 

resistance of 

connection 

caused by 

oxidation or loss 

of pre-load

A plant-specific aging 

management program 

is to be evaluated

Yes Not applicable Not applicable to 

Callaway

(see SER 

Section 3.6.2.2.3)
AGING MANAGEMENT REVIEW RESULTS

3-489

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Switchyard bus and 

connections 

composed of 

Aluminum; copper; 

bronze; stainless 

steel; galvanized 

steel exposed to 

Air – outdoor 

(3.6.1-6)

Loss of material 

caused by 

wind-induced 

abrasion; 

Increased 

resistance of 

connection 

caused by 

oxidation or loss 

of pre-load

A plant-specific aging 

management program 

is to be evaluated

Yes Not applicable Not applicable to 

Callaway

(see SER 

Section 3.6.2.2.3)

Transmission 

conductors 

composed of 

Aluminum; Steel 

exposed to Air –

outdoor (3.6.1-7)

Loss of material 

caused by 

wind-induced 

abrasion

A plant-specific aging 

management program 

is to be evaluated for 

ACAR and ACSR

Yes Not applicable Not applicable to 

Callaway

(see SER 

Section 3.6.2.2.3)

Insulation material 

for electrical cables 

and connections 

(including terminal 

blocks, fuse holders, 

etc.) composed of 

Various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to Adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-8)

Reduced 

insulation 

resistance 

caused by 

thermal/ 

thermoxidative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiation-induce

d oxidation; 

moisture 

intrusion

Chapter XI.E1, 

“Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Insulation 

Material for 

Electrical 

Cables and 

Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Consistent with 

the GALL Report

Insulation material 

for electrical cables 

and connections 

used in 

instrumentation 

circuits that are 

sensitive to 

reduction in 

conductor insulation 

resistance (IR) 

composed of 

Various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to Adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-9)

Reduced 

insulation 

resistance 

caused by 

thermal/thermox

idative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiation-induce

d oxidation; 

moisture 

intrusion

Chapter XI.E2, 

“Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation 

Circuits”

No Insulation 

Material for 

Electrical 

Cables and 

Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Used in 

Instrumentatio

n Circuits

Consistent with 

the GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-490

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Conductor insulation 

for inaccessible 

power cables greater 

than or equal to 400 

volts (e.g., installed 

in conduit or direct 

buried) composed of 

Various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to Adverse 

localized 

environment caused 

by significant 

moisture (3.6.1-10)

Reduced 

insulation 

resistance 

caused by 

moisture

Chapter XI.E3, 

“Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Inaccessible 

Power Cables 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Consistent with 

the GALL Report

Metal enclosed bus: 

enclosure 

assemblies 

composed of 

Elastomers exposed 

to Air – indoor, 

controlled or 

uncontrolled or Air –

outdoor (3.6.1-11)

Surface 

cracking, 

crazing, 

scuffing, 

dimensional 

change 

(e.g., “balloonin

g” and 

“necking”), 

shrinkage, 

discoloration, 

hardening and 

loss of strength 

caused by 

elastomer 

degradation

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Metal Enclosed 

Bus

Consistent with 

the GALL Report

Metal enclosed bus: 

bus/connections 

composed of 

Various metals used 

for electrical bus and 

connections 

exposed to Air –

indoor, controlled or 

uncontrolled or Air –

outdoor (3.6.1-12)

Increased 

resistance of 

connection 

caused by the 

loosening of 

bolts caused by 

thermal cycling 

and ohmic 

heating

Chapter XI.E4, “Metal 

Enclosed Bus”

No Metal Enclosed 

Bus

Consistent with 

the GALL Report

Metal enclosed bus: 

insulation; insulators 

composed of 

Porcelain; xenoy; 

thermo-plastic 

organic polymers 

exposed to Air –

indoor, controlled or 

uncontrolled or Air –

outdoor (3.6.1-13)

Reduced 

insulation 

resistance 

caused by 

thermal/thermox

idative 

degradation of 

organics/thermo

plastics, 

radiation-induce

d oxidation, 

moisture/debris 

intrusion, and 

ohmic heating

Chapter XI.E4, “Metal 

Enclosed Bus”

No Metal Enclosed 

Bus

Consistent with 

the GALL Report
AGING MANAGEMENT REVIEW RESULTS

3-491

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of Steel 

exposed to Air –

indoor, uncontrolled 

or Air – outdoor 

(3.6.1-14)

Loss of material 

caused by 

general, pitting, 

and crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No Metal Enclosed 

Bus

Consistent with 

the GALL Report

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

Galvanized steel; 

aluminum exposed 

to Air – outdoor 

(3.6.1-15)

Loss of material 

caused by 

pitting and 

crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No Metal Enclosed 

Bus

Consistent with 

the GALL Report

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

Various metals used 

for electrical 

connections 

exposed to Air –

indoor, uncontrolled 

(3.6.1-16)

Increased 

resistance of 

connection 

caused by 

chemical 

contamination, 

corrosion, and 

oxidation (in an 

air, indoor 

controlled 

environment, 

increased 

resistance of 

connection 

caused by 

chemical 

contamination, 

corrosion and 

oxidation do not 

apply); fatigue 

caused by 

ohmic heating, 

thermal cycling, 

electrical 

transients

Chapter XI.E5, “Fuse 

Holders”

No Not applicable Not applicable to 

Callaway 

(see SER 

Section 3.6.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-492

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

Various metals used 

for electrical 

connections 

exposed to Air –

indoor, controlled or 

uncontrolled 

(3.6.1-17)

Increased 

resistance of 

connection 

caused by 

fatigue caused 

by frequent 

manipulation or 

vibration

Chapter XI.E5, “Fuse 

Holders” No aging 

management program 

is required for those 

applicants who can 

demonstrate these 

fuse holders are 

located in an 

environment that does 

not subject them to 

environmental aging 

mechanisms or fatigue 

caused by frequent 

manipulation or 

vibration

No Not applicable Not applicable tp 

Callaway 

(see SER 

Section 3.6.2.1.1)

Cable connections 

(metallic parts) 

composed of 

Various metals used 

for electrical 

contacts exposed to 

Air – indoor, 

controlled or 

uncontrolled or Air –

outdoor (3.6.1-18)

Increased 

resistance of 

connection 

caused by 

thermal cycling, 

ohmic heating, 

electrical 

transients, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation

Chapter XI.E6, 

“Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Electrical 

Cable 

Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

Consistent with 

the GALL Report

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage composed 

of Various metals 

used for electrical 

contacts exposed to 

Air with borated 

water leakage 

(3.6.1-19)

Increased 

resistance of 

connection 

caused by 

corrosion of 

connector 

contact surfaces 

caused by 

intrusion of 

borated water

Chapter XI.M10, “Boric 

Acid Corrosion”

No Boric Acid 

Corrosion

Consistent with 

the GALL Report

Transmission 

conductors 

composed of 

Aluminum exposed 

to Air – outdoor 

(3.6.1-20)

Loss of 

conductor 

strength caused 

by corrosion

None - for Aluminum 

Conductor Aluminum 

Alloy Reinforced 

(ACAR)

None Not applicable Not applicable to 

Callaway 

(see SER 

Section 3.6.2.1.1)
AGING MANAGEMENT REVIEW RESULTS

3-493

Component Group

(SRP-LR Item No.)

Aging Effect or

Mechanism

AMP in SRP-LR Further 

Evaluation 

in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Fuse holders (not 

part of active 

equipment): 

insulation material, 

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

Insulation material: 

bakelite; phenolic 

melamine or 

ceramic; molded 

polycarbonate; 

other, Galvanized 

steel; aluminum, 

Steel exposed to Air 

– indoor, controlled 

or uncontrolled 

(3.6.1-21)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

Callaway (see 

SER 

Section 3.6.2.1.1)

3.6.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.6.2.1 identifies the materials, environments, and AERMs, 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 Environmental Qualification 

Requirements

• Boric Acid Corrosion

• Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements

• Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

• Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements

• Metal Enclosed Bus

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements Used 

in Instrumentation Circuits That Are Sensitive to Reduction in Conductor Insulation 

Resistance

LRA Table 3.6.2-1 summarizes AMRs for the electrical and I&C components and indicates 

AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which it does not recommend further evaluation, the 
AGING MANAGEMENT REVIEW RESULTS

3-494

staff’s audit and review determined whether the plant-specific components of these GALL 

Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with notes A–E, indicating how 

the AMR is consistent with the GALL Report.

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff reviewed these items to confirm consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff reviewed these items to confirm consistency with the GALL Report and 

confirmed that the identified exceptions to the GALL Report AMPs have been reviewed and 

accepted. The staff also determined whether the applicant’s AMP was consistent with the GALL 

Report AMP and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL Report AMP. This note indicates that the applicant was unable to find 

a listing of some system components in the GALL Report; however, the applicant identified in 

the GALL Report a different component with the same material, environment, aging effect, and 

AMP as the component under review. The staff reviewed these items to confirm consistency 

with the GALL Report. The staff also determined whether the AMR item of the different 

component was applicable to the component under review and whether the AMR was valid for 

the site-specific conditions.

Note D indicates that the component for the AMR item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL Report AMP. The staff reviewed these items to confirm 

consistency with the GALL Report. The staff confirmed whether the AMR item of the different 

component was applicable to the component under review and whether the identified 

exceptions to the GALL Report AMPs have been reviewed and accepted. The staff also 

determined whether the applicant’s AMP was consistent with the GALL Report AMP and 

whether the AMR was valid for the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect but credits a different AMP. The staff reviewed these items to 

confirm 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 confirm that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows.

In LRA Table 3.6-1, the applicant summarizes AMRs for the electrical and instrumentation and 

controls components and claimed that these AMRs are consistent with the GALL Report. The 
AGING MANAGEMENT REVIEW RESULTS

3-495

staff noted that LRA Section 3.6.1 lists the following electrical component types subject to an 

AMR under “insulated cable and connections.”

• 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 that are sensitive to reduction in conductor insulation resistance

• inaccessible power cables not subject to 10 CFR 50.49 EQ requirements

However, LRA Section 3.6.2.1.4, “Insulated Cable and Connections,” only lists the following 

AMPs:

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

• Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

By letter dated August 23, 2012, the staff issued RAI 3.6.2.1.4-1 to ask the applicant to explain 

why the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ Requirements 

Used in Instrumentation Circuits that are Sensitive to Reduction in Conductor Insulation 

Resistance AMP is not listed in LRA Section 3.6.2.1.4. 

In its response dated September 20, 2012, the applicant stated that LRA Section 3.6.2.1.4 

inadvertently omitted the Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits That Are Sensitive to Reduction in Conductor 

Insulation Resistance AMP. The applicant also amended the LRA to add LRA 

Section 3.6.2.1.4.3, “Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits That Are Sensitive to Reduction in Conductor 

Insulation Resistance” and credit the AMP.

The staff finds the applicant response acceptable because the applicant clarified that the 

omission of the AMP in LRA Section 3.6.2.1.4 was an error and the applicant also amended the 

LRA to credit the AMP under LRA Section 3.6.2.1.4. The staff finds the addition of LRA 

Section 3.6.2.1.4.3, “Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ 

Requirements Used in Instrumentation Circuits That Are Sensitive To Reduction In Conductor 

Insulation Resistance” is consistent with LRA Table 3.6-1, the GALL Report, and SRP-LR 

Table 3.6-1. The staff’s concern related to RAI 3.6.2.1.4-1 is resolved. 

3.6.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.6-1, items 3.6.1-20 and 3.6.1-21, the applicant claimed that the corresponding 

items in the GALL Report are not applicable because the component, material, and environment 

combination described in the SRP-LR does not exist for in-scope SCs at Callaway. The staff 

reviewed the LRA and FSAR and confirmed that the applicant’s LRA does not have any AMR 

results applicable for these items.

For LRA Table 3.6-1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable; however, the staff non-applicability verification of 

these items required the review of sources beyond the LRA and FSAR, and/or the issuance of 

RAIs.
AGING MANAGEMENT REVIEW RESULTS

3-496

In LRA Table 3.6-1, items 3.6.1-16 and 3.6.1-17, the applicant stated that for fuse holders (not 

part of a larger assembly): metallic clamps exposed to air – indoor controlled and uncontrolled, 

increased resistance of connection because of chemical contamination, corrosion, and 

oxidation; fatigue caused by ohmic heating, thermal cycling, electrical transients and frequent 

manipulation or vibration are not applicable to Callaway and no AMP is proposed. LRA 

Table 3.6.2-1 does not include fuse holder metallic clamps as a component type or identified 

fuse holder metallic clamps as generic note I (i.e., aging effect in the GALL Report for this 

component, material and environment combination is not applicable). The applicant stated, in 

Table 3.6-1, that no AMP is required because “[a]ll fuse holders including the fuses installed for 

electrical penetration protection are part of larger assemblies. GALL Report, item VI.A.LP-23 

and VI.A.LP-31, “Fuse holders (not part of active equipment): metallic clamp,” identifies the 

aging/effect mechanism as increased resistance of connection due to chemical contamination, 

corrosion, oxidation; fatigue due to ohmic heating, thermal cycling, electrical transients; and 

increased resistance of connection due to fatigue caused by frequent manipulation or vibration. 

The associated GALL Report AMP XI.E5, “Fuse Holders,” states that fuse holders within the 

scope of license renewal should be tested to provide an indication of the condition of the fuse 

holder metallic clamps. The GALL Report states that GALL Report AMP XI.E5 manages fuse 

holders (metallic clamps) located outside of active devices; however, fuse holders inside active 

devices are not within the scope of GALL Report AMP XI.E5. The applicant stated that GALL 

Report AMP XI.E5 is not applicable based on fuse holders (metallic clamps) being located in 

larger assemblies, which is inconsistent with GALL Report AMP XI.E5, “scope of program” 

program element. However, the staff noted that the applicant did not provide technical 

justifications as to why these in-scope fuse holders do not require aging management. By letter 

dated August 23, 2012, the staff issued RAI 3.6.2.1-1 requesting the applicant to provide an 

evaluation that addresses each aging effect or mechanism identified in GALL Report, items 

VI.A.LP-23 and VI.A.LP-31. 

In its response dated September 20, 2012, and as supplemented by letter dated 

November 20, 2012, the applicant stated that GALL Report items VI.A.LP-23 and VI.A.LP-31, 

apply only to fuse holders and metallic clamps which are not part of active equipment. The 

applicant also stated that the GALL Report AMP XI.E5, “scope of program” program element, 

states that fuse holders inside an active device are not within the scope of GALL Report 

AMP XI.E5. The applicant further stated that LRA Table 3.6-1, items 3.6.1-16 and 3.6.1-17 

have been revised to state that all fuse holders including fuse holders for electrical penetrations 

that use metallic clamps are within the scope of license renewal as part of an active device and 

do not require aging management. 

The staff finds the applicant response acceptable because the applicant clarified that all 

in-scope fuse holders using metallic clamps do not require aging management because they are 

located in active equipment. Therefore, the staff finds the applicants claim that the 

corresponding GALL AMR items are not applicable acceptable. The staff’s concern described 

in RAI 3.6.2.1-1 is resolved. 
AGING MANAGEMENT REVIEW RESULTS

3-497

3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.6.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the electrical and I&C components and provides information concerning 

how it will manage the following aging effects:

• electrical equipment subject to EQ

• reduced insulation resistance due to presence of any salt deposits and surface 

contamination, and loss of material due to mechanical wear caused by wind blowing on 

transmission conductors

• loss of material due to wind-induced abrasion, loss of conductor strength due to 

corrosion, and increased resistance of connection due to oxidation or loss of pre-load

• QA for aging management of nonsafety-related components

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 it 

adequately addressed the issues further evaluated. In addition, the staff reviewed the 

applicant’s further evaluations against the criteria contained in SRP-LR Section 3.2.2.2. The 

staff’s review of the applicant’s further evaluation follows.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

LRA Section 3.6.2.2.1 is associated with LRA Table 3.6-1, item 3.6.1-1. The applicant stated 

that environmental qualification is a TLAA. Applicants must evaluate TLAAs in accordance with 

10 CFR 54.21(c)(1). The applicant also stated that the EQ of Electric Components Program 

meets the requirements of 10 CFR 50.49. The applicant further stated that evaluation of this 

TLAA is addressed separately in LRA Section 4.4. The staff’s review of the applicant’s 

evaluation of this TLAA and the EQ of Electrical Components Program is documented in SER 

Sections 4.4 and 3.0.3.1.19, respectively. The applicant’s program also includes environmental 

qualification of mechanical components qualified in accordance with Criterion 4, “Environmental 

and Dynamic Effects Design Basis” of Appendix A to 10 CFR Part 50. LRA Section 4.7.10 

addresses the TLAA for mechanical EQ equipment. The staff’s evaluation of the TLAA for 

mechanical EQ equipment is documented in SER Section 4.7.10.

3.6.2.2.2 Reduced Insulation Resistance Due to Presence of Any Salt Deposits and Surface 

Contamination, and Loss of Material Due to Mechanical Wear Caused by Wind 

Blowing on Transmission Conductors

LRA Section 3.6.2.2.2, associated with LRA Table 3.6-1, items 3.6.1-2 and 3.6.1-3, addresses 

reduced insulation resistance due to presence of salt deposits and surface contamination, and 

loss of material caused by mechanical wear. The applicant stated that Callaway is located in an 

area with moderate rain fall and is not subject to air pollution or salt spray. The applicant also 

stated that contamination of high-voltage insulators is not a problem because of sufficient 

rainfall periodically washing the high-voltage insulators. The applicant noted that Callaway has 

no operating experience indicating instances of flashover because of pollution or salt deposits. 

The applicant therefore concluded that degradation of insulator quality in the absence of salt 

deposits and surface contamination is not an aging effect requiring aging management. 
AGING MANAGEMENT REVIEW RESULTS

3-498

The applicant stated that industry experience has shown that transmission conductors are 

designed and installed not to swing significantly and cause wear because of wind-induced 

abrasion and fatigue. The applicant also stated that Callaway transmission conductors are 

designed and installed not to swing significantly. The applicant noted that Callaway has no 

operating experience indicating loss of material on high-voltage connectors because of 

mechanical wear from wind-induced abrasion or fatigue. The applicant further stated that 

therefore, loss of material caused by wind-induced abrasion and fatigue is not an applicable 

aging effect requiring management.

The staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2, which 

states that reduced insulation resistance caused by salt deposits and surface contamination 

may occur in high-voltage insulators. The 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 caused by 

mechanical wear caused by wind on transmission conductors may occur in high-voltage 

insulators. The GALL Report recommends further evaluation of a plant-specific AMP to ensure 

that these aging effects are adequately managed.

The staff noted that SRP-LR Section 3.6.2.2.2 states that further evaluation of a plant specific 

AMP is recommended for management of reduced insulation resistance caused by presence of 

salt deposits and surface contamination for plants located such that potential exists for salt 

deposits or surface contamination (e.g., in the vicinity of salt water bodies or industrial pollution). 

The staff finds that Callaway is not located in vicinity of either salt water bodies or industrial 

pollution; therefore, surface contamination of high-voltage insulator is not a concern. In 

addition, rainfall and snow periodically wash away contamination and the glazed insulator 

surface also aids with this contamination removal. The staff also finds that the plant-specific 

operating experience at Callaway supports the applicant’s conclusion that contamination is not 

significant because there has been no occurrence of insulator flashover caused by salt or 

pollution surface contamination or experience with loss of material because of mechanical wear 

from wind-induced movement of transmission conductors. 

The staff also notes that EPRI 1003057 (License Renewal Handbook) states that mechanical 

wear in insulators is an aging effect for strain and suspension insulators in that they are subject 

to movement. Movement of insulators can be caused by wind blowing the supported 

transmission conductor, causing it to swing. If this swing is frequent enough, it could cause 

wear in the metal contact point of the insulator string and between an insulator and supporting 

hardware. Although this mechanism is possible, industry operating experience has shown that 

the transmission conductors are designed not to normally swing but when they do, (e.g., 

because of a substantial wind), transmission conductors do not continue to swing for a long 

period of time once the wind has subsided. The applicant has not identified loss of material on 

high-voltage insulators caused by mechanical wear based on plant specific operating 

experience. Based on its review, the staff finds the mechanical wear aging effect of 

high-voltage insulators is not an aging effect requiring management at Callaway.

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 items associated with LRA Section 3.6.2.2.2, the 

staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).
AGING MANAGEMENT REVIEW RESULTS

3-499

3.6.2.2.3 Loss of Material Due to Wind-Induced Abrasion, Loss of Conductor Strength Due to 

Corrosion, and Increased Resistance of Connection due to Oxidation or Loss of 

Pre-Load

LRA Section 3.6.2.2.3, associated with LRA Table 3.6-1, items 3.6.1-4, 5, 6, and 7 address loss 

of material due to wind-induced abrasion and fatigue, loss of conductor strength because of 

corrosion, and increased resistance of connections caused by oxidation or loss of pre-load of 

transmission conductors and connections, and switchyard bus and connections. 

The applicant stated that industry experience has shown that transmission conductors are 

designed and installed not to sway significantly and cause wear due to wind-induced abrasion 

and fatigue. The applicant stated that loss of material due to wind-induced abrasion is not an 

applicable aging effect requiring management for the period of extended operation. The 

applicant did not include plant specific operating experience for Callaway to support the 

applicant’s claim that wind-induced abrasion and fatigue is not a significant aging effect for 

transmission conductors. The applicant did not address whether a review of plant specific 

operating experience indicated additional aging effects exist beyond those addressed in the 

GALL Report. By letter dated August 23, 2012, the staff issued RAI 3.6.2.2.3-1 requesting the 

applicant confirm that there has been no plant-specific occurrence of transmission conductor 

wind-induced abrasion and fatigue, and if they have occurred, the staff requested the applicant 

to describe the corrective actions performed to prevent reoccurrence.

In its response dated September 20, 2012, the applicant stated that based on a review of 

Callaway corrective action documents there has been no plant-specific operating experience of 

loss of material due to wind-induced abrasion or fatigue, loss of conductor strength due to 

corrosion, or increased resistance of connection due to oxidation or loss of preload in 

transmission conductors and connections, or in switchyard bus and connections. The applicant 

also stated that there are no additional aging effects beyond those identified by the GALL 

Report and SRP-LR Section 3.6.2.2.3.

The staff finds the applicant response acceptable because the applicant has provided 

plant-specific operating experience to further justify its claim that 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 are not significant aging effects for 

transmission conductors and connections consistent with SRP-LR Section 3.6.2.2.3 and 

Appendix A.1, including plant-specific operating experience. The staff’s concern described in 

RAI 3.6.2.2.3-1 is resolved.

The applicant stated that the most prevalent aging mechanism contributing to the loss of 

transmission conductor strength is corrosion. The applicant also stated that corrosion rates 

depend largely on air quality (e.g., air particulates), SO2 concentration, rain, fog chemistry, and 

other weather conditions. The applicant further stated that Callaway is not subject to industrial 

or salt pollution. The applicant noted that Callaway FSAR Section 2.3.1.2.10-SA shows that 

there is a low frequency and duration (22 days in 5 years) of high air pollution potential caused 

by low mixing depth and low wind speed at Callaway. 

The applicant stated that transmission conductors within the switchyard are 91 strand 

2,500-kilo-circular-mils (kcmil) stranded aluminum conductors (SAC) to the first tower leaving 

the switchyard. The applicant also stated that SAC corrosion is not a credible aging effect that 

requires management for the period of extended operation. Transmission conductors from the 

switchyard tower to startup transformer XMRO1 are 795 kcmil aluminum conductors, steel 

reinforced (ACSR). The applicant also stated that Callaway ACSR conductors have adequate 
AGING MANAGEMENT REVIEW RESULTS

3-500

design margin to offset the loss of strength because of corrosion and will continue to meet 

National Electrical Safety Code (NESC) requirements of not exceeding 60 percent of the rated 

breaking strength for the period of extended operation.

The applicant referenced a study performed by Ontario Hydroelectric. The report was issued in 

two parts; part one of the report described field and laboratory tests to determine the condition 

of ACSR conductors while part 2 of the report analyzed the test results to determine the useful 

life of ACSR conductors. Ontario Hydroelectric undertook the study based on realization that 

one-third of Ontario Hydroelectric’s transmission lines would soon exceed their stated design 

life. The report indicated that the consequences of transmission lines exceeding their design life 

are decreased reliability seen as a reduction in system operability and maintainability, supply 

reliability, and public safety. 

The Ontario Hydroelectric study presented three life estimation techniques; the first was based 

on zinc losses using a corrosion detector developed for the study and assumed a constant 

degradation rate. The report considered this test qualitative based on variations in zinc 

thickness and uncertainty as to the thickness of the original zinc coating and was not effective if 

the zinc coating is pierced or removed. 

The second method estimated life based on torsion ductility based on the number of turns to 

failure. This test method was applied to overhead ground wires, its application to ACSR 

conductors was considered conservative by the report since the steel core of ACSR cable does 

not carry the full load of the conductors. 

The third test employed in the study was a tensile test of ACSR conductors. This tensile test 

along with the torsional ductility test provided the most precise information. In all cases the 

average value for the tests was greater than 60 years with the tensile test indicating an average 

greater than 80 years for ASCR conductors. 

The tests performed by Ontario Hydroelectric found that the steel wire components showed 

reductions in tensile strength and that the reduction in conductor strength was primarily with the 

steel wire. The aluminum conductors were found to be in good condition. The Ontario 

Hydroelectric study also noted that environmental factors affected the corrosion of transmission 

line conductors. The study developed averages based on areas with industrial pollution and 

commercial development to regions with largely underdeveloped land. The regional averages 

for tensile tests were all greater than 70 years with regions containing little industry greater than 

80 years. The report also indicated that the aggregate breaking strength was found to be 

30 percent below the rated breaking strength for an 80-year-old ACSR cable because of 

corrosion.

The ACSR transmission conductors tested in the Ontario Hydroelectric report are documented 

in paper, "Aged ACSR Conductors, Part I – Testing Procedures for Conductors and Line Items” 

and “Aged ACSR Conductors Part 2 – Prediction of Remaining Life.” The applicant stated that 

ACSR conductor construction was included in the Ontario Hydroelectric test, and therefore the 

results of Ontario Hydroelectric test are representative of the ACSR transmission conductors 

installed at Callaway.

The applicant referenced the NESC which requires that tension on installed conductors be less 

than 60 percent of the rated breaking strength. The applicant stated that the NESC also sets 

the maximum tension a conductor must be designed to withstand under heavy load 

requirements, which includes consideration of ice, wind, and temperature. The applicant also 

stated that the ACSR transmission conductors with seven steel strands have a rated breaking 
AGING MANAGEMENT REVIEW RESULTS

3-501

strength of 22,100 lbs. The applicant further stated that the ACSR transmission conductors 

within the scope of license renewal are installed so that conductor final tension is 4,337 lbs at 

60 °F and does not exceed the NESC heavy loading condition of 5,525 lbs.

The Ontario Hydroelectric Study found that 80-year-old ACSR transmission conductors with a 

seven strand core had a breaking strength 30 percent below the rated breaking strength. The 

applicant stated that, assuming a 30 percent loss of rated breaking strength of 6,630 lbs 

because of corrosion over 60 years, the in-scope ACSR transmission conductors installed at 

Callaway have adequate design margin to offset the loss of strength because of corrosion. The 

applicant also stated that the ACSR transmission conductors will still meet the NESC 

requirement of not exceeding 60 percent of the rated breaking strength ((22,100–

6,630) x 60 percent = 9,282 lbs). The applicant further stated that the Ontario Hydroelectric test 

envelopes the conductors at Callaway and based on margin, demonstrates that material loss on 

the Callaway transmission conductors is acceptable for the period of extended operation. 

Based on the above, the applicant concluded that corrosion is not a credible aging effect that 

requires management for the period of extended operation.

The applicant stated that the outdoor environment is not subject to industry air pollution or saline 

environment. The applicant also stated that aluminum bus material, galvanized steel support 

structures and aluminum connection material do not experience appreciable aging effects in this 

environment. The applicant further stated that Callaway includes stainless steel Belleville 

washers in connection configurations that are torqued to prevent loss of preload. Finally the 

applicant stated that these connections are periodically evaluated via thermography as part of 

preventive maintenance activities. The applicant concluded that increased resistance of 

connections because of oxidation or loss of preload are not AERM for the period of extended 

operation. 

The staff noted that the applicant did not include plant-specific operating experience at Callaway 

to support the its claim that loss of ACSR conductor strength caused by corrosion, or increased 

resistance of connection because of oxidation or loss of preload are not significant aging effects 

requiring aging management, In addition, the applicant did not address whether a review of 

plant-specific operating experience indicated additional aging effects exist beyond those 

addressed in the GALL Report. By letter dated August 23, 2012, the staff issued 

RAI 3.6.2.2.3-1 requesting the applicant confirm that there has been no plant-specific operating 

experience of loss of conductor strength caused by corrosion, or increased resistance of 

connection caused by oxidation or loss of preload.

In its response dated September 20, 2012, the applicant stated that based on a review of 

Callaway corrective action documents there has been no plant-specific operating experience of 

loss of material caused by wind-induced abrasion or fatigue, loss of conductor strength because 

of corrosion, or increased resistance of connection caused by oxidation or loss of preload in 

transmission conductors and connections, or in switchyard bus and connections. The applicant 

also stated that there are no additional aging effects beyond those identified by the GALL 

Report and SRP-LR Section 3.6.2.2.3. 

The staff finds the applicant response acceptable because the applicant has provided 

plant-specific operating experience to further justify its claim that loss of material due to 

wind-induced abrasion and fatigue, loss of transmission conductor strength from corrosion, 

increased resistance of connection because of oxidation or loss of preload are not significant 

aging effects for transmission conductors and connections consistent with the GALL Report, 
AGING MANAGEMENT REVIEW RESULTS

3-502

SRP-LR Section 3.6.2.2.3 and SRP-LR Appendix A.1, including plant specific operating 

experience. The staff’s concern described in RAI 3.6.2.2.3-1 is resolved.

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 

because of corrosion, and increased resistance of connection caused by oxidation or loss of 

pre-load could occur in transmission conductors and connections, and in switchyard bus and 

connections. The GALL Report recommends further evaluation of a plant-specific AMP to 

ensure that this aging effect is adequately managed.

The staff noted that switchyard buses are connected to flexible conductors that do not swing 

and are supported by insulators and structural supports such as concrete footings and structural 

steel. Since there are no connections to moving or vibrating equipment, wind-induced abrasion 

and fatigue is not an applicable aging mechanism for switchyard bus and connections at 

Callaway.

The staff noted that wind born particulates have not been shown to be a contributor to loss of 

material at Callaway. Therefore, the staff finds that wind-induced abrasion and fatigue is not a 

significant aging effect requiring management for transmission conductors and connections at 

Callaway.

The staff noted that design of switchyard bolted connections precludes torque relaxation. The 

use of stainless steel Belleville washers is the industry standard to preclude torque relaxation. 

Callaway design incorporates the use of stainless steel Belleville washers on bolted electrical 

connections to compensate for temperature changes, maintain the proper torque, and prevent 

loss of preload. This method of assembly is consistent with the good bolting practices 

recommended by EPRI TR-104213, “Bolted Joint Maintenance & Application Guide.” The 

applicant’s preventive maintenance activities include periodically inspecting the connections 

through the use of thermography. The staff finds that increased resistance of connection 

caused by oxidation or loss of pre-load are not significant AERM for transmission conductor and 

switchyard bus connections at Callaway.

The Ontario Hydroelectric study showed a 30 percent loss of conductor strength of an 

80-year-old ACSR conductor due to corrosion. In addition, the NESC requires that tension on 

installed conductors be a maximum of 60 percent of the rated conductor breaking strength. The 

NESC also sets the maximum tension a conductor must be designed to withstand under heavy 

load requirements, which include consideration of 1⁄2 inch of radial ice and 4 pounds per square 

feet wind. Based on Callaway data the ACSR transmission conductors have a rated breaking 

strength of 22,100 lbs and calculated heavy load tension of 5,525 lbs with an actual installed 

tension of 4,337 lbs. For a new conductor, NESC criteria would allow an installed tension of 

13,260 lbs (22100 x 0.6) which results in a margin of 8,840 lbs (40 percent margin). The actual 

installed margin for Callaway is 17,763 lbs (22,100 lbs – 4,337) or 80 percent. Based on the 

Ontario Hydroelectric study, a loss of conductor strength of 30 percent on ACSR conductors 

would mean that the 60-year conductor strength for Callaway would be 15,470 lbs. 

(22,100 lbs x 0.7) lbs). The NESC-installed tension for a 60-year conductor at Callaway would 

be 9,282 lbs (15,470 x 0.6) resulting in an installed margin of 6,188 lbs (15,470 lbs – 9,282 lbs). 

The margin between the NESC calculated heavy load and the calculated Callaway transmission 

conductor 60-year breaking strength is 9,945 lbs (15,470 lbs – 5,525). The actual margin 

between the conductor installed tension and Callaway transmission conductor 60-year breaking 

strength is 11,133 lbs (15,470 lbs – 4,337 lbs) resulting in a 72 percent margin to the 60-year 

transmission conductor breaking strength. The ratio between the NESC calculated heavy load 
AGING MANAGEMENT REVIEW RESULTS

3-503

tension and the 60-year conductor breaking strength would be approximately 35 percent 

(5,525 lbs/15,470 lbs). The NESC requires that tension on installed conductor be a maximum of 

60 percent of the ultimate conductor strength. The staff determined that the example provided 

by the applicant bounds the in-scope Callaway transmission conductors. With a 30 percent loss 

of conductor strength, there remains ample margin between the NESC requirements and the 

actual conductor strength. 

The applicant also stated that corrosion of SAC transmission conductors within the switchyard 

to the first tower leaving the switchyard is not a credible aging effect that requires management 

for the period of extended operation. This is consistent with item VI.A LP-46 of the GALL 

Report and therefore the staff finds that loss of conductor strength due to corrosion for SAC 

transmission conductors is not a significant aging effect at Callaway. In addition, the staff finds 

that loss of conductor strength due to corrosion is not a significant aging effect requiring 

management for ACSR transmission conductors at Callaway.

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 items associated with LRA Section 3.6.2.2.3, the 

staff determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA Program.

3.6.2.2.5 Operating Experience

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience of aging management 

programs.

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMR results for material, 

environment, AERM, and AMP combinations not consistent with or not addressed in the GALL 

Report.

In LRA Table 3.6.2-1, the applicant indicated, via notes F through J, that the combination of 

component type, material, environment, and AERM does not correspond to an AMR item in the 

GALL Report. The applicant provided further information about how it will manage the aging 

effects. Specifically, note F indicates that the material for the AMR item component is not 

evaluated in the GALL Report. Note G indicates that the environment for the AMR item 

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

AMR item component, material, and environment combination is not applicable. Note J 

indicates that neither the component nor the material and environment combination for the AMR 

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 
AGING MANAGEMENT REVIEW RESULTS

3-504

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. 

The staff’s evaluation is discussed in the following sections.

3.6.2.3.1 Electrical and Instrumentation and Controls—Summary of Aging Management 

Evaluation—Electrical Components—LRA Table 3.6.2-1 

The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for the 

electrical components component groups.

Carbon Steel (Galvanized), Cement (Electrical Insulators), and Porcelain High Voltage 

Insulators Exposed to Atmosphere or Weather (External). In LRA Table 3.6.2-1, the applicant 

stated that for high voltage insulators made of carbon steel (galvanized), cement (electrical 

insulators), and porcelain, and exposed to atmosphere or weather (external), there are no aging 

effects and no AMPs are proposed. The AMR items cite generic note I and are associated with 

LRA Table 3.6-1, items 3.6.1-2 and 3.6.1-3. The AMR items also cite plant specific note 1, 

which state that the discussion of these items is documented in LRA Section 3.6.2.2.2. The 

staff’s evaluation of LRA Section 3.6.2.2.2 and items 3.6.1-2 and 3.6.1-3 is documented in SER 

Sections 3.6.2.2.2.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

Aluminum, Carbon Steel (Galvanized), and Stainless Steel Switchyard Bus and Connections 

Exposed to Atmosphere or Weather (External). In LRA Table 3.6.2-1, the applicant stated that 

for switchyard bus and connections made of aluminum, carbon steel (galvanized), and stainless 

steel, and exposed to atmosphere or weather (external), there are no aging effects and no 

AMPs are proposed. The AMR items cite generic note I and are associated with LRA 

Table 3.6-1, item 3.6.1-6. The AMR items also cite plant specific note 2, which state that the 

discussion of these items is documented in LRA Section 3.6.2.2.3. The staff’s evaluation of 

LRA Section 3.6.2.2.3 and item 3.6.1-6 is documented in SER Section 3.6.2.2.3.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

Aluminum, Aluminum Conductor Steel Reinforced, and Stainless Steel Transmission 

Conductors and Connections Exposed to Atmosphere or Weather (External). In LRA 

Table 3.6.2-1, the applicant stated that for transmission conductors and connections made of 

aluminum, aluminum conductor steel reinforced, and exposed to atmosphere or weather 

external there are no aging effects and no AMPs are proposed. The AMR items cite generic 

note I and are associated with LRA Table 3.6-1, items 3.6.1-2, 4, 5, and 7. The AMR items also 

cite plant specific note 2, which state that the discussion of these items is documented in LRA 

Section 3.6.2.2.3. The staff’s evaluation of LRA Section 3.6.2.2.3 and items 3.6.1-4, 5, and 7, is 

documented in SER Section 3.6.2.2.3. The staff’s evaluation of item 3.6.1-2 is documented in 

SER Section 3.6.2.2.2.
AGING MANAGEMENT REVIEW RESULTS

3-505

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.6.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the electrical and I&C components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, “Aging Management Review,” and LRA 

Appendix B, “Aging Management Programs.” On the basis of its review of the AMR results and 

AMPs, the staff concludes that the applicant has demonstrated that the aging effects will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the applicable FSAR supplement program summaries and concludes that the FSAR 

supplement adequately describes the AMPs credited for managing aging, as required by 

10 CFR 54.21(d).

With regard to these matters, the staff concludes that there is reasonable assurance that the 

applicant will continue to conduct the activities authorized by the renewed license in accordance 

with the CLB, and any changes made to the CLB, in order to comply with 10 CFR 54.21(a)(3), 

are in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.

4-1

SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses 

This section of the safety evaluation report (SER) provides the evaluation performed by the 

United States (U.S.) Nuclear Regulatory Commission (NRC) staff (the staff) of the basis 

provided by Union Electric Company (doing business as Ameren Missouri) (the applicant) for 

identifying those plant-specific or generic analyses that need to be identified as time-limited 

aging analyses (TLAAs) for the applicant’s license renewal application (LRA) and the list of 

TLAAs for the LRA. TLAAs are certain plant-specific safety analyses that involve time-limited 

assumptions defined by the current operating term. This SER section also provides the staff’s 

evaluation of the applicant’s basis for identifying those exemptions that need to be identified in 

the LRA.

In accordance with the requirements in Section 54.21(c)(1) of Title 10 of the Code of Federal 

Regulations (10 CFR 54.21(c)(1)), an applicant for license renewal must list all evaluations, 

analyses, and calculations in the current licensing basis (CLB) that conform to the definition of a 

TLAA, as specified in 10 CFR 54.3, “Definitions.” Regulations in 10 CFR 54.3 state that a 

plant-specific or generic evaluation, analysis, or calculation is a TLAA if it meets all six of the 

following identification criteria:

(1) involves a system, structure, or component (SSC) within the scope of license renewal, 

as delineated in 10 CFR 54.4(a)

(2) considers the effects of aging

(3) involves time-limited assumptions that are defined by the current operating term 

(e.g., 40 years)

(4) was determined to be relevant by the applicant in making a safety determination

(5) involves conclusions or provides the basis for conclusions related to the capability of the 

SSCs to perform its intended functions, as described in 10 CFR 54.4(b)

(6) is contained or incorporated by reference in the CLB

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list all plant-specific exemptions in 

the CLB that were granted in accordance with the exemption approval criteria in 10 CFR 50.12, 

“Specific Exemptions,” and that are based on a TLAA. For any such exemptions, the applicant 

must evaluate and justify the continuation of the exemptions for the period of extended 

operation.

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

for Nuclear Power Plants” (SRP-LR), Section 4.1, “Identification of Time-Limited Aging 

Analyses,” dated December 2010, provides the staff’s guidance for reviewing LRA Section 4.1. 

SRP-LR Section 4.1.1 summarizes the areas of review. SRP-LR Section 4.1.2 provides the 

staff’s acceptance criteria for performing TLAA and LRA exemption identification reviews. 

SRP-LR Section 4.1.3 provides the staff’s review procedures for performing the TLAA and LRA 

exemption identification reviews. SPR-LR Table 4.1-1 provides case-by-case examples on 
TIME-LIMITED AGING ANALYSES

4-2

whether a given analysis category would be required to be identified as a TLAA for an LRA. 

SPR-LR Table 4.1-2 provides a generic list of those analyses or calculations that are commonly 

identified as TLAAs for an LRA. SPR-LR Table 4.1-3 provides a generic list of those analyses 

or calculations that may be identified as plant-specific TLAAs for an LRA.

4.1.1 Summary of Technical Information in the Application 

4.1.1.1 Identification of Time-Limited Aging Analyses

LRA Section 4.1.1 states that a list of potential TLAAs was assembled from regulatory guidance 

and industry experience, which included the SRP-LR; NUREG-1801, Revision 2, “Generic Aging 

Lessons Learned (GALL) Report,” December 2010 (the GALL Report); Nuclear Energy Institute 

95-10, Revision 6, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54 –

the License Renewal Rule,” June 2005 (NEI 95-10); 10 CFR 54; prior license renewal 

applications and plant-specific document reviews; and interviews with plant personnel.

The LRA also states that the applicant performed keyword searches for its CLB to determine 

whether each of these potential TLAAs exists in the licensing basis. This keyword search was 

also used to identify additional potential plant-specific TLAAs. This search of the CLB included 

the final safety analysis report (FSAR) – Standard Plant (SP), the FSAR – Site Addendum (SA), 

technical specifications and bases, SERs for the original operating license, subsequent SERs, 

and Ameren Missouri and the staff docketed licensing correspondences.

Next, the applicant stated that the list of potential TLAAs was reviewed with respect to the 

criteria for a TLAA specified in 10 CFR 54.3(a). This review was based on the information in the 

CLB source documents and from source documents for the potential TLAAs, such as vendor, 

staff-sponsored, and licensee topical reports, design calculations, code stress reports or code 

design reports, drawings, and specifications. The LRA states that these source documents 

provided the information and the basis for the dispositions in LRA Section 4.

Based on this review, LRA Table 4.1-1, “List of TLAAs,” provides a list of the TLAAs applicable 

for the Callaway Plant:

• Neutron Embrittlement of the Reactor Vessel (LRA Section 4.2)

• Metal Fatigue of Vessels, Piping, and Components (LRA Section 4.3)

• Environmental Qualification (EQ) of Electric Equipment (LRA Section 4.4) 

• Loss of Prestress in Concrete Containment Tendons (LRA Section 4.5) 

• Fatigue of the Containment Liner and Penetrations (LRA Section 4.6)

• Other Plant-Specific TLAAs (LRA Section 4.7)

4.1.1.2 Identification of Exemptions

The LRA states that docketed correspondence, the operating license, and the FSAR were 

searched to identify exemptions in effect. Furthermore, there are only two exemptions “currently 

in effect,” that are based in part on a TLAA. These two analyses are the use of the 

leak-before-break (LBB) evaluation of reactor coolant system piping and the use of American 

Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Case N-514. The 

LRA states that the LBB analysis is described in LRA Section 4.7.7 and the use of ASME Code 

Case N-514, which supports the implementation of the low-temperature overpressure protection 

(LTOP) limits, is described in LRA Section 4.2.5.
TIME-LIMITED AGING ANALYSES

4-3

4.1.2 Staff Evaluation

4.1.2.1 Identification of TLAAs

The staff reviewed the applicant’s methodology for identifying the TLAAs and the TLAA results 

for the LRA against the six criteria for TLAA identification in 10 CFR 54.3 and the generic list of 

TLAAs in SRP-LR Section 4.1, including those in SRP-LR Tables 4.1-2 and 4.1-3, as reviewed 

for applicability to the Callaway CLB. The staff used the acceptance criteria in SRP-LR 

Section 4.1.2 and the review procedures in SRP-LR Section 4.1.3 as the basis for its review.

4.1.2.1.1 Evaluations, Analyses, and Calculations that Conform to the Definition of a TLAA, as 

defined in 10 CFR 54.3

The staff confirmed that the applicant included those TLAAs that SRP-LR Table 4.1-2 identifies 

as potentially being generically applicable to license renewal applicants. These TLAAs 

applicable to the applicant are provided below:

• Neutron Embrittlement of the Reactor Vessel (LRA Section 4.2)

• Metal Fatigue of Vessels, Piping, and Components (LRA Section 4.3)

• EQ of Electric Equipment (LRA Section 4.4) 

• Loss of Prestress in Concrete Containment Tendons (LRA Section 4.5) 

• Fatigue of the Containment Liner and Penetrations (LRA Section 4.6)

The staff determined that the applicant’s identification of these TLAAs is consistent with the staff 

recommendations for identifying applicable TLAAs in SRP-LR Sections 4.2 and 4.6. Based on 

this review, the staff finds that the identification of these TLAAs is acceptable and is in 

accordance with 10 CFR 54.21(c)(1). The staff’s evaluation of the applicant’s dispositions for 

these TLAAs in accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii) is documented in the 

corresponding SER Sections 4.2, 4.3, 4.4, 4.5, and 4.6 and their subsections.

The staff confirmed that the applicant reviewed the list of potential plant-specific TLAAs 

identified in SRP-LR Table 4.1-3 and, of these, identified the potential plant-specific TLAAs that 

the applicant either included as plant-specific TLAAs in LRA Section 4 or justified that they were 

not applicable TLAAs in LRA Section 4, as amended by letter dated May 3, 2012. Those 

potential plant-specific TLAAs identified in SRP-LR Table 4.1-3 that the applicant determined 

were not applicable to its LRA are evaluated in SER Section 4.1.2.1.2.

In addition, LRA Section 4.7 contains those plant-specific TLAAs that were identified as part of 

the applicant’s review of its CLB that are not correlated to SRP-LR Table 4.1-3. The staff’s 

evaluation of the applicant’s dispositions for these TLAAs, in accordance with 

10 CFR 54.21(c)(1)(i), (ii), or (iii), is documented in the corresponding SER Section 4.7 and its 

subsections.

4.1.2.1.2 Evaluation of Applicant’s List of Evaluations, Analyses, and Calculations that Do Not 

Conform to the Definition of a TLAA, as defined in 10 CFR 54.3

Absence of a TLAA for Reactor Vessel Underclad Cracking Analyses. LRA Table 4.1-1 

identifies that the applicant’s CLB does not include an analysis for reactor vessel underclad 

cracking that meets the definition of a TLAA. LRA Section 4.7.4 contains additional information 

related to the applicant’s determination that there is no TLAA for reactor vessel underclad 

cracking.
TIME-LIMITED AGING ANALYSES

4-4

By letter dated May 3, 2012, the applicant revised LRA Table 4.1-1 and LRA Section 4.7.4 to 

identify that its CLB contains a TLAA for reactor vessel underclad cracking. Specifically, the 

revised LRA Section 4.7.4 states that Westinghouse Commercial Atomic Power

(WCAP)-15338-A has demonstrated that the vessel integrity is maintained in the presence of 

underclad cracks and addresses the aging mechanism of underclad cracking. WCAP-15338-A 

is, therefore, a TLAA for the Callaway Plant and is dispositioned in accordance with 

10 CFR 54.21(c)(1)(i). The staff’s evaluation of LRA Section 4.7.4, as amended by letter dated 

May 3, 2012, is documented in SER Section 4.7.4.2.

Absence of a TLAA for Inservice Local Metal Containment Corrosion Analyses. LRA 

Table 4.1-2 identifies that an inservice local metal containment corrosion analysis is applicable 

to its CLB and is evaluated in LRA Section 4.7.3, “Corrosion Analysis of the Reactor Vessel 

Cladding Indications.” By letter dated May 3, 2012, the applicant revised LRA Table 4.1-2 to 

indicate that the CLB does not include any inservice local metal containment corrosion analyses 

for its plant.

The staff reviewed FSAR Section 3.8 and noted that the containment structure is designed to 

house the reactor coolant system (RCS) and is referred to as the reactor building. The reactor 

building is part of the containment system designed to control the release of airborne 

radioactivity following postulated design basis accidents and to provide shielding for the reactor 

core and the RCS. FSAR Section 3.8.1.1.1 further describes the reactor building as consisting 

of a prestressed, reinforced concrete, cylindrical structure with a hemispherical dome and a 

conventionally reinforced concrete base slab with a central cavity and instrumentation tunnel to 

house the reactor vessel.

The staff confirmed that FSAR Section 3.8 does not reference any localized metal corrosion 

analyses for the containment structure, other Seismic Category 1 structures, or their 

subcomponents. Therefore, the staff finds that the LRA does not need to include any localized 

metal containment corrosion TLAAs because the applicant’s CLB does not include or reference 

metal corrosion analyses for the concrete containment structure, other Seismic Category 1 

structures, or their subcomponents. 

Absence of a TLAA for lntergranular Separations in the Heat-Affected Zone (HAZ) of Reactor 

Vessel Low-Alloy Steel under Austenitic SS Cladding. LRA Table 4.1-2 identifies that the 

Westinghouse technical report analysis of intergranular separations in the heat-affected zones 

of the reactor vessel low-alloy steel forging to cladding welds is not applicable to its CLB and is 

evaluated in LRA Section 4.7.4. By letter dated May 3, 2012, the applicant revised LRA 

Table 4.1-2 to indicate that this analysis is applicable to its CLB and is a TLAA, which is 

evaluated in LRA Section 4.7.4. The staff’s evaluation of LRA Section 4.7.4, as amended by 

letter dated May 3, 2012, is documented in SER Section 4.7.4.2.

Absence of a TLAA for Flow-Induced Vibration Endurance Limit for the Reactor Vessel 

Internals. LRA Table 4.1-2 identifies that an analysis for flow-induced vibration endurance limit 

for the reactor vessel internal (RVI) components is not applicable to its CLB and that the basis 

for claiming an absence of a TLAA on this topic is evaluated in LRA Section 4.3.3. LRA 

Section 4.3.3 states that protection from flow-induced vibration for the RVI components is 

ensured by satisfying the regulatory position in Regulatory Guide (RG) 1.20, “Comprehensive 

Vibration Assessment Program for Reactor Internals during Preoperational and Initial Startup 

Testing.” The applicant also stated that the basis for meeting RG 1.20 is discussed in FSAR 

Sections 3.9(N).2.3, 3.9(N).2.4, and 3.9(N).2.6 SP. The applicant stated that its review of the 
TIME-LIMITED AGING ANALYSES

4-5

supporting references in these FSAR sections did not identify any analyses that were based on 

time-limited assumptions defined by the current operating term. 

The staff noted that RG 1.20 provides an acceptable position that can be used by an applicant 

to demonstrate compliance with the technical information requirements for flow-induced 

vibrations in 10 CFR 50.34, “Design Objectives for Equipment to Control Releases of 

Radioactive Material in Effluents — Nuclear Power Reactors.” It also permits applicants to 

assess flow-induced vibrations of their RVI components using prototypical data and tests results 

from other U.S. pressurized-water reactors (PWRs) whose RVI components were well analyzed 

for their responses to flow-induced vibrations. The staff reviewed FSAR Sections 3.9(N).2.3, 

3.9(N).2.4, and 3.9(N).2.6 SP and confirmed that there is no discussion or reference to analyses 

associated with a dependence on time for flow-induced vibration endurance limits for the RVIs. 

Based on its review of the FSAR, the staff determined that the evaluation of high cycle 

vibrational loads does not depend on the licensed period and is therefore not a TLAA in 

accordance with 10 CFR 54.3(a).

Absence of a Fatigue Analysis TLAA for the Metal Containment Liner. LRA Section 4.6 states 

that the applicant’s review of the CLB did not identify any fatigue analyses for the containment 

liner plate. Furthermore, the LRA states that the prestressed concrete containment vessel was 

poured against a steel membrane liner designed to the standards in Bechtel Topical Report 

BC-TOP-1, Revision 1, “Containment Building Liner Plate Design Report,” (BC-TOP-1). The 

applicant clarified that the containment liner and other metal containment components were 

designed to stress limit criteria of BC-TOP-1, independent of the number of load cycles, and 

require no fatigue analyses with the exception of the main steam and feedwater penetrations, 

the containment access hatches, and the leak chases. 

The staff reviewed FSAR-SP Section 3.8.1.4.6, “Steel Liner Plate and Anchors,” which identifies 

the governing design documents for the containment liner plate to be Bechtel Report BC-TOP-1,

and BC-TOP-5-A Sections 6.8, 7.5, and Appendix C. The staff searched the design calculations 

(BC-TOP-1) in the CLB for the liner and noted that, for design calculations, it “was subjected to 

the effects of prestress, concrete creep and shrinkage, deadload, maximum hypothetical 

earthquake, accident thermal gradients, and accident pressure.” BC-TOP-1 does not contain an 

entry for fatigue or loading cycles related to fatigue design of the liner plate. The staff also 

reviewed BC-TOP-5-A Sections 6.8, “Liner Plate System,” 7.5, “Liner Plate System,” and 

Appendix C, “Design Criteria,” and noted the only relevant entry regarding fatigue is in 

Appendix C of BC-TOP-5-A, which incorporates verbatim Section CC-3760, “Fatigue,” of the 

Proposed Standard for Concrete Reactor Vessels and Containments (Proposed Section III, 

Division 2) ASME B&PV Code. 

The staff searched both the FSAR-SP and FSAR-SA using the keywords “cycles” and “fatigue.” 

There were no entries related to loading cycles for the steel liner, but there were entries related 

to fatigue. Key elements of Section CC-3760, “Fatigue,” are replicated in FSAR-SP

Section 3.7(B).3.2, “Determination of Number of Earthquake Cycles,” which states that “[f]atigue 

was not considered in the design of seismic Category I structures, because the occurrence of 

full design earthquake loads is too infrequent to warrant consideration of fatigue design, and the 

calculated stresses and strains are below yield.” FSAR-SP Table 3.8-3, “Stress Limits for Steel 

Portions of Concrete Containments Designed in Accordance with Subsection NE of the ASME 

Code,” contains three loading combinations that consider fatigue in the analysis when peak 

stresses are involved. These, however, are considered for Section 3.8.2, “Containment System 

Steel Items,” which describes the major penetrations and portions of penetrations intended to 

resist pressure, which are not backed by structural concrete. The fatigue analyses for the main 
TIME-LIMITED AGING ANALYSES

4-6

steam and feedwater penetrations are discussed in LRA Section 4.6.1, the fatigue analyses for 

the containment access hatches and the leak chases are discussed in LRA Section 4.6.2, and 

the staff’s reviews of these LRA sections are documented in SER Sections 4.6.1 and 4.6.2, 

respectively.

Based on its review, the staff confirmed that the analysis and design procedures used for the 

liner plate system are in accordance with BC-TOP-1. Furthermore, FSAR Table 1.6-1 indicates 

that BC-TOP-1 was submitted to the staff for review in January 1973 and was later approved by 

the staff. The staff reviewed BC-TOP-1 and confirmed that it does not include an analysis that 

is dependent on time-limited assumptions defined by the current operating term for the metal 

containment liner; thus, the staff finds the design of containment liner plate does not include a 

TLAA.

Absence of a TLAA for Ductility Reduction of Fracture Toughness for the Reactor Vessel 

Internals. LRA Section 4.3.3 states that a review of the CLB did not identify a 40-year ductility 

reduction analysis for RVI components.

The staff noted that SRP-LR Section 3.1.2.2.3.3 states that the evaluation of ductility reduction 

may be a plant-specific TLAA for the RVI components in Babcock and Wilcox (B&W) reactor 

designs and is to be evaluated for the period of extended operation in accordance with the 

staff’s safety evaluation on B&W Owners Group Technical Report No. BAW-2248,

“Demonstration of the Management of Aging Effects for the Reactor Vessel Internals,” dated 

December 9, 1999, (Agencywide Documents Access and Management System (ADAMS) 

Accession No. ML993490303). The staff reviewed the FSAR and confirmed that the applicant’s 

CLB does not contain or reference a 40-year embrittlement analysis for RVI components. In 

addition, the staff determined that Technical Report No. BAW-2248 is not applicable because 

the applicant’s plant is a Westinghouse-designed PWR. Instead, the staff confirmed that the 

applicant manages loss of fracture toughness and reduced material ductility in the RVI 

components during the period of extended operation with its PWR Vessel Internal Program. 

The staff’s evaluation of the PWR Vessel Internal Program is documented in SER 

Section 3.0.3.1.5. Based on its review of the FSAR, the staff determined that an analysis of 

ductility reduction for RVI components does not exist in the applicant’s CLB and, therefore, is 

not a TLAA in accordance with 10 CFR 54.3(a).

Absence of a TLAA for Metal Corrosion Allowance. LRA Table 4.1-2 identifies that metal 

corrosion allowance analyses are not applicable to the applicant’s CLB because no explicit 

metal corrosion allowance analysis basis that is based on plant life applies to the CLB. By letter 

dated May 3, 2012, the applicant revised LRA Table 4.1-2 to indicate that the CLB does include 

a metal corrosion analysis that is TLAA for the LRA. The applicant stated that the TLAA is 

evaluated in LRA Section 4.7.3, as amended for in the letter of May 3, 2012.

The staff’s evaluation of the revised LRA Section 4.7.3 is documented in SER Section 4.7.3.2.

Absence of a TLAA for Minimum Required Value for Concrete Containment Tendon Prestress. 

LRA Section 4.5 states that to ensure the integrity of the containment pressure boundary under 

design basis accident loads, tendon surveillances are performed under the Inservice Inspection 

Program in accordance with ASME Code Section XI, Subsection IWL. Furthermore, the 

minimum required value is the average tendon prestress force used in the prestressed concrete 

containment design analysis. The design prestress must account for the loss of prestressing 

force after the initial tensioning, in accordance with RG 1.35.1, “Determining Prestressing 

Forces for Inspection of Prestressed Concrete Containments.” The LRA also states that the 

minimum required value is the acceptance criterion for the average tendon prestressing force 
TIME-LIMITED AGING ANALYSES

4-7

over the entire plant life and does not vary with the plant life; therefore, the MRV is not a TLAA, 

in accordance with 10 CFR 54.3(a).

The staff’s review of the applicant’s claim that the minimum required value for concrete 

containment tendon prestress is not a TLAA is documented in SER Section 4.5.

Absence of a TLAA for Design Cycles for the Feedwater Penetrations. LRA Section 4.6.1 

states that the analyses in BC-TOP-1 do not qualify the components on a generic basis. The 

staff noted that analyses must be performed, or at least the analyses in BC-TOP-1 must be 

confirmed to be conservative, on a plant-specific basis. The applicant stated that, for its plant, 

the specific analyses were performed for the main steam line penetrations and the feedwater 

penetrations. Furthermore, BC-TOP-1, Part II, analyzed “Loading Condition V,” which 

compared the allowed value of the alternating stress range from the ASME Code Section III, 

I-9-1 diagram for 100 cycles to the maximum calculated alternating stress intensity for the load 

combination. The applicant stated that its plant-specific analysis determined that the feedwater 

penetrations would not exceed the primary plus secondary stress intensity (3SM) requirement of 

ASME Code Section III, Subsection NB-3222.2 for “Loading Condition V” and does not require 

an elastic-plastic analysis for the feedwater penetrations. Thus, the analysis of the feedwater 

penetrations for “Loading Condition V” does not include a cyclic loading aging effect and is not a 

TLAA in accordance with 10 CFR 54.3(a). 

The staff’s review of the applicant’s claim that the design cycles for the feedwater penetrations

is not a TLAA is documented in SER Section 4.6.1.

Absence of a TLAA for Fracture Mechanics Analyses for Cold Leg Elbow-to-Safe End Weld 

Flaw Indications. LRA Section 4.7.2 states that operation with a crack is acceptable with 

respect to unstable ductile tearing mechanism if the applied J-integral remains below the 

JIc fracture toughness and the only aging mechanism that affects these criteria is thermal aging. 

It further states that the forged safe end material is not subject to thermal aging; the gas 

tungsten arc welds (GTAWs) are subject to thermal aging, but the effects are considered 

negligible. The applicant stated that the fracture mechanics analysis for these flaw indications 

do not consider aging effects and is not a TLAA, by 10 CFR 54.3(a), Criterion 2.

The staff noted that LRA Section 4.7.2 did not justify why the GTAWs are subject to thermal 

aging, but the effect is considered negligible. In addition, the LRA did not indicate if the 

statically cast stainless steel elbow is susceptible to thermal aging and why such fracture 

mechanics analysis is not a TLAA. By letter dated August 6, 2012, the staff issued request for 

additional information (RAI) 4.7.2-2 requesting the applicant justify that thermal aging on the 

GTAWs is considered negligible and justify why the fracture mechanics analysis did not 

consider thermal aging. The staff’s evaluation of the applicant’s response to RAI 4.7.2-2 and 

the applicant’s claim that the fracture mechanics analysis for cold leg elbow-to-safe end weld 

flaw indications is not a TLAA is documented in SER Section 4.7.2.2. In addition, the staff’s 

evaluation of the fatigue crack growth TLAA for cold leg elbow-to-safe end weld flaw indications 

is also documented in SER Section 4.7.2.2.

Absence of a TLAA for the Fracture Mechanics of the Reactor Coolant Loops 

Leak-Before-Break Analysis. LRA Section 4.7.7 states that the reactor coolant loop LBB 

analysis included a fracture mechanics analysis, which accounts for reduction in fracture 

toughness of the cast austenitic stainless steel (CASS) in the primary loops from thermal aging. 

The LRA further states that the fracture mechanics analysis was performed for a reference 

material with fully aged fracture toughness material properties. Therefore, the applicant 
TIME-LIMITED AGING ANALYSES

4-8

determined that since the fracture toughness material properties used in the analysis are not 

time-dependent, this analysis is not a TLAA because it does not conform to 10 CFR 54.3(a).

The staff noted that the evaluation of the fracture toughness property for CASS reactor coolant 

loop components in the LBB would not be time-dependent if the applicant’s analysis assumed a 

lower-bound fracture toughness for the CASS components under assumed saturated thermal 

aging conditions. However, the staff also noted that the applicant’s basis may be predicated on 

thermal aging data that are not up-to-date or conservative when compared to the most recent 

data for the industry. By letter dated August 6, 2012, the staff issued RAI 4.7.7-2 requesting the 

applicant to justify why the fracture toughness material properties used in the LBB analysis are 

not time dependent and whether the thermal aging data used in the analysis are up-to-date or 

conservative when compared to the most recent data for the state of the industry. The staff’s 

evaluation of the applicant’s response to RAI 4.7.7-2 and the applicant’s claim that the fracture 

mechanics analysis of the reactor coolant loops LBB analysis is not a TLAA is documented in 

SER Section 4.7.7.2. In addition, the staff’s evaluation of the fatigue crack growth TLAA of the 

reactor coolant loops LBB analysis also is documented in SER Section 4.7.7.2.

Absence of a TLAA for the Fracture Mechanics of the Leak Before Break Analyses for the

Accumulator Injection and Residual Heat Removal Lines. LRA Section 4.7.7 states that 

Westinghouse performed LBB analyses of the 10 in. accumulator lines and the 12 in. residual 

heat removal (RHR) lines to minimize pipe breaks and reduce pipe whip restraints and jet 

shield, which would mitigate the dynamic consequences of the postulated breaks. It further 

states that the LBB analyses consist of fracture mechanics and fatigue crack growth analyses. 

The applicant stated that since the components in these lines and associated fittings are made 

from forged materials, they are not subject to thermal aging embrittlement. Therefore, the 

applicant stated that the fracture mechanics analyses in the LBB assessment are not TLAAs 

because they do not conform to 10 CFR 54.3(a), criterion 2.

The staff noted that, as described in the GALL Report, at operating temperatures of 250 to 343 

degrees Celsius (°C) [500 to 650 degrees Fahrenheit (°F)], cast austenitic stainless steels 

exhibit a spinodal decomposition of the ferrite phase into ferrite-rich and chromium-rich phases. 

Furthermore, the phenomena may give rise to significant embrittlement (reduction in fracture 

toughness) caused by thermal aging, depending on the amount, morphology, and distribution of 

the ferrite phase and the alloying composition of the steel. The staff noted that since the 

accumulator injection and RHR lines, including associated fittings, at the applicant’s site are 

forged components and do not contain a sufficient amount of the ferrite phase, thermal aging 

and spinodal decomposition, as described above, are not a concern for these reactor coolant 

pressure boundary (RCPB) piping lines. The staff finds that spinodal decomposition and 

thermal aging embrittlement are not applicable to these lines that only include forging materials. 

It also finds that the Westinghouse fracture mechanics analysis is not applicable to these lines 

and does not need to be identified as a TLAA. The staff’s evaluation of the fatigue crack growth

TLAA of the LBB analyses for the accumulator injection and RHR lines is documented in SER 

Section 4.7.7.2.

4.1.2.2 Identification of Exemptions in the LRA

LRA Section 4.1.2 states that 10 CFR 54.21(c)(2) requires a list of plant-specific exemptions 

granted in accordance with 10 CFR 50.12 and in effect that are based on TLAAs as defined in 

10 CFR 54.3. It further states that an evaluation that justifies the continuation of these 

exemptions for the period of extended operation shall be provided. The staff noted that 

docketed correspondence, the operating license, and the FSAR were searched by the applicant 
TIME-LIMITED AGING ANALYSES

4-9

to identify exemptions in effect, and each exemption in effect was then evaluated to determine if 

it involved a TLAA as defined in 10 CFR 54.3.

The applicant stated that only two exemptions “currently in effect” are based, in part, on a TLAA, 

which include the use of the LBB evaluation of RCS piping and the use of ASME Code Case 

N-514. The staff noted that the first exemption based on a TLAA relates to the staff’s 

permission to use the LBB evaluation as the basis for being exempt to the dynamic effect 

protection requirements in 10 CFR Part 50, Appendix A, “General Design Criteria for Nuclear 

Power Plants,” Criterion 4, “Environmental and Dynamic Effects Design Bases.” The applicant’s 

evaluation of the LBB TLAA for the main coolant loops, accumulator line, and RHR line in the 

RCPB is described in LRA Section 4.7.7. The staff’s evaluation of the leak before break TLAA 

is documented in SER Section 4.7.7.2. In addition, it was noted that in the second exemption 

that ASME Code Case N-514 supports the implementation of the LTOP limits. The applicant’s 

evaluation of the methodology, consistent with WCAP-14040-NP-A and ASME Code 

Case N-514, to determine the cold overpressure mitigation system pressurizer power operated 

relief valve (PORV) setpoints is described in LRA Section 4.2.5. The staff’s evaluation of the 

low temperature overpressure protection TLAA is documented in SER Section 4.2.5.2.

The staff reviewed the applicant’s FSAR and, in addition to the two above-mentioned 

exemptions, the staff identified other exemptions discussed in FSAR Section 16.6.1.1.2. This 

FSAR Section states the following exemptions have been granted to the requirements of 

Appendix J of 10 CFR Part 50:

• Section III.A.1(a) — an exemption to the requirement to stop the Type A test if excessive 

leakage is determined. This exemption allows the satisfactory completion of the Type A 

test if the leakage can be isolated and appropriately factored into the results.

• Section III.A.5(b) — an exemption for the acceptance criteria, in lieu of the present single 

criterion of the total measured containment leakage rate being less than 0.75 of the 

maximum allowable leakage rate (La), the "as found" allowable leakage rate will be La 

and the "as left" allowable leakage rate will be less than 0.75 La.

• Section III.D.1(a) — an exemption that removes the requirement that the third test of 

each set of three Type A tests be conducted when the plant is shut down for the 10-year 

plant inservice inspection.

The staff reviewed FSAR Section 16.6.1.1.2 and the applicable sections of Appendix J of 

10 CFR Part 50, and it determined that these exemptions are not based on an aging effect or 

any analysis that is a TLAA for the LRA. Thus, these exemptions do not meet the criteria of a 

TLAA, as defined in 10 CFR 54.3(a), and do not need to be identified in accordance with 

10 CFR 54.21(c)(2).

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 concludes that, as required by 

10 CFR 54.21(c)(2), the applicant has identified the appropriate exemptions that were granted 

under 10 CFR 50.12 and that are based on a TLAA.
TIME-LIMITED AGING ANALYSES

4-10

4.2 Reactor Vessel Neutron Embrittlement Analysis 

During plant service, neutron irradiation reduces the fracture toughness of ferritic steel in the 

reactor vessel beltline region, as defined in 10 CFR Part 50, Appendix G, “Fracture Toughness 

Requirements,” for light-water nuclear power reactors. In addition to the ASME Code Section III 

requirements, the reactor vessel materials must maintain adequate fracture toughness during 

both normal and off-normal operating conditions (e.g., upset, emergency, and faulted 

conditions) to ensure the structural integrity of the reactor vessel during the period of extended 

operation.

LRA Section 4.2 provides the applicant’s analyses of the following areas related to reactor 

vessel neutron embrittlement:

• LRA Section 4.2.1, “Neutron Fluence Values”

• LRA Section 4.2.2, “Charpy Upper-Shelf Energy” 

• LRA Section 4.2.3, “Pressurized Thermal Shock”

• LRA Section 4.2.4, “Pressure-Temperature (P-T) Limits”

• LRA Section 4.2.5, “Low Temperature Overpressure Protection” 

10 CFR Part 50, Appendix G, specifies fracture toughness requirements for ferritic 

pressure-retaining components that make up the RCPB of light-water nuclear reactors, including 

requirements for Charpy upper-shelf energy (USE) and P-T limits. The rule states that reactor 

vessel beltline material properties, including the nil-ductility reference temperature (RTNDT) 

values and Charpy USE values, must account for the effects of neutron irradiation. The staff’s 

guidelines for neutron embrittlement calculations are established in RG 1.99, Revision 2, 

“Radiation Embrittlement of Reactor Vessel Materials,” dated May 1988. RG 1.99 specifies the 

methods for calculating the projected adjustment to the RTNDT values (adjusted RTNDT) and the 

projected decrease in the Charpy USE values for reactor vessel beltline materials caused by 

neutron irradiation during the operating life of the plant.

Regulations in 10 CFR 50.61, “Fracture Toughness Requirements for Protection against 

Pressurized Thermal Shock Events,” provide requirements for ensuring the resistance of reactor 

vessel beltline materials against pressurized thermal shock (PTS) events, as applicable only to 

PWR plants. The PTS rule characterizes the toughness of reactor vessel beltline materials by 

the reference temperature for PTS (RTPTS) which is defined as the RTNDT value evaluated for the 

projected end-of-life (EOL) fluence or, for license renewal, the projected end-of-life-extended 

(EOLE) neutron fluence, at the reactor vessel stainless steel clad-to-low-alloy steel (clad/base 

metal) interface. Procedures in 10 CFR 50.61 for calculating RTPTS are the same as those 

established in RG 1.99 for calculating the adjusted RTNDT.

4.2.1 Neutron Fluence Values

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 describes the applicant's TLAA for the neutron fluence values. The applicant 

stated that neutron fluence projections are made to analyze neutron embrittlement effects on 

Charpy USE and RTPTS. The applicant also stated that fluence projections were calculated 

based on a conservatively assumed plant lifetime capacity factor of 90 percent, which 

corresponds to 54 effective full power years (EFPYs) of facility operation for 60 calendar years 

of operation, also referred to as EOLE.
TIME-LIMITED AGING ANALYSES

4-11

According to the applicant, the fluence values for EOLE were projected based on the results of 

the analysis for reactor vessel surveillance Capsule X (Capsule X), as documented in 

WCAP-15400-NP, “Analysis of Capsule X from the Ameren UE Callaway Unit 1 Reactor Vessel 

Surveillance Program,” June 2000. The applicant stated that the 54 EFPY fluence projections 

were determined based on neutron transport calculations using the discrete ordinates code, 

DORT, with the BUGLE-96 cross-section library, which is derived from ENDF/B-VI scattering 

cross-section data set. The applicant further stated that these neutron transport and dosimetry 

evaluation methodologies follow the guidance of RG 1.190, “Calculational and Dosimetry 

Methods for Determining Pressure Vessel Neutron Fluence,” dated March 2001, and are 

consistent with the fluence methodology described in WCAP-14040-A, “Methodology Used 

To Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown 

Limit Curves,” Revision 4, dated May 2004. The applicant provided peak neutron fluence 

values, projected to 54 EFPY, for the reactor vessel beltline and extended beltline materials in 

LRA Tables 4.2-1 and 4.2-2.

The applicant dispositioned the TLAA for the neutron fluence values in accordance with 

10 CFR 54.21(c)(1)(ii), that the neutron fluence analysis has been projected to the end of the 

period of extended operation.

4.2.1.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the neutron fluence values and the corresponding 

disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in SRP-LR 

Section 4.7.3.1.2, which state that the documented results of the revised analyses are reviewed 

to verify that their period of evaluation is extended, such that they are valid for the period of 

extended operation (e.g., 60 years). The SRP-LR also states that the applicable analysis 

technique can be the one that is in effect in the plant’s CLB at the time of filing of the LRA.

The analysis technique for determining the 54 EFPY fluence values is the same as the one that 

is currently in effect in the Callaway CLB. Specifically, the staff confirmed that the 54 EFPY 

neutron fluence values for the Callaway reactor vessel beltline and extended beltline materials 

were calculated using the same staff-approved neutron fluence methodology that is currently 

approved in the CLB for calculating beltline material adjusted RTNDT values for P-T limit curves. 

The neutron transport and dosimetry evaluation methodologies follow the guidance of RG 1.190 

and are consistent with the neutron fluence calculation methods established in the 

staff-approved P-T limits report (PTLR) methodology for Westinghouse plants, WCAP-14040-A, 

Revision 4.

The WCAP-14040-A, Revision 4 PTLR methodology for Westinghouse plants discusses the 

methods for plant-specific neutron transport calculations and the validity of the calculations. For 

the neutron transport calculations, the WCAP-14040-A, Revision 4 PTLR methodology 

implements the two-dimensional discrete ordinates code, DORT, with the BUGLE-96 cross 

section library, which is derived from ENDF/B-VI scattering cross-section data set. As 

discussed in its February 27, 2004, Final Safety Evaluation (SE) for WCAP-14040-A, 

Revision 4, the staff determined that the above neutron fluence calculation methodology 

adheres to the guidance of RG 1.190 and is acceptable for implementation without conditions by 

Westinghouse plants implementing the WCAP-14040-A methodology for calculating P-T limit 

curves.

LRA Tables 4.2-1 and 4.2-2 provide peak neutron fluence projections for EOLE (54 EFPY) at 

the reactor vessel clad/base metal interface for the reactor vessel beltline and extended beltline 

regions, respectively. The staff noted that the applicant applied a neutron fluence threshold of 
TIME-LIMITED AGING ANALYSES

4-12

1 x 1017 n/cm2 (E greater than 1.0 MeV) to define the reactor vessel beltline and extended 

beltline materials subject to neutron embrittlement analysis in LRA Section 4.2. The staff finds 

that the applicant’s definition of the RV beltline region includes those materials previously 

analyzed for neutron embrittlement for the CLB through 35 EFPY. The applicant’s definition of 

the extended beltline region includes materials outside the CLB beltline region that have 

projected neutron fluence exposure greater than 1 x 1017 n/cm2 (E greater than 1.0 MeV) for the 

period of extended operation. 

The fluence threshold for identifying the reactor vessel beltline materials is defined in the GALL 

Report as 1 x 1017 n/cm2 (E greater than 1.0 MeV) at the end of the period of extended 

operation. This fluence threshold is based on the Reactor Vessel Material Surveillance 

Program requirements of 10 CFR Part 50, Appendix H, “Reactor Vessel Material Surveillance 

Program Requirements,” which requires monitoring the changes in fracture toughness 

parameters caused by neutron embrittlement for all reactor vessel materials projected to 

experience neutron fluence greater than 1 x 1017 n/cm2 (E greater than 1.0 MeV) at the 

expiration of the facility operating license. Therefore, the staff finds the applicant’s definition of 

the reactor vessel beltline and extended beltline regions acceptable because it is consistent with 

guidance provided in the GALL Report.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that 

the analysis for determining the reactor vessel neutron fluence values and defining the reactor 

vessel beltline and extended beltline regions has been adequately projected to the end of the 

period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.7.2.1 because the applicant’s analysis for determining the neutron fluence values and 

defining the beltline and extended beltline regions of the reactor vessel has been projected to

the end of the period of extended operation, in accordance with the requirements of 

10 CFR 54.21(c)(1)(ii).

4.2.1.3 FSAR Supplement

LRA Section A3.1.1 provides the FSAR supplement summarizing the neutron fluence TLAA. 

The staff reviewed LRA Section A3.1.1 consistent with the review procedures in SRP-LR 

Section 4.7.3.2, which state that the FSAR supplement is reviewed to verify that the applicant 

has provided an appropriate summary description of the evaluation of the TLAA, including the 

applicant’s disposition of the TLAA for the period of extended operation.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2, and is therefore acceptable. Additionally, the staff finds that the 

applicant provided an adequate summary description of its actions to address neutron fluence 

for the period of extended operation, as required by 10 CFR 54.21(d).

4.2.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(ii), that the analysis for determining the 

reactor vessel neutron fluence values and defining the reactor vessel beltline and extended 

beltline regions has been adequately projected to the end of the period of extended operation. 

The staff also concludes that the FSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).
TIME-LIMITED AGING ANALYSES

4-13

4.2.2 Charpy Upper-Shelf Energy

4.2.2.1 Summary of Technical Information in the Application

LRA Section 4.2.2 describes the applicant's TLAA for Charpy USE. The applicant stated that 

the USE results from Capsule X are reported in WCAP-15400-NP. According to the applicant, 

the Charpy test results were deemed to be credible and show that the decline in USE for the 

surveillance plate and weld materials are less than originally predicted by RG 1.99, 

demonstrating that the reactor vessel materials age consistently with RG 1.99 predictions and 

provide assurance of reactor vessel integrity. 

The applicant stated that the USE values for the reactor vessel beltline and extended beltline 

materials were projected to the end of the period of extended operation in WCAP-17168-NP, 

“Callaway Unit 1 Time-Limited Aging Analysis on Reactor Vessel Integrity,” September 2010. 

These USE calculations are summarized in LRA Table 4.2-3. According to the applicant, the 

most limiting value of EOLE USE for any of these materials is 61 ft-lbs for Intermediate Shell 

Plate R2707-1. The applicant stated that this satisfies the 10 CFR Part 50, Appendix G EOL (or 

EOLE) USE acceptance criterion of 50 ft-lbs.

The applicant dispositioned the TLAA for the Charpy USE in accordance with 

10 CFR 54.21(c)(1)(ii), that the USE analysis has been projected to the end of the period of 

extended operation.

4.2.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the Charpy USE and the corresponding disposition 

of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in SRP-LR Section 4.2.3.1.1.2, 

which state that the documented results of the revised USE analysis based on the projected 

neutron fluence at the end of the period of extended operation are reviewed for compliance with 

10 CFR Part 50, Appendix G. The SRP-LR also states that the applicant may use RG 1.99 to 

project USE to the end of the period of extended operation, or the applicant also may use the 

ASME Code Section XI, Appendix K, for the purpose of performing an equivalent margins 

analysis (EMA) to demonstrate that adequate protection against ductile failure is maintained to 

the end of the period of extended operation.

10 CFR Part 50, Appendix G specifies that reactor vessel beltline materials must maintain 

Charpy USE values of no less than 50 ft-lbs throughout the operating life of the facility, unless it 

is demonstrated through an EMA that adequate protection against ductile failure is maintained 

to the end of the period of extended operation. Therefore, for the reactor vessel beltline 

materials, EMAs are required only if the projected USE values at EOLE cannot be shown to be 

greater than or equal to 50 ft-lbs.

In LRA Table 4.2-3, the applicant provided 54 EFPY USE values for all RV beltline and 

extended beltline materials. All 54 EFPY USE values are projected to remain greater than 

50 ft-lbs, as required by 10 CFR Part 50, Appendix G. The limiting (lowest) 54 EFPY USE value 

is 61 ft-lbs for Intermediate Shell Plate R2707-1. The staff independently confirmed that all 

projected USE values were accurately calculated using the procedures in RG 1.99, Position 1.2, 

which is used for materials without credible surveillance data. For those reactor vessel beltline 

materials represented in the Reactor Vessel Materials Surveillance Program, (Lower Shell Plate 

R2708-1 and all beltline shell welds), LRA Table 4.2-3 also lists 54 EFPY values that were 

calculated using the procedures in RG 1.99, Position 2.2. The staff also confirmed the accuracy 

of these calculations and noted that the 54 EFPY USE values for the surveillance materials, 
TIME-LIMITED AGING ANALYSES

4-14

based on Position 2.2 of RG 1.99, exceed those calculated using Position 1.2, thereby 

demonstrating additional conservatism in the RG 1.99, Position 1.2 calculation.

The following inputs are required to project EOLE USE using the methods specified in RG 1.99, 

Position 1.2: neutron fluence at a location corresponding to one-quarter of the RV wall 

thickness from the RV clad/base metal interface (heretofore referred to as the 1/4T location); the 

material’s percentage copper (Cu) content by weight; and the unirradiated (initial) USE value for 

the material. The staff confirmed that 54 EFPY fluence values at the 1/4T location were 

appropriately used for the EOLE USE calculations. The staff confirmed that the initial USE 

values and the weight percentage Cu content listed in LRA Table 4.2-3 for the RV beltline 

materials are consistent with those listed in the staff’s reactor vessel integrity database (RVID) 

and in previously docketed correspondence. For the extended beltline materials [i.e., those 

materials projected to exceed the 1 x 1017 n/cm2 (E greater than 1.0 MeV) neutron fluence 

threshold during the period of extended operation] the staff found no documentation of the initial 

USE values and Cu contents in the RVID or in previously docketed correspondence. 

Furthermore, the LRA did not include any information regarding the heat (defined as a 

production run of homogeneous metal from a period of continuous melting in a cupola or 

furnace), nor the material specification or weld type, for any of the extended beltline 

components. Therefore, to obtain reasonable assurance concerning the identification of the 

extended beltline components and their associated material properties, by letter dated 

June 22, 2012, the staff issued RAIs 4.2.2-1 requesting that the applicant provide this 

information for the extended beltline materials.

In RAI 4.2.2-1, Part (a), the staff requested that the applicant identify the material specifications 

for the reactor vessel nozzle shell plates and the inlet and outlet nozzle forgings, based on the 

ASME Code Section II standards. In its RAI response, dated July 20, 2012, the applicant stated 

that the nozzle shell plates are SA-533B, Class 1 plate material, and the inlet and outlet nozzle 

forgings are SA-508 Class 2 forging material. The staff found the applicant’s response to 

RAI 4.2.2-1, Part (a), acceptable because the applicant identified the appropriate ASME Code 

Section II, material specification for the reactor vessel nozzle shell plates and inlet/outlet nozzle 

forgings. Therefore, the staff’s concern described in RAI 4.2.2-1, Part (a), is resolved.

In RAI 4.2.2-1, Part (b), the staff requested that the applicant identify the weld fabrication 

method and flux type for the nozzle-shell-to-intermediate-shell weld and the inlet and outlet 

nozzle-to-shell welds. In its RAI response, dated July 20, 2012, the applicant provided a table 

identifying the weld fabrication method and flux type for all extended beltline welds, which 

includes the nozzle shell-to-intermediate-shell welds, the inlet and outlet nozzle-to-shell welds, 

as well as the nozzle shell longitudinal welds. According to the applicant, all extended beltline 

welds were fabricated by either the shielded metal arc welding (SMAW) or the submerged arc 

welding (SAW) process. Flux types (Linde 0091 or Linde 124) were listed for all 

SAW-fabricated welds. For the SMAW-fabricated welds, a welding flux is not used because this 

process uses a coated electrode to create an inert environment to protect the weld from 

impurities during fabrication. The staff found the applicant’s response to RAI 4.2.2-1, Part (b) 

acceptable because the applicant appropriately identified the weld fabrication method and flux 

type for all extended beltline welds. Therefore, the staff’s concern described in RAI 4.2.2-1, 

Part (b), is resolved.

In RAI 4.2.2-1, Part (c), the staff requested that the applicant identify: (i) the heat numbers for 

all extended beltline plates and forgings, and the weld wire heat number and flux lot number for 

all extended beltline welds; and (ii) the source of the initial USE and Cu content data listed in 

LRA Table 4.2-3. If the initial USE and Cu content data are not based on measured 
TIME-LIMITED AGING ANALYSES

4-15

heat-specific values from certified material test reports (CMTRs), the staff requested that the 

applicant provide justification for using these values. In its RAI response, dated July 20, 2012, 

the applicant provided a table identifying the heat numbers for all extended beltline materials, 

including plates, forgings, and weld wires. For the SAW-fabricated welds, the applicant included 

the welding flux lot numbers. The applicant noted that each individual extended beltline weld 

component identified in the LRA is fabricated from multiple heat numbers of weld wire with 

differing USE values and Cu contents. The applicant stated that for each extended beltline 

weld, the most limiting values for the initial USE and Cu content are chosen for the EOLE USE 

calculation in LRA Table 4.2-3. Regarding the source of the initial USE values, the applicant 

stated that, with the exception of the Linde 0091 welds of Heat No. 4P7656 (Flux Lot No. 1054), 

the initial USE values listed in LRA Table 4.2-3 for all reactor vessel extended beltline materials 

are based on heat-specific CMTRs. The applicant stated that the Linde 0091 welds of Heat No. 

4P7656 (Flux Lot No. 1054) used a generic initial USE value of 101 ft-lbs that is based on 

CEN-622-A Final Report, “Generic Upper Shelf Values for Linde 1092, 124, and 0091 Reactor 

Vessel Welds, CEOG Task 839,” June 30, 1995 (ADAMS Legacy Library Accession 

No. 9508020111). The staff confirmed that the NRC-approved CEN-622-A report provides a 

conservative statistical basis for the generic initial USE value of 101 ft-lbs for the Linde 0091 

welds of heat No. 4P7656 (Flux Lot No. 1054), and therefore 101 ft-lbs is an acceptable generic 

initial USE for these particular welds. Accordingly, the staff determined that the applicant 

adequately identified the basis for the extended beltline material initial USE values listed in LRA 

Table 4.2-3. The staff’s concern described in RAI 4.2.2-1, Part (c), is resolved.

Regarding the source of the Cu content data, the applicant stated that, with the exception of the 

inlet and outlet nozzle forgings, the Cu content values listed in LRA Table 4.2-3 for all extended 

beltline materials are based on heat-specific CMTRs. The applicant stated that the CMTRs for 

the inlet and outlet nozzles did not contain measurements of Cu content because it was not 

required. Instead, the applicant invoked a generic Cu content of 0.16 percent for all inlet and 

outlet nozzle forgings — eight nozzle forgings total. The applicant stated that the 0.16 percent 

Cu content was taken from the analysis of chemistry measurements made for archived PWR 

surveillance capsule materials. The applicant indicated that the chemistry measurements for 

SA-508, Class 2, forgings are provided in Oak Ridge National Laboratory (ORNL) Report 

ORNL/TM-2006/530, “A Physically Based Correlation of Irradiation-Induced Transition 

Temperature Shifts for RPV Steels,” dated November 30, 2007. 

To determine if these chemistry measurements were analyzed properly to arrive at the generic 

Cu content of 0.16 percent, by letter dated September 12, 2012, the staff issued RAI 4.2.2-1a, 

requesting that the applicant provide additional justification based on statistical analysis for the 

selection of a 0.16 percent Cu content for the SA-508, Class 2, inlet and outlet nozzles. By 

letter dated October 15, 2012, the applicant provided its response to RAI 4.2.2-1a. In its RAI 

response, the applicant stated that ORNL Report ORNL/TM-2006/530 provides the mean, 

standard deviation (σ), minimum, and maximum Cu values for the SA-508, Class 2, forging data 

analyzed in the report. The applicant noted that the mean value for the Cu content is 

0.1220 percent, with a σ of 0.0313 percent, resulting in a mean + 2σ upper bound value of 

0.1846 percent. The applicant stated that the USE and PTS calculations for the reactor vessel 

inlet and outlet nozzles are revised to incorporate the 0.1846 percent Cu content for these 

nozzle forgings. The staff finds the applicant’s response to RAI 4.2.2-1a acceptable because 

the applicant invoked the mean + 2σ upper bound value for establishing the 0.1846 percent 

generic Cu content for its inlet and outlet nozzles forgings. The staff noted that the generic Cu 

content of 0.1846 percent is a statistically conservative value that is consistent with statistical 

analyses performed on industry-wide data. The applicant’s response also included LRA 

Amendment 12, which revised LRA Tables 4.2-3 and 4.2-4 to include revised USE and RTPTS
TIME-LIMITED AGING ANALYSES

4-16

calculations for the reactor vessel inlet and outlet nozzles based on the revised generic Cu 

content value of 0.1846 percent for SA-508, Class 2 nozzle forgings. The staff noted that the 

EOLE USE values for these nozzles, based on the revised Cu content, remain significantly 

greater than the EOLE 50 ft-lb threshold specified in 10 CFR Part 50, Appendix G. Therefore, 

the staff’s concern described in RAI 4.2.2-1a is resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that 

the analysis of Charpy USE for the reactor vessel beltline and extended beltline components 

has been projected to the end of the period of extended operation. Additionally, the staff finds 

that the applicant’s analysis of Charpy USE meets the acceptance criteria in SRP-LR 

Section 4.2.2.1.1.2 because the Charpy USE values for the reactor vessel beltline and extended 

beltline components have been appropriately evaluated for the period of extended operation 

and found to remain in compliance with 10 CFR Part 50, Appendix G.

4.2.2.3 FSAR Supplement

LRA Section A3.1.2 provides the FSAR supplement summarizing the Charpy USE TLAA. The 

staff reviewed LRA Section A3.1.2 consistent with the review procedures in SRP-LR 

Section 4.2.3.2, which state that the FSAR supplement is reviewed to verify that the applicant 

has provided an appropriate summary description of the evaluation of the reactor vessel neutron 

embrittlement TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.2.2.2 and is therefore acceptable. Additionally, the staff finds that the 

applicant provided an adequate summary description of its actions to address Charpy USE for 

the period of extended operation, as required by 10 CFR 54.21(d).

4.2.2.4 Conclusion

On the basis of its review, the staff concludes that, the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(ii), that the analysis of Charpy USE for 

the reactor vessel beltline and extended beltline components has been projected to the end of 

the period of extended operation. The staff also concludes that the FSAR supplement contains 

an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.3 Pressurized Thermal Shock

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3 describes the applicant’s TLAA for PTS. The applicant stated that the CLB 

RTPTS assessment is based on a 35 EFPY operating life and is documented in FSAR 

Table 5.3-9 and the Callaway PTLR. The applicant stated that the surveillance specimen 

examination results are credible and show that the RTPTS values for the surveillance plate and 

weld materials are in good agreement with or less than the RG 1.99, Position 1.1 predictions, 

thereby demonstrating conservatism in the Position 1.1 predictions.

The applicant stated that the reactor vessel beltline and extended beltline materials were 

evaluated for PTS in WCAP-17168-NP. These RTPTS calculations are summarized in LRA 

Table 4.2-4. According to the applicant, the most limiting predicted RTPTS value for the period of 

extended operation is 49 °C (120 °F) for Lower Shell Plate R2708-3, based on the methods of 

RG 1.99, Position 1.1. The applicant stated that the RTPTS values for all beltline and extended 

beltline materials meet the PTS screening criteria of 10 CFR 50.61.
TIME-LIMITED AGING ANALYSES

4-17

The applicant dispositioned the TLAA for PTS in accordance with 10 CFR 54.21(c)(1)(ii), that 

the PTS analysis has been projected to the end of the period of extended operation.

4.2.3.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for PTS and the corresponding disposition of 

10 CFR 54.21(c)(1)(ii), consistent with the review procedures in SRP-LR Section 4.2.3.1.2.2, 

which state that the documented results of the revised PTS analysis based on the projected 

neutron fluence at the end of the period of extended operation are reviewed for compliance with 

10 CFR 50.61.

10 CFR 50.61 requires that PWR facilities have projected values of RTPTS that are accepted by 

the staff for each reactor vessel beltline material. The RTPTS assessment shall follow the 

calculation procedures specified in 10 CFR 50.61(c), which are the same as the methods 

described in RG 1.99 for calculating the adjusted RTNDT. RTPTS calculations account for the 

effects of neutron embrittlement; to verify that the calculations provide values that are bounding 

for each reactor vessel material, applicant’s shall consider plant-specific information that could 

affect the level of embrittlement, such as the reactor vessel operating temperature and any 

related reactor vessel surveillance capsule data, including data from the applicant’s 

implementation of its Reactor Vessel Materials Surveillance Program. Regulations in 

10 CFR 50.61 define the RTPTS as the RTNDT evaluated for the EOL (or EOLE) neutron fluence 

at the clad/base metal interface for the reactor vessel beltline materials. RTPTS values for 

reactor vessel beltline materials shall not exceed the screening criteria specified in 

10 CFR 50.61(b)(2), except as provided in 10 CFR 50.61(b)(3) – (b)(7). The PTS screening 

criteria are 132 °C (270 °F) for reactor vessel plates, forgings, and axial welds, and 149 °C 

(300 °F) for circumferential welds.

The staff reviewed the applicant’s RTPTS calculations for the period of extended operation 

against the screening criteria in 10 CFR 50.61(b)(2). The staff used the applicant’s 60-year 

projected neutron fluence values for the reactor vessel beltline and extended beltline materials 

from LRA Tables 4.2-1 and 4.2-2 as the basis for determining if the reactor vessel beltline 

materials would have acceptable RTPTS values for the period of extended operation. 

LRA Table 4.2-4 lists 54 EFPY RTPTS values for all reactor vessel beltline and extended beltline 

materials, including the input data used in the calculations. All 54 EFPY RTPTS values are 

projected to remain less than the applicable screening criteria of 10 CFR 50.61(b)(2). The 

limiting (highest) 54 EFPY RTPTS value listed in LRA Table 4.2-4 is 49 °C (120 °F) for Lower 

Shell Plate R2708-3, based on the methods specified in 10 CFR 50.61(c)(1) (equivalent to the 

procedures in RG 1.99, Position 1.1), which is used for materials without credible surveillance 

data. The staff confirmed that all 54 EFPY RTPTS values are correctly calculated using the 

methods specified in 10 CFR 50.61(c)(1). For those reactor vessel beltline materials 

represented in the Reactor Vessel Materials Surveillance Program, (Lower Shell Plate R2708-1 

and all beltline shell welds), LRA Table 4.2-4 also lists 54 EFPY values that are calculated using 

the procedures in 50.61(c)(2) (equivalent to the procedures in RG 1.99, Position 2.1). The staff 

also confirmed the accuracy of these calculations and noted that the 54 EFPY RTPTS value for 

Lower Shell Plate R2708-1 of 38 °C (100 °F), based on Position 2.1 of RG 1.99, is significantly 

less than that calculated using Position 1.1, thereby demonstrating conservatism in the Position 

1.1 calculation.

The following inputs are required to project RTPTS using the methods specified in RG 1.99, 

Position 1.1: EOLE (54 EFPY) neutron fluence at the reactor vessel clad/base metal interface, 

the material’s weight percentage Cu and Ni content, the unirradiated (initial) RTNDT value for the 
TIME-LIMITED AGING ANALYSES

4-18

material, and the margin term. The staff confirmed that 54 EFPY fluence values at the 

clad/base metal interface of the RV wall were appropriately used for the RTPTS calculations. The 

staff confirmed that the initial RTNDT values and the Cu and Ni contents listed in LRA Table 4.2-4 

for the RV beltline materials are consistent with those listed in the staff’s RVID and in previously 

docketed correspondence regarding P-T limit curves. Calculated margin term values for the 

RV beltline materials also were found to be consistent with previously docketed correspondence 

and RG 1.99. For the extended beltline materials (i.e., those materials projected to exceed the 

1 x 1017 n/cm2 (E greater than 1.0 MeV) neutron fluence threshold during the period of extended 

operation), the staff found no documentation of the initial RTNDT values and Cu and Ni contents. 

Therefore, by letter dated June 22, 2012, the staff issued RAI 4.2.3-1 requesting that the 

applicant identify the source of the initial RTNDT and Nickel (Ni) content data for all extended 

beltline materials. The issue of the Cu content data for the extended beltline materials was 

previously addressed in RAIs 4.2.2-1 and.4.2.2-1a which are discussed in SER Section 4.2.2.2. 

In the RAI, the staff noted that, if the initial RTNDT and Ni content data are not based on 

measured heat-specific values from CMTRs, then the applicant should provide justification for 

using these values.

In its RAI response, dated July 20, 2012, the applicant stated that the initial RTNDT and 

Ni content for all extended beltline materials are based on heat-specific CMTRs. The applicant 

noted that each individual extended beltline weld component identified in the LRA is fabricated 

from multiple heat numbers of weld wire with differing initial RTNDT values and Cu and Ni 

contents. The applicant stated that for each extended beltline weld, the most limiting value for 

the initial RTNDT is chosen for the RTPTS calculation in LRA Table 4.2-4. To account for varying 

chemical content of the weld heats, the applicant stated that for each extended beltline weld, a 

chemistry factor (CF) is calculated for each heat based on the measured Cu and Ni content 

using the procedures in RG 1.99, Position 1.1, and the most limiting CF of all the weld’s heats is 

used for the RTPTS calculation for the weld in LRA Table 4.2-4. 

The staff found the applicant’s RAI response acceptable because the applicant confirmed that 

the initial RTNDT and Ni content for all extended beltline materials are based on heat-specific 

CMTRs. Furthermore, based on its review of the RAI response, the staff determined that the 

extended beltline weld RTPTS values listed in LRA Table 4.2-4 were calculated using the most 

limiting initial RTNDT and CF values for the various weld wire heads from which the welds were 

fabricated. Therefore, the staff’s concern described in RAI 4.2.3-1 is resolved.

As discussed in SER Section 4.2.2.2, the applicant has revised the generic Cu content for the 

inlet and outlet nozzle forgings from 0.16 percent to the statistically determined value of 

0.1846 percent. LRA Amendment 12 revised LRA Tables 4.2-3 and 4.2-4 to include revised 

USE and RTPTS calculations for the RV inlet and outlet nozzles based on this revised Cu 

content. The staff noted that the 54 EFPY RTPTS values for these nozzles, based on the revised 

Cu content, remain significantly less than the RTPTS screening criterion of 132 °C (270 °F)

specified in 10 CFR 50.61(b). 

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that 

the analysis of RTPTS for the reactor vessel beltline and extended beltline components has been 

projected to the end of the period of extended operation. Additionally, the staff finds that the 

applicant’s PTS analysis meets the acceptance criteria in SRP-LR Section 4.2.2.1.2.2 because 

the RTPTS values for the RV beltline and extended beltline components have been evaluated for 

the period of extended operation and found to remain in compliance with 10 CFR 50.61.
TIME-LIMITED AGING ANALYSES

4-19

4.2.3.3 FSAR Supplement

LRA Section A3.1.3 provides the FSAR supplement summarizing the PTS TLAA. The staff 

reviewed LRA Section A3.1.3 consistent with the review procedures in SRP-LR Section 4.2.3.2, 

which state that the FSAR supplement is reviewed to verify that the applicant has provided an 

appropriate summary description of the evaluation of the reactor vessel neutron embrittlement 

TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.2.2.2 and is therefore acceptable. Additionally, the staff finds that the 

applicant provided an adequate summary description of its actions to address PTS for the 

period of extended operation, as required by 10 CFR 54.21(d).

4.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(ii), that the analysis of PTS for the 

reactor vessel beltline and extended beltline components has been projected to the end of the 

period of extended operation. The staff also concludes that the FSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.2.4 Pressure-Temperature (P-T) Limits

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 describes the applicant's TLAA for the P-T limits. The applicant stated that 

the methods used to develop the Callaway P-T limit curves are based on the adjusted RTNDT

value for the limiting reactor vessel beltline material. The applicant also stated that withdrawal 

and testing of the surveillance specimens verifies that the limiting adjusted RTNDT value used for 

calculating the P-T limit curves bounds the aging of the reactor vessel beltline materials. 

Adjusted RTNDT values for the reactor vessel beltline materials are listed in the Callaway PTLR.

The applicant stated that the current P-T limit curves and adjusted RTNDT values are valid up to 

28 EFPY, based on a peak clad/base metal interface neutron fluence of 1.625 x 1019 n/cm2

(E greater than 1.0 MeV), as determined from the analysis of Capsule X in WCAP-15400-NP. 

The applicant also stated that the current P-T limit curves are calculated based on adjusted 

RTNDT values of 53 °C (128 °F) at the 1/4T location and 44 °C (112 °F) at three-quarters of the 

RV wall thickness from the RV clad/base metal interface (heretofore referred to as the 3/4T 

location) for the limiting beltline material, Lower Shell Plate R2708-1. According to the 

applicant, the current P-T limit curves were generated based on the methodologies of the 

ASME Code Section XI, Appendix G and WCAP-14040-A, Revision 4. The applicant further 

stated that the P-T limit curves are required to be maintained and updated as necessary by the 

administrative controls in Callaway Technical Specifications (TS), Section 5.6.6, and that it will 

revise the P-T limit curves before reaching 28 EFPY. 

The applicant dispositioned the TLAA for the P-T limits in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of neutron embrittlement on the P-T limits will be 

adequately managed by the TS 5.6.6 administrative controls for the period of extended 

operation.
TIME-LIMITED AGING ANALYSES

4-20

4.2.4.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the P-T limits and the corresponding disposition of 

10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR Section 4.2.3.1.3.3, 

which state that updated P-T limits for the period of extended operation must be available 

before entering the period of extended operation. SRP-LR Section 4.2.3.1.3.3 also states that 

either the 10 CFR 50.90 process for P-T limits located in the TS limiting conditions of operation 

(LCOs) or the TS administrative controls process for P-T limits contained in PTLRs can be 

considered adequate aging management programs (AMPs) within the scope of 

10 CFR 54.21(c)(1)(iii), such that P-T limits will be appropriately maintained through the period 

of extended operation.

10 CFR Part 50, Appendix G, provides fracture toughness requirements for ferritic materials in 

the RCPB, including requirements for calculating the RCS P-T limits. Section IV.A.2 of 

10 CFR Part 50, Appendix G, requires that P-T limits be at least as conservative as those 

determined in accordance with the ASME Code Section XI, Appendix G. The P-T limits shall 

also incorporate a 22 °C (40 °F) temperature adjustment above the ASME Code Section XI, 

Appendix G, limits for core criticality and incorporate the minimum temperature requirements, as 

specified in 10 CFR Part 50, Appendix G, Table 1. Additionally, 10 CFR Part 50, Appendix G,

requires that the P-T limit calculations account for the effects of neutron irradiation on the 

properties of the reactor vessel beltline materials and that these calculations incorporate 

relevant reactor vessel surveillance capsule data. Since the adjusted RTNDT values for reactor 

vessel beltline beltline materials increase as a function of neutron fluence, which changes with 

time, the P-T limits must be periodically updated to ensure that they bound the plant’s operating 

conditions.

The current Callaway P-T limits, valid through 28 EFPY, are established in Revision 5 of the 

Callaway PTLR, which was submitted to the staff by letter dated January 5, 2007. The content 

of the Callaway PTLR is administratively controlled in accordance with Callaway TS 5.6.6. TS 

5.6.6a specifies that P-T limits, including heatup and cooldown rates, shall be established and 

documented in the PTLR for heatup and cooldown operations, low-temperature conditions, core 

criticality, and hydrostatic testing, for operation of the RCS in accordance with TS LCO 3.4.3. 

LCO 3.4.3 specifies that RCS pressure, temperature, and heatup and cooldown rates shall be 

maintained within the limits specified in the PTLR at all times. TS 5.6.6b specifies the analytical 

methods used to calculate the P-T limits and the LTOP system setpoints contained in the PTLR 

— specifically the staff-approved methods of WCAP-14040-A, Revision 4. TS 5.6.6c requires 

that the PTLR be provided to the staff upon issuance for each reactor vessel neutron fluence 

period and for any revision or supplement thereto, thereby meeting the acceptance criterion 

from SRP-LR Section 4.2.2.1.3.3. SRP-LR Section 4.2.2.1.3.3 allows the P-T limits to be 

managed by the TS administrative controls process for P-T limits contained in PTLRs. The 

applicant will update the PTLR for new neutron fluence limits before operating beyond the 

current period. 

Table 5.0-5 of the Callaway PTLR lists 28 EFPY adjusted RTNDT values at the 1/4T and 3/4T 

locations for all reactor vessel materials that were established as beltline materials for the 

current licensing basis. This list does not include those components designated in the LRA as 

extended beltline materials. The staff found that the 28 EFPY P-T limits are calculated based 

on the adjusted RTNDT values for the limiting reactor vessel beltline material. Table 5.0-6 of the 

Callaway PTLR shows the detailed adjusted RTNDT calculations for the limiting beltline material, 

based on the methods of RG 1.99, Position 1.1. For the current PTLR, the staff noted that the 
TIME-LIMITED AGING ANALYSES

4-21

applicant conservatively selected Position 1.1 for calculating the limiting adjusted RTNDT values 

even though the RG 1.99, Position 2 values for this material are significantly less.

The staff noted that the current Callaway PTLR (Revision 5) documents CF calculations based 

on the application of surveillance data from capsules “U,” “Y,” “V,” and “X” using the methods in 

RG 1.99, Position 2.1. Section 4.0 of the Callaway PTLR states that all of the measured shifts 

in the RTNDT for the surveillance plate and weld materials are deemed credible based on the 

RG 1.99 surveillance data credibility assessment.

By letter dated July 9, 2012, the staff issued RAI 4.2.4-1, requests (a), (b), (c), and (d). The 

applicant responded to RAI 4.2.4-1 by letter dated August 9, 2012. A discussion of each 

RAI 4.2.4-1 request and the applicant’s response follows.

In RAI 4.2.4-1, Part (a), the staff requested that the applicant confirm whether surveillance 

Capsule “X” was the last capsule pulled from the Callaway reactor vessel. In its response, the 

applicant stated that Capsule X was the last surveillance capsule removed from the reactor 

vessel and tested. The staff found the applicant's response acceptable because the applicant 

confirmed that Capsule X was the last capsule tested. Therefore, the staff’s concern described 

in RAI 4.2.4-1, Part (a), is resolved.

The staff noted that Table 5.0-2 of the Callaway PTLR lists the RG 1.99, Position 2.1 CF for the 

surveillance plate as 13.9 °C (25 °F) and the adjusted CF for the surveillance weld as 22.2 °C

(39.9 °F). However, LRA Table 4.2-4 of the Callaway LRA lists a Position 2.1 CF of 14.2 °C

(25.6 °F) for the surveillance plate and 22.7 °C (40.8 °F) for the surveillance weld. Therefore, in 

RAI 4.2.4-1, Part (b), the staff requested that the applicant explain this discrepancy. In its 

response the applicant stated that the PTLR CFs for the surveillance materials were calculated 

using the results of the Capsule X analysis, which is documented in WCAP-15400-NP, whereas 

the LRA CFs were calculated in WCAP-17168-NP. The WCAP-17168 analysis was performed 

in support of the 54 EFPY USE and RTPTS calculations listed in LRA Table 4.2-3 and 4.2-4. 

According to the applicant, WCAP-17168 developed a new neutron fluence model, which 

incorporates operational information for the period after Capsule X was pulled. The applicant 

also stated that the source of the discrepancy between the LRA and PTLR CFs is the calculated 

fluence values that support the Position 2.1 CFs. The small difference in surveillance material 

CF values documented in the PTLR and the LRA can be attributed to the difference between 

the neutron fluence models used for each CF calculation. The applicant further stated that both 

neutron fluence models meet the criteria of RG 1.190 with uncertainty falling within the 

20 percent limit specified in the RG. The applicant stated that both neutron fluence models are 

DORT calculations using the BUGLE 96 cross section library, which is consistent with neutron 

fluence methodology described in WCAP-14040-A, Revision 4.

The applicant's response to RAI 4.2.4-1, Part (b), also included a table comparing the calculated 

surveillance capsule fluence values, as determined from the two models. The staff noted that 

the difference between the two sets of calculated fluence values and the resulting CF values is 

minor and has no impact on the P-T limit curves for the beltline shell region of the reactor vessel

because other materials have higher RTNDT values and thus control the P-T limit curves. The 

staff found the applicant's response acceptable because the applicant provided an adequate 

explanation for the discrepancy between the surveillance material CF values listed in the PTLR 

and the LRA, and the staff agreed with the applicant's explanation that this discrepancy is 

attributable to minor differences in the fluence inputs used for the CF calculations. The staff 

found that credible surveillance data was correctly applied for determining the CF values and 

28 EFPY adjusted RTNDT values for the reactor vessel plate and weld materials represented in 
TIME-LIMITED AGING ANALYSES

4-22

the Reactor Vessel Materials Surveillance Program. In addition, the staff finds that, since the 

surveillance material CFs listed in LRA Table 4.2-4 were calculated using neutron fluence 

valves that incorporate more recent core operating conditions and the values are (slightly) 

conservative relative to those from the PTLR, the CFs listed in LRA Table 4.2-4 are acceptable. 

The staff’s concern described in RAI 4.2.4-2, Part (b), is resolved.

In RAI 4.2.4-1, Part (c), the staff requested that the applicant identify the calendar year when the 

current 28 EFPY P-T limit curves are projected to expire. In its response the applicant stated 

that, as of October 2011, Callaway has experienced 23 EFPY of facility operation. The 

applicant also stated that Callaway will reach 28 EFPY in April 2017, assuming a plant capacity 

factor of 90 percent. The staff found the applicant's response acceptable because the applicant 

identified the calendar year (2017) when the 28 EFPY P-T limits are projected to expire. The 

staff notes that the TS 5.6.6 require that new P-T limits be established in the PTLR and 

submitted to the staff before operating beyond this neutron fluence period. Therefore, the staff’s 

concern described in RAI 4.2.4-1, Part (c), is resolved.

10 CFR Part 50, Appendix G, Paragraph IV.A states that:

[T]he pressure-retaining components of the reactor coolant pressure boundary 

[RCPB] that are made of ferritic materials must meet the requirements of the 

American Society of Mechanical Engineers Boiler and Pressure Vessel Code 

[ASME Code, Section III], supplemented by the additional requirements set forth 

in [paragraph IV.A.2, “Pressure-Temperature (P-T) Limits and Minimum 

Temperature Requirements"]...”

Wording provided prior to RAI 4.2.4-1, Part (d), states the following:

[...] 10 CFR Part 50, Appendix G, requires that P-T limits be developed for the 

ferritic materials in the RV beltline (neutron fluence greater than or equal to

1 x 1017 n/cm2

, E greater than 1 MeV), as well as ferritic materials not in the 

reactor vessel beltline (neutron fluence less than 1 x 1017 n/cm2

, E greater than

1 MeV). Further, 10 CFR Part 50, Appendix G, requires that all RCPB 

components must meet the ASME Code Section III, requirements. The relevant 

ASME Code Section III requirement that will affect the P-T limits is the lowest 

service temperature requirement for all RCPB components specified in 

Section III, NB-2332(b).

The current Callaway PTLR and the PTLR methodology described in 

WCAP-14040-A, Revision 4, address P-T limit curve calculations for only the 

reactor vessel beltline shell region. P-T limit calculations for ferritic RCPB 

components that are not reactor vessel beltline shell materials may define P-T 

curves that are more limiting than those calculated for the reactor vessel beltline 

shell materials. This may be because of the following factors:

i. Reactor vessel nozzles, penetrations, and other discontinuities have 

complex geometries that may exhibit significantly higher stresses than 

those for the RV beltline shell region. These higher stresses can 

potentially result in more restrictive P-T limits, even if the RTNDT for 

these components is not as high as that of RV beltline shell materials 

that have a simpler cylindrical geometry.

ii. Ferritic RCPB components that are not part of the reactor vessel may 

have initial RTNDT values, which may define a more restrictive lowest 
TIME-LIMITED AGING ANALYSES

4-23

operating temperature in the P -T limits than those for the reactor 

vessel beltline shell materials.

Therefore, in RAI 4.2.4-1, Part (d), the staff requested that the applicant describe how the P-T 

limit curves to be developed for use in the period of extended operation, and the methodology 

used to develop these curves, will consider all reactor vessel materials (beltline and 

non-beltline) and the lowest service temperature of all ferritic RCPB materials, consistent with 

the requirements of 10 CFR Part 50, Appendix G.

In its RAI response, the applicant stated that when the current P-T limits expire at 28 EFPY, 

new limits will be developed and submitted to the staff in accordance with TS 5.6.6 and 

10 CFR Part 50, Appendix G, requirements. The applicant also stated that future P-T limit 

curves will consider the effects of neutron embrittlement on the adjusted RTNDT for beltline and 

extended beltline components and the higher stresses in the inlet/outlet nozzle corner region. In 

addition, the applicant stated that the future P-T limit curves will also consider the effects of the 

ferritic RCPB components outside the reactor vessel beltline and extended-beltline regions 

when determining the lowest service temperature. In its response the applicant included LRA 

Amendment 6, which revised LRA Section 4.2.4 and the corresponding FSAR supplement 

section provided in LRA Section A3.1.4 to describe how future P-T limit curves will be 

developed in accordance with the requirements of 10 CFR Part 50, Appendix G, considering all 

ferritic RCPB components during the period of extended operation. 

The staff reviewed the applicant’s response to RAI 4.2.4-1, Part (d), including the relevant 

portions of LRA Amendment 6, and found the response acceptable because the applicant 

appropriately described how the P-T limit curves to be developed for use in the period of 

extended operation will consider all reactor vessel materials and the lowest service temperature 

of all ferritic RCPB materials, consistent with the requirements of 10 CFR Part 50, Appendix G. 

Specifically, the staff noted that LRA Amendment 6 revisions to LRA Sections 4.2.4 and A3.1.4 

ensure that future changes to the P-T limit curves beyond 28 EFPY will consider the following:

• the effects of neutron embrittlement on the adjusted RTNDT values for all reactor vessel 

locations projected to receive a neutron fluence greater than 1×1017 n/cm2 (E greater 

than 1.0 MeV)

• the higher stresses in the inside corner region of the reactor vessel inlet and outlet 

nozzles

• the ferritic RCPB components, which receive a neutron fluence of less than 

1×1017 n/cm2 (E greater than 1.0 MeV) when determining the lowest service temperature

Based on a review of the applicant’s FSAR, the staff determined that, other than the reactor 

vessel closure flange region, which is bounded by the minimum temperature requirements 

specified in Table 1 of 10 CFR Part 50, Appendix G, the reactor vessel inlet/outlet nozzles are 

the reactor vessel locations for which stress concentration effects are the most significant. 

Therefore, for the calculation of future P-T limit curves, the staff found that the above LRA 

revisions provide adequate assurance that future P-T limit curves will be developed such that 

they are bounding for all ferritic reactor vessel materials and the lowest service temperature of 

all ferritic RCPB materials, consistent with the requirements of 10 CFR Part 50, Appendix G. 

The staff’s concern described in RAI 4.2.4-1, Part (d) is resolved. 

For the reasons discussed above the staff’s concern described in RAI 4.2.4-1 is resolved.
TIME-LIMITED AGING ANALYSES

4-24

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of neutron embrittlement on the P-T limits will be adequately managed for the period 

of extended operation. Additionally, the staff finds that that the applicant’s P-T limits analysis 

meets the acceptance criteria in SRP-LR Section 4.2.2.1.3.3 because the applicant’s TS 5.6.6 

administrative controls for the PTLR ensure that updated P-T limits for the period of extended 

operation will be available before entering the period of extended operation. 

4.2.4.3 FSAR Supplement

LRA Section A3.1.4 provides the FSAR supplement summarizing the P-T limits TLAA, as 

revised in LRA Amendment 6. The staff reviewed amended LRA Section A3.1.4 consistent with 

the review procedures in SRP-LR Section 4.2.3.2, which state that the FSAR supplement is 

reviewed to verify that the applicant has provided an appropriate summary description of the 

evaluation of the reactor vessel neutron embrittlement TLAA.

Based on its review of the amended FSAR supplement, the staff finds it meets the acceptance 

criteria in SRP-LR Section 4.2.2.2 and is therefore acceptable. Additionally, the staff finds that 

the applicant provided an adequate summary description of its actions to address the P-T limits 

for the period of extended operation, as required by 10 CFR 54.21(d).

4.2.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of neutron 

embrittlement on the P-T limits will be adequately managed by the TS 5.6.6 PTLR 

administrative controls for the period of extended operation. The staff also concludes that the 

FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.2.5 Low-Temperature Overpressure Protection

4.2.5.1 Summary of Technical Information in the Application

LRA Section 4.2.5 describes the applicant's TLAA for LTOP. The applicant stated that LTOP at 

Callaway is required by TS 3.4.12 and TS 5.6.6, and is provided by the cold overpressure 

mitigation system (COMS), which opens the pressurizer PORVs at a setpoint calculated to 

prevent violation of the P-T limits. COMS setpoints are established in the PTLR.

The applicant stated that, since the COMS setpoints are based on the P-T limits, which are a 

TLAA, the COMS setpoints are also a TLAA, and these LTOP analyses do not depend on any 

other time-dependent values beyond the P-T limits and the adjusted RTNDT values at the critical 

locations. The applicant stated that changes to the RCS P-T limit curves also require an 

evaluation of the COMS enable temperature and PORV pressure setpoints, and supporting 

safety analyses, based on the methodology used to determine the COMS PORV setpoints, 

WCAP-14040-NP-A and ASME Code Case (CC) N-514, “Low Temperature Overpressure 

Protection, Section XI, Division 1.” The applicant also stated that the COMS setpoints are 

established in the PTLR and are managed consistent with the P-T limits.

The applicant dispositioned the TLAA for LTOP in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of neutron embrittlement on the COMS enable temperature and pressure setpoints 

will be adequately managed by the PTLR process (as established in TS 5.6.6 administrative 

controls) for the period of extended operation.
TIME-LIMITED AGING ANALYSES

4-25

4.2.5.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for LTOP and the corresponding disposition of 

10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR Section 4.2.3.1.3.3, 

which state that updated P-T limits for the period of extended operation must be available 

before entering the period of extended operation. SRP-LR Section 4.2.3.1.3.3 also states that 

either the 10 CFR 50.90 process for P-T limits located in the TS LCOs or the TS administrative 

controls process for P-T limits contained in PTLRs can be considered adequate AMPs within the 

scope of 10 CFR 54.21(c)(1)(iii), such that P-T limits will be appropriately maintained through 

the period of extended operation. The staff noted that, although SRP-LR Section 4.2.3.1.3.3 

explicitly addresses P-T limit TLAA reviews, this SRP-LR section is also the appropriate review 

standard for the LTOP TLAA, as discussed below. 

LTOP at Callaway is provided by the COMS. The COMS opens the pressurizer PORVs at a 

setpoint calculated to prevent violation of the P-T limits. At Callaway, P-T limits and COMS 

setpoints are established in the PTLR, and the COMS setpoints are based on the P-T limits. In 

LRA Section 4.2.5, the applicant proposed to manage the COMS setpoints using the PTLR 

process, which is administratively controlled in accordance with Callaway TS 5.6.6 

requirements. Therefore SRP-LR Section 4.2.3.1.3.3 is the appropriate review standard for the 

applicant’s LTOP TLAA because the applicant has proposed to manage the COMS setpoints for 

the period of extended operation in the same manner as the P-T limits. 

The PTLR process for Callaway, as established in TS 5.6.6, requires that the COMS setpoints 

be developed using the staff-approved methodology of WCAP-14040-A, Revision 4. 

TS LCO 3.4.12 specifies that the COMS shall be operable for the following modes of reactor 

operation:

• MODE 4 – hot shutdown, with any RCS loop cold leg temperature less than or equal to 

than 275 °F

• MODE 5 – cold shutdown

• MODE 6 – refueling, with the reactor vessel head installed 

LCO 3.4.12 requires that pressure relief capabilities be provided by the PORVs, within the 

COMS pressure setpoints, as established in the PTLR or alternatively, by two RHR system 

suction relief valves with lift setpoints greater than or equal to 436.5 psig and less than or equal 

to 463.5 psig. The RHR suction relief valve lift setpoints are established directly in LCO 3.4.12. 

The staff confirmed that the COMS PORV setpoints established in the current Callaway PTLR 

and the RHR suction relief valve lift setpoints in the LCO limit the pressure in the reactor vessel 

to less than the maximum pressure allowed by the current P-T limit curves. Future COMS 

setpoints will be developed using the methodologies of WCAP-14040-A, Revision 4, and ASME 

Code Case N-514 as stated in LRA Section 4.2.5. 

ASME Code Section XI Article G-2215, specifies pressure and temperature conditions for LTOP 

systems to ensure protection against RCPB failure during reactor startup and shutdown 

operations. Article G-2215 states that LTOP systems shall be effective at RCS temperatures 

less than 93 °C (200 °F) or at RCS temperatures corresponding to a reactor vessel metal 

temperature less than the limiting RTNDT value + [27.8 °C] 50 °F, whichever is greater. Based 

on the 54 EFPY adjusted RTNDT value for the limiting reactor vessel beltline material (49 °C or 

120 °F at the clad/base metal interface), the staff confirmed that the current COMS enable 
TIME-LIMITED AGING ANALYSES

4-26

temperature of 135 °C (275 °F) is bounded by the ASME Code Section XI requirements for 

LTOP enable temperatures. 

The staff noted that implementation of the WCAP-14040-A, Revision 4 methodology, as 

specified in TS 5.6.6, requires that changes to RCS P-T limits include an evaluation of the 

COMS enable temperature, PORV pressure setpoints, and supporting safety analyses. The 

staff noted that the methodology used to determine the COMS PORV setpoints conforms to 

WCAP-14040-A, Revision 4. 

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of neutron embrittlement on the plant’s LTOP capability will be adequately managed 

for the period of extended operation. Additionally, the staff finds that the applicant’s LTOP 

analysis meets the acceptance criteria in SRP-LR Section 4.2.2.1.3.3 because the applicant’s 

TS 5.6.6 administrative controls for the PTLR ensure that updated COMS setpoints for the 

period of extended operation will be available before entering the period of extended operation.

4.2.5.3 FSAR Supplement

LRA Section A3.1.5 provides the FSAR supplement summarizing the LTOP TLAA. The staff 

reviewed LRA Section A3.1.5 consistent with the review procedures in SRP-LR Section 4.2.3.2, 

which state that the FSAR supplement is reviewed to verify that the applicant has provided an 

appropriate summary description of the evaluation of the reactor vessel neutron embrittlement 

TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.2.2.2 and is therefore acceptable. Additionally, the staff finds that the 

applicant provided an adequate summary description of its actions to address the LTOP system 

for the period of extended operation, as required by 10 CFR 54.21(d). 

4.2.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of neutron 

embrittlement on the LTOP capability will be adequately managed by the TS 5.6.6 PTLR 

administrative controls for the period of extended operation. The staff also concludes that the 

FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.3 Metal Fatigue

4.3.1 Fatigue Monitoring Program

LRA Section 4.3.1 states that ASME III Class 1 design specifications define a set of static and 

transient load conditions for which components are to be designed. The fatigue analyses are 

based on a specified number of occurrences of each transient rather than the design or licensed 

life. 

The Fatigue Monitoring Program manages crack initiation caused by the specified transient 

conditions by periodically counting and evaluating transients consistent with GALL Report 

AMP X.M1 and is required by Callaway TS 5.5.5, “Component Cyclic or Transient Limit.” The 

program will require periodic reviews of the plant instrumentation and operator logs to ensure 

that the critical thermal and pressure transients have not exceeded the design transient severity 
TIME-LIMITED AGING ANALYSES

4-27

or analyzed number and to ensure that usage factors will not exceed the allowable value of 1.0 

without corrective actions. 

LRA Table 4.3-2, “Transient Accumulations and Projections,” lists the transients monitored by 

the Fatigue Monitoring Program, which were identified through a review of the design and 

licensing analyses. These identified transients will be reconciled with the transients identified in 

FSAR Table 3.9(N)-1 SP in accordance with 10 CFR 54.29.

4.3.1.1 Fatigue Monitoring Methods

4.3.1.1.1 Summary of Technical Information in the Application

LRA Section 4.3.1.1 states the Fatigue Monitoring Program will include both manual cycle 

counting of certain transients along with automatic cycle counting of selected transients using 

monitoring software. In addition, the program monitors transient pressure and thermal 

conditions to calculate the actual fatigue usage for specified fatigue critical locations. Monitored 

locations will include locations identified by the evaluation of ASME Code Section III fatigue 

analyses; the sample locations for a newer vintage Westinghouse plant listed in 

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

Power Plant Components,” February 1995; and plant-specific bounding 

environmentally-assisted fatigue (EAF) locations. The program also accounts for the effects of 

the reactor coolant environment on fatigue usage where applicable.

The program will track the occurrences of plant transients listed in LRA Table 4.3-2 using cycle 

counting, and monitors the cumulative usage factors (CUFs) at the components listed in LRA 

Table 4.3-1 using either cycle-based fatigue (CBF) or stress-based fatigue (SBF). The LRA 

provides the details of the CBF and SBF monitoring methods.

The LRA also describes the charging nozzle SBF benchmarking evaluation performed to 

address Regulatory Issue Summary (RIS) 2008-30. RIS 2008-30 discusses the staff concerns 

about the use of a single-stress term used in SBF algorithms and only recommends that it be 

demonstrated that the simplification of the use of less than the six-stress tensors produces a 

conservative result. Thus, the applicant performed a benchmark evaluation to demonstrate that 

the charging nozzle SBF algorithm produces a conservative CUF as compared to an 

independent ASME Code Section III, Division 1, Subsection NB, Subarticle NB- 3200 fatigue 

calculation of the same component. The LRA provided the details of the benchmarking 

performed for the charging nozzle SBF algorithm, which indicates that the bulk of the difference 

is due to the use of Green’s Functions (influence functions, based on constant material 

properties) and is not attributable to the use of a single stress term. Furthermore, the applicant 

determined that the concerns expressed by the staff in RIS 2008-30 are addressed and 

eliminated for the charging nozzles.

4.3.1.1.2 Staff Evaluation

LRA Section 4.3.1.1 discusses the monitoring methods of the Fatigue Monitoring Program that 

will be used to manage metal fatigue of various components discussed in LRA Section 4.3. The 

staff noted that the monitoring methods of the Fatigue Monitoring Program include cycle 

counting, cycle-based fatigue monitoring and stress-based fatigue monitoring. The staff’s 

evaluation of the acceptability of these monitoring methods to manage metal fatigue is 

documented in SER Section 3.0.3.2.22.
TIME-LIMITED AGING ANALYSES

4-28

LRA Section 4.3.1.1 states that a benchmark was performed to demonstrate that the charging 

nozzle SBF algorithm produces a conservative CUF when compared to an ASME Code 

Section III, Subarticle NB-3200 fatigue calculation of the same component. The benchmarking 

consisted of inputting the temperature, pressure, and flow rate time histories for the most severe 

transient pairs into the SBF algorithms. These time histories, which are the same as those 

assumed in the NB-3200 fatigue calculation, constitute about 88 percent of the NB-3200 CUF. 

The LRA states that a comparison demonstrated that the CUF for those transient pairs as 

computed by the SBF algorithms is more conservative than the CUF calculated with all transient 

pairs as computed using the detailed NB-3200 methodology. 

The staff noted that the LRA did not provide sufficient detail to support its statement that the 

single-stress component SBF is more conservative than the NB-3200 calculation. Since the 

LRA did not identify or compare the results between the single stress component SBF and 

NB-3200 calculations, the staff was not able to verify the adequacy of the applicant’s calculation 

to support the use of single stress component SBF for the charging nozzle.

By letter dated September 6, 2012, the staff issued RAI 4.3-8 requesting the applicant to identify 

those most severe transient pairs that “constitute about 88% of the NB-3200 CUF” and provide 

the associated CUF contribution for these pairs. In addition, the applicant was requested to 

identify the CUF contributions (both in SBF and NB-3200 calculations) for the two transients, 

described above. Finally the applicant was requested to justify that the results calculated from 

the single-stress component SBF is conservative compared to the NB-3200 for the charging 

nozzle.

In its response dated October 11, 2012, the applicant provided the transient pairs that 

“constitute about 88% of the NB-3200 CUF” of 0.164 for the charging nozzles and stated that it 

was the result of an elastic-plastic fatigue analysis performed to support license renewal. The 

applicant also provided the CUF contributions (both in SBF and NB-3200 calculations) for the 

two transients that the SBF algorithms calculated stress ranges approximately one to 

two percent less than the NB-3200 analysis. The staff noted that these two transient pairs were 

the “charging decrease/letdown increase” pair with a CUF contribution of 0.036 and “charging 

increase/ letdown increase” pair with a CUF contribution of 0.008. The applicant also explained 

that the SBF algorithm CUF was 0.172, which is approximately 5 percent more conservative 

than the NB-3200 CUF of 0.164. The staff noted that the overall results demonstrated that the 

applicant’s use of its SBF algorithm would produce a higher CUF value when compared to an 

NB-3200 analysis. The staff noted that a higher calculated CUF value is considered 

conservative because there is additional margin that was not removed from the calculation 

results. Based on the data and results provided in the RAI response, the staff was able to 

confirm that the CUF value calculated with the SBF algorithm for the charging nozzles are 

greater than the CUF value of an NB-3200 analysis. Thus, the staff finds the applicant’s 

response acceptable. The staff’s concern described in RAI 4.3-8 is resolved.

The staff noted that the applicant’s benchmark evaluation demonstrated that the issue identified 

in RIS 2008-30 is not applicable to its charging nozzle SBF calculation. Thus, the staff finds it 

reasonable that the applicant implement SBF monitoring for the charging nozzles as indicated in 

LRA Table 4.3-1. The staff noted that the SBF monitoring method computes a “real-time” stress 

history for a given component from data that is collected by plant instruments to calculate 

transient pressure and temperature, and the corresponding stress history at the critical location. 

The use of actual plant data, such as local pressure and thermal conditions, to calculate actual 

fatigue usage is consistent with the “parameters monitored/inspected” program element of 
TIME-LIMITED AGING ANALYSES

4-29

GALL Report AMP X.M1 for more “detailed monitoring.” The staff’s evaluation of the applicant’s 

Fatigue Monitoring Program is documented in the SER Section 3.0.3.2.22.

4.3.1.1.3 FSAR Supplement

LRA Sections A2.1 and A3.2 provide the FSAR supplement summarizing the applicant’s basis 

of its fatigue analyses and describing its Fatigue Monitoring Program to ensure that the 

numbers of transients actually experienced remain below the assumed number. The staff 

reviewed LRA Sections A2.1 and A3.2, consistent with the review procedures in SRP-LR 

Section 4.3.3.2. The procedures state that the reviewer should confirm that the applicant has 

provided information to be included in the FSAR supplement that includes a summary 

description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds that it meets the acceptance criteria 

in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the applicant provided an 

adequate summary description for its Fatigue Monitoring Program to monitor the numbers of 

transients actually experienced, as required by 10 CFR 54.21(d).

4.3.1.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an adequate 

description and acceptable basis for monitoring design transients and cycles with its Fatigue 

Monitoring Program. The program ensures that corrective actions are taken before exceeding 

the design limit during the period of extended operation. The staff also concludes that the 

FSAR supplement contains an appropriate summary description of the monitoring bases of 

transients and design cycles, as required by 10 CFR 54.21(d). 

4.3.1.2 Projected Status of Monitored Transients

4.3.1.2.1 Summary of Technical Information in the Application

Cycle Count Baselining. LRA Section 4.3.1.2 states that a review of the operating history was 

performed under a 10 CFR 50 Appendix B Program in order to baseline the transient event 

count in the Fatigue Monitoring Program from initial startup (1983) to January 31, 2011. The 

baseline was performed covering two periods of operation. For Period 1, which covers plant 

startup through May 10, 1995, the manual records of the current program were used to 

re-create the event history for the plant. For Period 2, which covers May 11, 1995 through 

January 31, 2011, fatigue monitoring software was used to review plant instrument data to 

identify transient occurrences. If the plant instrumentation was unavailable for Period 2, then 

the manual plant records were used.

Cycle Count Projection Method. LRA Section 4.3.1.2 states that the baseline cycle counting 

results were projected to a 60-year operating life based on the actual accumulation history since 

the start of plant life. The cycle projections are based on (1) a long-term rate of cycle 

accumulation, based on the entire history, and (2) a short-term rate of cycle accumulation. The 

LRA describes the cycle projection methodology and states that, by weighting the short-term 

operation more heavily than the long-term operation, more weight is given to the recent plant 

history in the future projection calculations. The assumption is that recent plant operating 

history is generally a better predictor of future plant operation than the early operating history. 

In addition, these projections are intended to be a best estimate of the actual cycles expected 

and do not represent a revision of the design basis. The purpose is to demonstrate that the 
TIME-LIMITED AGING ANALYSES

4-30

40-year design numbers of transients are reasonable for 60 years and future cycle count 

projections will be based on the actual accumulation history over the analysis period.

The projected cycle counts for 60 years of operation are provided in LRA Table 4.3-2.

4.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.2 to confirm that the transients that are significant fatigue 

contributors are monitored to ensure that the applicant’s fatigue evaluations remain valid and 

that the methodology for determining the baseline cycle counts is appropriate. The staff also 

reviewed the methodology used by the applicant to obtain the 60-year cycle projections. The 

staff’s evaluation of the applicant’s Fatigue Monitoring Program, which is used to cycle count 

these transients, is documented in the SER Section 3.0.3.2.22.

LRA Table 4.3-2 describes Transient 1b as “Plant Cooldown at 100 o

F/hr, Pressurizer Cooldown 

at 200 o

F/hr” and indicates that there were 29 occurrences of Transient 1b between 1983 and 

2011. FSAR Table 3.9(N)-1A SP indicates that the “plant cooldown cycle at less than 100 o

F/hr” 

is defined as “cooldown cycle Tave from ≥ 550 o

F to ≤ 200 oF” and that the “pressurizer cooldown 

cycle at less than 200 o

F/hr” is defined as “pressurizer cooldown cycle temperature from 

≥650 o

F to ≤ 200 oF.”

Based on these descriptions in the LRA and FSAR, it is not clear to the staff why the plant 

cooldown and pressurizer cooldown cycles are grouped together as a single transient 

(Transient 1b) in LRA Table 4.3-2 and whether the two components of Transient 1b should be 

considered separately based on the definition in the FSAR SP. 

By letter dated September 6, 2012, the staff issued RAI 4.3-1 requesting that the applicant 

provide the basis for combining these two transients when they are being monitored by the 

Fatigue Monitoring Program. In addition, with respect to the baseline value of 29 occurrences in 

LRA Table 4.3-2, the applicant was requested to clarify whether the two transients have been 

monitored separately or together since the beginning of power operations (considering that 

manual records and fatigue monitoring software have been used).

In its response dated October 11, 2012, the applicant clarified that the Fatigue Monitoring 

Program combined the monitoring of the plant cooldown and pressurizer cooldown. The staff 

noted that although the Fatigue Monitoring Program combined the monitoring of these two 

transients, the applicant confirmed that these transients are counted separately and the cycle 

count for plant cooldown, pressurizer cooldown, and Transient 1b increment by one cycle when 

the plant is shut down. The applicant confirmed that the number of plant cooldown and 

pressurizer cooldown transients were baselined separately since the beginning of power 

operation. 

The staff finds the applicant response acceptable because (1) since the plant cooldown and 

pressurizer cooldown transients are considered separately and counted independently, the staff 

finds it appropriate that the applicant performed baseline cycle counts of these two transient 

separately; and (2) based on the applicant’s clarifications, the staff finds that the Fatigue 

Monitoring Program is capable of cycle counting Transient 1b and ensuring that the number of 

actual occurrences of this transient does not exceed the number used in fatigue analyses; 

otherwise corrective actions will be taken. Therefore, the staff’s concern described in RAI 4.3-1 

is resolved.
TIME-LIMITED AGING ANALYSES

4-31

LRA Section 4.3.1.2 states the baseline cycle counting results were projected to a 60-year 

operating life based on the actual accumulation history since the start of plant life. In addition, a 

rate of future cycle accumulation is computed for each transient and the cycle projections are 

based on a long-term rate and a short-term rate of cycle accumulation. These accumulation 

rates are then combined based on a weighting factor of one for the long-term rate and three for 

the short–term rate. The staff noted that since the applicant used the 60-year transient 

projections to support the disposition of the TLAAs evaluated in LRA Sections 4.7.2 and 4.7.7, 

additional information is required to determine whether the long-term and short-term weighting 

factors and the associated transient occurrences for these weighting factors used in the 

projection methodology is appropriate and conservative.

By letter dated September 6, 2012, the staff issued RAI 4.3-2, Part (a), requesting the applicant 

to identify the transients in LRA Table 4.3-2 in which the long-term and short term weighting 

factors are applicable and provide the short-term and long-term occurrence rate for each 

transient. In addition, RAI 4.3-2, Part (b), the applicant was requested to describe and justify as 

conservative any “alternative” 60-year projection methodology, other than the one discussed in 

LRA Section 4.3.1.2.

In response to Part (a) to RAI 4.3-2, dated October 11, 2012, the applicant provided the 

short-term and long-term weighting factors. However, the applicant did not provide short-term 

and long-term occurrences (i.e., short-term average rate of accumulation and total average rate 

of accumulation, respectively) of each transient as requested in Part (a) of RAI 4.3-2.

By letter dated November 21, 2012, the staff issued RAI 4.3-2a requesting that the applicant 

provide the short-term average rate of accumulation and total average rate of accumulation for 

each transient listed in LRA Table 4.3-2 that supports the calculation of the 60-year projections. 

In its response to RAI 4.3-2a dated December 13, 2012, the applicant provided a table (Table 1) 

with the short-term average rate and total average rate of accumulation for each transient listed 

in LRA Table 4.3-2. The applicant stated there were differences between LRA Table 4.3-2 and 

the table provided in the RAI response; thus, in order to be consistent, LRA Table 4.3-2 was 

revised to be consistent with Table 1 of the RAI response. The applicant described the 

differences between the tables and stated that the changes did not affect any TLAA 

dispositions. The staff reviewed the revisions to LRA Table 4.3-2 and confirmed that the TLAA 

dispositions that rely on the 60-year projections (i.e. 10 CFR 54.21(c)(1)(i) and (ii)) in LRA 

Sections 4.3 and 4.7 were not affected. The staff also noted that the revisions do not affect the 

applicant’s ability to manage EAF calculations, which are based on the 60-year cycle 

projections, because the Fatigue Monitoring Program incorporates preemptive cycle action 

limits to initiate corrective actions. The staff’s review of these cycle count action limits are 

documented in SER Section 3.0.3.2.22.

The staff noted the projections for transients used in TLAAs discussed in LRA Sections 4.7.2 

and 4.7.7 do not exceed 50 percent of the design number of cycles. The staff also noted that 

there is margin between the design cycle limits and the expected number of cycles at 60 years 

to account for unanticipated transient occurrence. Therefore, the staff finds that this margin 

could be used to support a conclusion that these TLAAs could be dispositioned in accordance 

with 10 CFR 54.21(c)(1)(i). The staff’s evaluations of the TLAAs for in-service flaw analyses 

that demonstrate structural integrity for 40 years are documented in SER Section 4.7.2.2. In 

addition, the staff’s evaluations of the TLAAs for fatigue crack growth assessment in support of 

a fracture mechanics analysis for the LBB elimination of dynamic effects of piping failures are 

documented in SER Section 4.7.7.2.
TIME-LIMITED AGING ANALYSES

4-32

The staff reviewed Table 1 of the RAI response and noted that there is margin between the 

60-year projected cycles and the design cycle limit; thus, the staff determined that it is 

reasonable that the 60-year projections are not solely based on data from the entire history of 

plant operation because recent operating practices are expected to be more representative of 

how the plant will operate in the future. Furthermore, the staff finds the 60-year cycle 

projections reasonable because the Fatigue Monitoring Program ensures that actual plant 

experience will remain bounded by the thermal and pressure transient numbers and severities 

analyzed in the design calculations, or that corrective actions will implemented to maintain the 

design and license basis of the components.

The staff finds the applicant’s response to Part (a) to RAI 4.3-2 and RAI 4.3-2a acceptable 

because (1) the applicant provided the details of its 60-year projection methodology based on 

short-term and long-term operational history; (2) the projections provide a reasonable outlook at 

the number of cycles expected to occur after 60-years of operation, as described above; and (3) 

the applicant manages transient cycle counts with its Fatigue Monitoring Program to ensure 

design limits are not exceeded. The staff’s concerns described in Part (a) to RAI 4.3-2 and RAI 

4.3-2a are resolved.

In response to Part (b) to RAI 4.3-2, dated October 11, 2012, the applicant provided a list of 

transients that used an “alternative” 60-year projection methodology. The staff’s review of each 

“alternative” methodology is documented below.

The applicant stated that the 60-year projection is set equal to the baseline for "Normal 

Transient #13, Turbine roll test,” “Test Transient #1, Primary side hydrostatic test,” and “Test 

Transient #2, Secondary side hydrostatic test,” because these tests were performed during 

initial startup and no more tests are expected. The staff finds it reasonable that the 60-year 

projections were set equal to the baseline count because these are transients associated with 

the initial plant operation and are not associated with the normal, current, or future operation of 

the applicant’s site.

The applicant stated that the 60-year projection is set equal to the baseline for “Upset 

Transient #2, Loss of Power (with natural circulation in the RCS)” and “Upset Transient #8, 

Inadvertent safety injection actuation,” because this is the value analyzed in the EAF 

calculations and is further justified in LRA Section 4.3.4. The staff noted that LRA Section 4.3.4 

states that, even though the numbers of “inadvertent safety injection” and “loss of power” events 

to-date were used in fatigue analyses, the affected location is monitored with CBF. The staff 

finds acceptable that the 60-year projection is set equal to the baseline for these two transients 

because: (1) there is margin between the baseline cycle count and the design limiting value, 

and (2) the affected locations are managed with CBF that will determine, with each transient 

occurrence, the incremental contribution to the CUF and ensure that the design limit of 1.0 is not 

exceeded during the period of extended operation.

In its response, the applicant provided 10 upset transients, one test transient, and six auxiliary 

transients in which the projected number of events was set equal to one event because there 

have been no historical events recorded on which to base an accumulation rate. The staff finds 

it reasonable that these 17 transients were projected to occur once through the period of 

extended operation because after 27 years of operation there have been no recorded 

occurrences of these transients. In addition, there is margin between the baseline cycle count 

and the design limiting value, and the Fatigue Monitoring Program monitors these transients to 

ensure the design limit is not exceeded before corrective actions are taken to assess any 

impact.
TIME-LIMITED AGING ANALYSES

4-33

The applicant stated that for “Normal Transient #7a/b, Loop out of service, Normal loop 

shutdown/startup,” the 60-year projection is zero because its site is not licensed for N-1 loop 

operation. The staff reviewed the applicant’s FSAR SP and noted on page 450-17 that the site 

does not operate with a loop out of service. The staff finds it acceptable that this transient is not 

projected to occur because the applicant’s current licensing basis does not permit operation with 

a loop out of service.

The applicant stated that the maneuver associated with “Normal Transient #11, Reduced 

temperature return to power,” is not used because Callaway does not load follow. The staff 

finds it acceptable that this transient is not projected to occur since this transient is associated 

with load-following operation and the applicant operates its plant as base-loaded.

The applicant stated that for “Auxiliary Transient #28, Excess letdown heat exchanger 

operation,” the 60-year projection is based on a linear projection of the available data and is 

further explained in LRA Section 4.3.8. The staff’s evaluation of this projection is documented in 

SER Section 4.3.8.2. Based on the aforementioned evaluation of the applicant’s response 

regarding alternative 60-year projection methodologies, the staff concerns identified in Part (b) 

to RAI 4.3-2 are resolved.

LRA Table 4.3-2 describes that for Normal Transients 16a and 16b, the baseline results were 

judged to be conservative based on a review of instrumentation data available from 2000 to 

2011. However, it is not clear to the staff whether the baseline numbers of 56 and 12, for 

Normal Transients 16a and 16b, respectively, were the results of a review of instrumentation 

data available from 2000 to 2011 or whether they incorporated a backward-projection to include 

the years from 1983 to 2011. In addition, the applicant did not provide the technical basis for 

why using the data from 2000 to 2011 was conservative and whether the 1:3 ratio for long-term 

to short-term weighting factor was used to calculate the 60-year projection for this transient.

By letter dated September 6, 2012, the staff issued RAI 4.3-3, Part (a) requesting the applicant 

to provide the number of occurrences for Normal Transients 16a and 16b from 2000-2011 and 

the calculation performed to obtain the baseline values for 56 and 12 in LRA Table 4.3-2. The 

applicant was further requested to justify that the data from 2000-2011 is conservative to 

represent the occurrences of these transients between 1983 and 2011. In Part (b) of RAI 4.3-3, 

the applicant was requested to provide and justify the short-term and long-term weighting 

factors used to calculate the 60-year projection and the associated transient occurrences for 

these weighting factors.

In response to Part (a) to RAI 4.3-3 dated October 11, 2012, the applicant stated it experienced 

22 events of Normal Transient 16a, “Feedwater heaters out of service: One heater out of 

service,” between 2000 and 2011. In its response to Part (b) of RAI 4.3-3, the applicant stated 

that in the past 9 years there have been 12 events of Normal Transient 16a and that a weighting 

factor of 1 for the long term and 3 for the short term were used and that the short-term period 

consists of the preceding 9 years.

Based on the information provided, the staff noted that there were approximately 10 events of 

Normal Transient 16a that occurred from 2000 through 2002. Since LRA Table 4.3-2 states the 

60-year projection is 106 cycles and the design limiting value is 120 cycles, it is not clear to the 

staff whether using the occurrences from preceding 9 years is conservative and represents the 

future trend for Normal Transient 16a, considering the short-term occurrence would be 22 if a 

short-term period of 11 years was used.
TIME-LIMITED AGING ANALYSES

4-34

By letter dated November 21, 2012, the staff issued RAI 4.3-3a requesting the applicant to 

provide the annual occurrence for Normal Transient 16a since the plant startup to 2011 to show 

the trend of this transient. The applicant also was requested to justify that the 60-year 

projection, for Normal Transient 16a, using a short-term period of the preceding 9 years 

(2002-2011) is conservative considering that 10 events occurred from 2000 through 2001. 

In its response to RAI 4.3-3a dated December 13, 2012, the applicant provided the occurrences 

for Normal Transient 16a since plant startup until 2011. The applicant explained that the reason 

for the high frequency of Normal Transient 16a between 2000 and 2001 is due to the spurious 

isolation of the 3B low pressure heater due to a Hi-Hi level alarm. In response to these 

conditions the applicant replaced the stage 3 feedwater heaters during Spring 2001. The staff 

noted that the replacement feedwater heater did not completely resolve the condition described 

above, but it did lower the accumulation rate over the next 10 years.

The applicant confirmed that Normal Transient 16a is not used in the analyses discussed in 

LRA Sections 4.7.2 and 4.7.7. The staff noted that the analyses discussed in LRA Sections 

4.7.2 and 4.7.7 were dispositioned in accordance with 10 CFR54.21(c)(1)(i), which could be 

affected by the use of a non-conservative 60-year projection. However, since these analyses 

do not use this transient as an input, the staff determined that the 60-year projection 

methodology for this transient does not impact the TLAA disposition. In addition, since the 

applicant uses it Fatigue Monitoring Program to track the occurrences of Normal Transient 16a,

the staff finds it reasonable that any increase in accumulation rate of this transient will be 

identified and action limits will prevent the design limit from being exceeded. The staff noted 

that establishing action limits provides the applicant sufficient time for activities such as 

resource utilization and planning future activities to ensure that corrective actions will be 

complete prior to the design limits from being exceeded.

The staff finds the applicant’s response to RAI 4.3-3 and RAI 4.3-3a acceptable because 

Normal Transient 16a is monitored by the Fatigue Monitoring Program, which will prevent the 

design limit of 120 cycles from being exceeded, and there are no TLAA dispositions that are 

affected by the 60-year projection of Normal Transient 16a.

LRA Table 4.3-2 indicates that for Normal Transient 5b, “Steady state fluctuations, Random 

fluctuations,” the number of cycles is beyond the endurance limit of the fatigue curve and, 

therefore, this transient does not need to be counted. The staff noted that the endurance limit of 

the fatigue curve is typically referred to as the stress level below which it results in an infinite 

number of allowable cycles. Based on the information in the LRA, it may be interpreted that the 

endurance limit is based upon a certain number of cycles. Thus, the applicant has not 

explained why the transient does not need to be counted when the number of cycles is greater 

than 106

.

By letter dated September 6, 2012, the staff issued RAI 4.3-4 requesting the applicant clarify 

and explain the statement that “the number of cycles is beyond endurance limit of the fatigue 

curve” and provide the basis for not counting this transient when the number of cycles is greater 

than 106

.

In its response dated October 11, 2012, the applicant revised the “Comments” for Normal 

Transient 5b in LRA Table 4.3-2 and clarified that the occurrence of this transient does not 

result in the accumulation of fatigue usage. The applicant also stated that the temperature and 

pressure variations caused by this transit are very small and that the resulting stress intensity 

ranges do not result in any contribution to fatigue usage. 
TIME-LIMITED AGING ANALYSES

4-35

The staff finds it reasonable that, if the stress caused by Normal Transient 5b is less than the 

alternating stress intensity (Sa) associated with the endurance limit on the ASME Code fatigue 

curves, then fatigue life can be considered infinite because the alternating stress from this 

transient is less than the cyclic stress that would result in metal fatigue. Therefore, the staff 

finds that this transient does not need to be monitored by the Fatigue Monitoring Program 

during the period of extended operation. The staff’s concern described in RAI 4.3-4 is resolved.

LRA Table 4.3-2 indicates that there are 29 occurrences of the plant heatup transient, 

29 occurrences of the plant cooldown transient, 66 occurrences of the reactor trip transient, 

2 occurrences of the inadvertent RCS depressurization transient, and 1 occurrence of the loss 

of power transient. Based on the baseline cycle occurrence data in LRA Table 4.3-2, it is not 

clear to the staff how there are an equal number of plant heatup and cooldown transients when 

considering there have been occurrences of reactor trip, inadvertent RCS depressurization, and 

loss of power transients. Thus, it is not clear to the staff whether there is a plant heatup 

recorded after each occurrence of the reactor trip, RCS depressurization, or loss of power. 

By letter dated September 6, 2012, the staff issued RAI 4.3-5 requesting the applicant 

to provide the basis that there are an equal number of plant heatup and cooldown transients 

when considering there have been occurrences of reactor trip, inadvertent RCS 

depressurization, and loss of power transient.

In its response dated October 11, 2012, the applicant clarified that a plant cooldown is counted 

independently from the reactor trip, inadvertent RCS depressurization, and loss of power 

transients. Since these transients are counted independently, the staff noted that the 

occurrence of one of these upset transients does not preclude a plant cooldown event from 

being counted. Furthermore, the applicant explained that the occurrence of an inadvertent RCS 

depressurization, loss of power, and reactor trip transient does not always result in a plant 

cooldown. Following one of these upset transients, however, if there is a plant cooldown, there 

would be a subsequent heatup event to return the unit to power. The applicant clarified that all 

plant cooldowns and plant heatups are counted separately, regardless of whether they follow a 

reactor trip or any other event. The staff noted that since the fatigue analyses incorporated 

these transients separately, it is appropriate that the number of cycles are counted independent 

of one another to ensure that the assumptions in these analyses are not exceeded.

Based on the applicant’s clarifications, the staff finds that the Fatigue Monitoring Program is 

capable of counting the number of occurrences for transients, such as the plant heatup, plant 

cooldown reactor trip, inadvertent RCS depressurization, and loss of power, incorporated into 

fatigue analyses to ensure that the number of actual transient occurrences does not exceed the 

number used in any fatigue analyses. The staff’s evaluation of the Fatigue Monitoring Program 

is documented in SER Section 3.0.3.2.22. Therefore, the staff’s concern described in RAI 4.3-5 

is resolved.

Based on its review, the staff finds the applicant demonstrated that it has an appropriate 

baseline for monitored transients and that it monitors all transients that cause cyclic strains 

which are significant contributors to the fatigue usage factor with its Fatigue Monitoring 

Program, such that corrective actions are taken prior to exceeding the design limit. Even 

though the applicant’s projection methodology provides a reasonable outlook of the number of 

cycles after 60 years of operation, which are less than the design cycle limits, the staff finds the 

applicant’s Fatigue Monitoring Program ensures that such that the effects of aging due to metal 

fatigue will be adequately managed for the period of extended operation.
TIME-LIMITED AGING ANALYSES

4-36

4.3.1.2.3 FSAR Supplement

LRA Sections A2.1, as amended by letter dated June 5, 2012, and A3.2 provide the FSAR 

supplement summarizing the applicant’s basis of its fatigue analyses and describing its Fatigue 

Monitoring Program to ensure that the numbers of transients actually experienced remain below 

the assumed number. The staff reviewed LRA Sections A2.1 and A3.2, consistent with the 

review procedures in SRP-LR Section 4.3.3.2. The procedures state that the reviewer should 

confirm that the applicant has provided information to be included in the FSAR supplement that 

includes a summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds that it meets the acceptance criteria 

in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the applicant provided an 

adequate summary description for its Fatigue Monitoring Program to monitor the numbers of 

transients actually experienced, as required by 10 CFR 54.21(d).

4.3.1.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has an appropriate baseline for

all transients and that these transients will be monitored by the Fatigue Monitoring Program

Program such that the effects of aging due to fatigue on the intended functions will be 

adequately managed for the period of extended operation. In addition, the staff concludes that 

the applicant’s projection methodology provides a representative expectation of the number of 

cycles after 60 years of operation, which are below the design cycle limits, and the Fatigue 

Monitoring Program ensures corrective actions are taken prior to exceeding the design limit 

during the period of extended operation. 

4.3.2 ASME Section III Class I Fatigue Analysis of Vessels, Piping, and Components

4.3.2.A Summary of Technical Information 

LRA Section 4.3.2 states that fatigue analyses are performed for ASME Code Section III, 

Division 1, Class 1 components per the ASME Code Section III, paragraph NB-3222.4(e). 

A detailed fatigue evaluation is not required if components conform to the waiver of fatigue 

requirements, ASME Code paragraph NB-3222.4(d). The LRA states that these fatigue 

analyses and fatigue waivers depend on the numbers of anticipated transients over the life of 

the plant and, therefore, constitutes TLAAs. The following lists all vessels, pumps, and 

components subject to Class 1 fatigue analyses.

• reactor pressure vessel (RPV), nozzles, head, head adapter plugs, and studs

• control rod drive mechanisms (CRDMs) and core exit thermocouple nozzle assembly 

(CETNAs) (the CRDMs were shown to satisfy the fatigue waiver requirements)

• reactor coolant pumps (RCP) (the RCP casing, thermal barrier assembly, seal housing, 

and auxiliary nozzles were shown to satisfy the fatigue waiver requirements)

• pressurizer and pressurizer nozzles

• steam generators, and feedwater nozzles (no fatigue analysis is required for the Class 2 

secondary side of the steam generator; however, the entire pressure boundary of the 

replacement steam generators is constructed in accordance with ASME Code Section III 

Class 1 requirements)
TIME-LIMITED AGING ANALYSES

4-37

• ASME III Class 1 valves

• ASME III Class 1 piping and piping nozzles

The fatigue analyses for the components listed in LRA Table 4.3-3 and the fatigue waiver 

evaluations were performed using the transients listed in LRA Table 4.3-2. These analyses and 

waivers will remain applicable as long as the numbers of specified design transients are not 

exceeded. Thus, the Fatigue Monitoring Program will track the numbers of events and transient 

severities. The applicant stated that LRA Sections 4.3.2.1 through 4.3.2.4 include topics that 

required additional consideration when evaluating the ability of the Fatigue Monitoring Program 

to manage fatigue and fatigue analyses, which were not dispositioned in accordance with 

10 CFR 54.21(c)(1)(iii).

The applicant dispositioned the TLAAs for the vessels, pumps, and components subject to 

Class 1 fatigue analyses, as listed above, in accordance with 10 CFR 54.21(c)(1)(iii), that the 

effects of metal fatigue on the intended functions will be adequately managed by the Fatigue 

Monitoring Program for the period of extended operation.

4.3.2.B Staff Evaluation

The staff reviewed LRA Section 4.3.2 and the TLAAs for the vessels, piping, and components 

subject to Class 1 analyses, except those discussed in LRA Sections 4.3.2.1 through 4.3.2.4, to 

verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of fatigue will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation.

The staff reviewed the applicant’s TLAAs for the vessels, piping, and components subject to 

ASME Section III Class 1 analyses, except those discussed in LRA Sections 4.3.2.1 

through 4.3.2.4, and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the 

review procedures in SRP-LR Section 4.3.3.1.1.3. These procedures state that the reviewer 

should verify the appropriateness of the applicant’s program for monitoring and tracking the 

number of critical thermal and pressure transients for the selected RCS components.

The staff reviewed LRA Table 4.3-3, which provides the CUF values for the components that 

have ASME Class 1 fatigue analyses which will be managed by the Fatigue Monitoring 

Program, and noted that the CUF values are less than the Code design limit of 1.0. The staff 

determined that the program includes three monitoring methods (cycle counting, cycle-based 

fatigue monitoring, and stress-based fatigue monitoring) that are capable of managing metal 

fatigue during the period of extended operation. The staff also determined that the use of these 

three monitoring methods progressively provide a more refined monitoring approach to manage 

metal fatigue to ensure that the applicable allowable design limits are not exceeded and fatigue 

waivers remain valid. The staff determined that these characteristics of the applicant’s Fatigue 

Monitoring Program are consistent with GALL Report AMP X.M1. The staff’s evaluation of the 

Fatigue Monitoring Program is documented in SER Section 3.0.3.2.22.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of aging related to metal fatigue of the vessels, pumps, and components subject to 

Class 1 fatigue analyses, except those discussed in LRA Sections 4.3.2.1 through 4.3.2.4, will 

be adequately managed for the period of extended operation. Additionally, the applicant's 

disposition meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant 

is crediting its Fatigue Monitoring Program, which the staff determined in SER 

Section 3.0.3.2.22 is consistent with GALL Report AMP X.M1, to manage metal fatigue to 

ensure that the allowable design limits on fatigue usage are not exceeded during the period of 
TIME-LIMITED AGING ANALYSES

4-38

extended operation; otherwise, the applicant will take corrective actions in accordance with its 

program.

4.3.2.C FSAR Supplement

LRA Section A3.2.1 provides the FSAR supplement summarizing the TLAA for the vessels, 

piping, and components subject to Class 1 fatigue analyses, except those discussed in LRA 

Sections 4.3.2.1 through 4.3.2.4. The staff reviewed LRA Section A3.2.1 consistent with the 

review procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that the 

applicant has provided information to be included in the FSAR supplement that includes a 

summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA for the 

vessels, piping, and components subject to Class 1 fatigue analyses, except those discussed in 

LRA Sections 4.3.2.1 through 4.3.2.4, as required by 10 CFR 54.21(d).

4.3.2.D Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on 

the intended functions of the vessels, piping, and components subject to Class 1 fatigue 

analyses, except those discussed in LRA Sections 4.3.2.1 through 4.3.2.4, will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation. The staff 

also concludes that the FSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.2.1 Reactor Coolant Pump Thermal Barrier Flange

4.3.2.1.1 Summary of Technical Information in the Application

LRA Section 4.3.2.1 states that the fatigue waiver conditions of the ASME Code are satisfied for 

the RCP, but a cumulative usage factor was calculated as part of simplified elastic-plastic 

analyses for the thermal barrier flange at component cooling water (CCW) connection. The 

fatigue analysis of the thermal barrier flange at CCW connection results in a CUF of 0.9334, 

which uses auxiliary seal injection and CCW transients in addition to the design basis shown in 

FSAR 3.9(N)-1 SP.

LRA Section 4.3.2.1 states that the auxiliary seal injection and component CCW transients used 

in the design of the RCP thermal barrier flange include the following:

No. 1 seal injection 

• 180 cycles of seal injection flow temperature change 

• 200 cycles of elevated seal water injection temperature 

• 40 cycles of loss of seal injection flow 
TIME-LIMITED AGING ANALYSES

4-39

CCW connection 

• 200 cycles of elevated CCW injection temperature 

• 40 cycles of seasonal temperature change 

• 200 cycles of loss of CCW flow

The LRA states that the numbers of the plant cooldown, seal injection flow temperature change, 

elevated seal water injection temperature change, elevated CCW injection temperature, loss of 

seal injection, and complete loss of CCW flow transients will be tracked by the Fatigue 

Monitoring Program, as shown in LRA Table 4.3-2. Since the seasonal temperature change is 

the only transient not counted, its usage contribution during the period of extended operation 

can be estimated by multiplying its 40-year usage contribution by 1.5, which causes the CUF to 

exceed the ASME Code allowable of 1.0. LRA Section 4.3.2.1 also discusses an evaluation 

that was performed to ensure the CUF will be less than 0.9 for the period of extended operation, 

by limiting the number of cycles due to elevated CCW injection temperature to 75 percent of its 

design value, or 150 cycles. 

The applicant dispositioned the TLAA for the RCP thermal barrier in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on the intended functions will be 

adequately managed by the Fatigue Monitoring Program for the period of extended operation.

4.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.1 and the TLAA for the RCP thermal barrier flange to 

verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of fatigue will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation.

The staff reviewed the applicant’s TLAA for the RCP thermal barrier flange and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in 

SRP-LR Section 4.3.3.1.1.3. These procedures state that the reviewer should verify the 

appropriateness of the applicant’s program for monitoring and tracking the number of critical 

thermal and pressure transients for the selected RCS components.

The staff noted that the applicant monitors all the transients, except the seasonal temperature 

change transient, used in the fatigue analysis of the RCP thermal barrier flange with its Fatigue 

Monitoring Program. The staff determined that the program includes three monitoring methods 

(cycle counting, CBF monitoring, and SBF monitoring) that are capable of managing metal 

fatigue during the period of extended operation. The staff also determined that the use of these 

three monitoring methods progressively provides a more refined monitoring approach to 

manage metal fatigue to ensure that the applicable allowable design limits are not exceeded. 

The staff determined that these characteristics of the applicant’s Fatigue Monitoring Program 

are consistent with GALL Report AMP X.M1. The staff’s evaluation of the Fatigue Monitoring 

Program is documented in SER Section 3.0.3.2.22. The staff finds that the Fatigue Monitoring 

Program ensures the validity of the fatigue analyses through the period of extended operation. 

The staff’s review of the basis that the seasonal temperature change transient is not monitored 

is documented below.

The LRA states that the seasonal temperature change transient is the only transient not 

counted; thus, its usage contribution during the period of extended operation can be estimated 

by multiplying its 40-year usage contribution by 1.5, which results in the CUF exceeding the 

ASME Code allowable of 1.0. It also states that the transient that contributes most significantly 

to fatigue is the 200 cycles of elevated CCW injection temperature. To account for the increase 
TIME-LIMITED AGING ANALYSES

4-40

in usage described above caused by the 20 additional years of operation and to keep the usage 

below the ASME Code allowable of 1.0, the LRA states that the number of the most severe 

transient will be limited to 75 percent of its design value (i.e., limited to 150 elevated CCW 

injection temperature), which will keep the CUF less than 0.9. 

Additional information regarding the CUF contribution for each of the transients in the original 

fatigue analysis for this component is required for the staff to verify the adequacy of the TLAA 

disposition. It is not clear to the staff whether the applicant has performed a CUF 

“re-calculation” consistent with ASME Code Section III NB-3222.4(e)(5) Step 1 to arrive at its 

conclusion.

By letter dated September 6, 2012, the staff issued RAI 4.3-13 requesting the applicant provide 

the CUF contribution, as documented in the original fatigue evaluation, for each of the transient 

pairings (including the number of cycles used in each pairing) consistent with ASME Code 

NB-3222.4(e)(5). The applicant also was requested to confirm that the CUF value has been 

recalculated consistent with ASME Code Section III NB-3222.4(e)(5) to reach its conclusion to 

restrict the occurrence of the elevated CCW injection temperature and to justify that the 

accumulated fatigue usage will remain less than 0.9 without monitoring or confirmation that the 

number of occurrences of the seasonal temperature change transient will not exceed the design 

limit. 

In its response dated October 11, 2012, the applicant provided the CUF contributions from the 

thermal barrier stress report, as documented in the original fatigue evaluation, for each of the 

transient pairings (including number of cycles used in each pairing) consistent with ASME Code 

NB-3222.4(e)(5). (The staff noted a typographical error in RAI 4.3-13 and the applicant’s

response – reference to ASME Code NB 3224(e)(5) is meant to be ASME Code 

NB 3222.4(e)(5).) The applicant also confirmed that the conclusion of restricting the occurrence 

of the elevated CCW injection temperature to 75 percent of the design limit will result in a CUF 

of less than 0.9 was determined with an evaluation that is consistent with ASME Code 

Section III NB-3222.4(e)(5). The staff noted that ASME Code Subsection NB-3222.4(e)(5) 

provides the required procedures to analyze cyclic loading. 

The staff noted that, for design purposes, a seasonal temperature change is represented by the 

CCW temperature dropping instantaneously from an initial temperature of 54 °C (130 °F) to a 

minimum of 8 °C (47 °F) and then returned instantaneously to 54 °C (130 °F). This is assumed 

to occur once per year. The staff noted that the seasonal temperature change transient is the 

only transient that is not counted and only contributes 0.24 to the recalculated CUF of 0.8915. 

However, the staff noted that it is reasonable to assume that the actual occurrence of this 

transient will not be as severe because the change in CCW temperature will be slow and 

gradual rather than being instantaneous, as assumed in the design analysis. 

Thus, the staff finds it reasonable that the design limit of 1.0 will be not exceeded during the 

period of extended operation if this transient is not monitored because: (1) the contribution to 

the CUF from each occurrence of this transient will be less than anticipated by the design 

report, as described above, (2) the staff confirmed that the applicant cycle counts all other 

transients used in the fatigue evaluation of the thermal barrier flange at the CCW connection, 

and (3) the Fatigue Monitoring Program will include cycle count action limits that will permit 

completion of corrective actions if the design limits are expected to be exceeded within the next 

three fuel cycles. Therefore, the staff finds the applicant response acceptable and its concern 

described in RAI 4.3-13 is resolved.
TIME-LIMITED AGING ANALYSES

4-41

The staff noted that the thermal barrier flange at No. 1 seal injection and at the CCW connection 

will be managed by cycle counting, as part of the Fatigue Monitoring Program, which involves 

initiating corrective actions if the cycle count for any one transient approaches an action limit. 

The staff finds that this method of monitoring will ensure that the recalculated CUF will not be 

approached, let alone the design limit of 1.0. The staff’s evaluation of cycle counting monitoring 

method and the Fatigue Monitoring Program is documented in SER Section 3.0.3.2.22. 

The staff determined that this program also includes CBF monitoring and SBF monitoring that 

are capable of managing metal fatigue, which progressively provide a more refined monitoring 

approach to manage metal fatigue to ensure that the applicable allowable design limits are not 

exceeded. The staff determined that these characteristics of the applicant’s Fatigue Monitoring 

Program are consistent with GALL Report AMP X.M1.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of metal fatigue on the intended functions of the RCP thermal barrier flange will be 

adequately managed for the period of extended operation. Additionally, it meets the acceptance 

criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting its Fatigue Monitoring 

Program to manage metal fatigue to ensure that the allowable design limits on fatigue usage are 

not exceeded during the period of extended operation; otherwise, the applicant will take 

corrective actions in accordance with its program.

4.3.2.1.3 FSAR Supplement

LRA Section A3.2.1.1 provides the FSAR supplement summarizing the RCP thermal barrier 

flange at CCW connection. The staff reviewed LRA Section A3.2.1.1, consistent with the review 

procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that the applicant 

has provided information to be included in the FSAR supplement that includes a summary 

description of the evaluation of the metal fatigue TLAA.

The staff noted that LRA Section A3.2.1.1 states that the transients used in the fatigue analysis 

of the thermal barrier flange at the CCW connection will be tracked by the Fatigue Monitoring 

Program; however, the LRA does not identify that elevated CCW injection temperature 

transients will be limited to 75 percent of its design value and does not clearly indicate that, with 

the exception of the seasonal temperature change transient, the transients used in the fatigue 

analysis of the thermal barrier flange at the CCW connection will be tracked by the Fatigue 

Monitoring Program. Without an explicit reference to the 75 percent limit of the design value of 

the elevated CCW inlet temperature transients, the proposed FSAR supplement in LRA 

Section A3.2.1.1 does not reflect an accurate summary description of the program and activities 

to manage the effects of aging. 

By letter dated September 6, 2012, the staff issued RAI 4.3-19 requesting the applicant revise 

LRA Section A3.2.1.1 to indicate that elevated CCW injection temperature transient will be 

limited to 75 percent of its design value to accommodate the seasonal temperature change 

transient in the RCP thermal barrier flange fatigue analysis. The applicant also was requested 

to revise LRA Section A3.2.1.1 to indicate that, with the exception of the seasonal temperature 

change transient, the transients used in the fatigue analysis of the thermal barrier flange at the 

CCW connection will be tracked by the Fatigue Monitoring Program.
TIME-LIMITED AGING ANALYSES

4-42

In its response dated October 11, 2012, the applicant revised LRA Section A3.2.1.1 to state the 

following:

To account for the increase in usage caused by 20 additional years of operation 

associated with the seasonal temperature change transient in the RCP thermal 

barrier flange fatigue analysis and to maintain the usage below the ASME Code 

allowable of 1.0, the elevated CCW injection temperature transient will be limited 

to 75 percent of its design value, (i.e., limited to 150 transients).

With the exception of the seasonal temperature change transient, the transients 

used in the fatigue analysis of the thermal barrier flange at the [CCW] connection 

will be tracked by the Fatigue Monitoring Program, summarized in Section A2.1.

The staff finds the applicant’s response acceptable because LRA Section A3.2.1.1 was revised 

to accurately summarize and provide the details of how the TLAA was evaluated and how the 

Fatigue Monitoring Program manages metal fatigue in accordance with 10 CFR 54.21(d). In 

addition, the staff noted that the applicant’s Fatigue Monitoring Program will include appropriate 

cycle count action limits to ensure corrective actions are taken prior to exceeding the design 

limit of 150 for the elevated CCW injection temperature transient. The staff’s evaluation of the 

Fatigue Monitoring Program is documented in SER Section 3.0.3.2.22. The staff’s concern 

described in RAI 4.3-19 is resolved. 

Based on its review of the FSAR supplement, as amended by letter dated October 11, 2012, 

the staff finds it meets the acceptance criteria in SRP-LR Section 4.3.2.2, and is therefore 

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address metal fatigue TLAA of the RCP thermal barrier flange, as 

required by 10 CFR 54.21(d).

4.3.2.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on 

the intended functions of the RCP thermal barrier flange will be adequately managed by the 

Fatigue Monitoring Program for the period of extended operation. The staff also concludes that 

the FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.3.2.2 Pressurizer Insurge-Outsurge Transients

4.3.2.2.1 Summary of Technical Information in the Application

LRA Section 4.3.2.2 states that Westinghouse Nuclear Safety Advisory Letter NSAL 04-5 

describes the thermal transients resulting from a reactor coolant insurge-outsurge during normal 

heatup and cooldown operations. In addition, the limiting CUF locations for 

Westinghouse-designed plants are at the heater penetrations and pressurizer surge nozzle. 

This type of transient was not considered in the original design analyses of the pressurizer 

because it was assumed that when a pressurizer insurge occurred, the screen covering the 

surge nozzle opening inside the pressurizer caused mixing of the colder hot leg and hotter 

pressurizer water. However, instead of mixing, surge line stratification data led to the realization 

that the cooler, denser, hot leg water flows underneath the pressurizer water, resulting in a 

moving stratified condition. 
TIME-LIMITED AGING ANALYSES

4-43

To mitigate pressurizer insurge-outsurge transients, the applicant has used modified operating 

procedures (MOPs) since 1996. Guidance on operations and engineering actions for 

monitoring and evaluating fatigue if the pressurizer surge line temperature change (ΔT) limits 

are exceeded is incorporated into the plant heatup and cooldown procedures. Sample fatigue 

analyses for typical Westinghouse plants using MOPs show that the expected maximum fatigue 

for the pressurizer and pressurizer components is expected to remain below the ASME Code 

limit of 1.0. 

To determine if the pressurizer contains a limiting EAF location, the fatigue analyses will be 

revised to incorporate the effect of insurge-outsurge transients on the pressurizer lower head, 

surge nozzle, and heater well nozzles at plant-specific conditions. For license renewal, the 

applicant committed (Commitment No. 36) to monitor the CUF of the limiting location out of the 

pressurizer lower head, pressurizer surge line nozzle, and heater well nozzles using fatigue 

monitoring software consistent with RIS 2008-30. 

The applicant dispositioned the TLAAs associated with the pressurizer insurge-outsurge 

transients, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue, including 

the effects from pressurizer insurge-outsurge transients, on the intended functions will be 

adequately managed by the Fatigue Monitoring Program for the period of extended operation.

4.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.2 and the TLAA associated with pressurizer 

insurge-outsurge transients to verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects 

of fatigue will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation.

The staff reviewed the applicant’s TLAAs associated with pressurizer insurge-outsurge 

transients and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the 

review procedures in SRP-LR Section 4.3.3.1.1.3. These procedures state that the reviewer 

should verify the appropriateness of the applicant’s program for monitoring and tracking the 

number of critical thermal and pressure transients for the selected RCS components.

The staff noted that the pressurizer insurge-outsurge transients were not considered in the 

original design analyses of the pressurizer and that the applicant has mitigated the effects of 

these transients by using MOPs since 1996. Specifically, the staff noted that the MOPs include 

guidance for monitoring and evaluating fatigue if the pressurizer surge line ΔT limits are 

exceeded and were incorporated into the Plant Heatup and Cooldown procedures. In addition, 

these actions include direction to initiate an engineering evaluation of the surge line 

accumulated fatigue if the surge line ΔT limits are exceeded. The staff finds it appropriate that 

the applicant revised its plant procedures to ensure that ΔT limits were incorporated into its 

plant heatup and cooldown procedures to prevent pressurizer insurge-outsurge transients from 

significantly affecting the pressurizer surge line by the means of metal fatigue.

LRA Table A4-1 contains Commitment No. 36, which states, “[i]mplement SBF or CBF 

consistent with RIS 2008-30 to monitor the CUF of the limiting location out of the pressurizer 

lower head, surge nozzle and heater penetrations to accommodate the insurge-outsurge 

transient.” In addition, LRA Table A4-1 contains Commitment No. 37, which states, in part, that 

“to determine if the pressurizer contains a limiting EAF location, the fatigue analyses will be 

revised to incorporate the effect of insurge-outsurge transients on the pressurizer lower head, 

surge nozzle, and heater well nozzles at plant specific conditions.” The staff noted that in LRA 

Amendment 2, dated May 3, 2012, the applicant revised Commitment No. 37 to state that this 
TIME-LIMITED AGING ANALYSES

4-44

portion of the commitment was completed and was revised to state, in part, that “[t]he 

pressurizer contains a limiting EAF location. The fatigue analyses will be revised to incorporate 

the effect of insurge-outsurge transients in the pressurizer lower head.”

Based on the completed portion of Commitment No. 37 and the revision to Commitment No. 37, 

it is not clear to the staff whether the effects of insurge-outsurge transients have been 

incorporated into the fatigue analyses of the pressurizer. Furthermore, based on LRA 

Table 4.3-7, as amended by letter dated May 3, 2012, there are a total of seven sentinel 

locations for three different regions (pressurizer lower head, pressurizer spray, and pressurizer 

SRV/PORV) of the pressurizer, which contradicts the revised Commitment No. 37 statement 

that the pressurizer contains a single limiting EAF location. 

Considering the completed portion of Commitment No. 37 described above, the staff noted that 

LRA Sections 4.3.2.2 and A3.2.1.2 were not revised to capture the incorporation of 

insurge-outsurge transients on the pressurizer lower head, surge nozzle, and heater well 

nozzles at plant-specific conditions. In addition, the staff noted that locations to be monitored 

are different between LRA Section A3.2.1.2 and Commitment No. 36. Thus, it is not clear to the 

staff what the basis is for the discrepancy. Furthermore, it is not clear how the effects of 

insurge-outsurge transients were incorporated into the fatigue analyses of the pressurizer 

before the implementation of MOPs in 1996. 

By letter dated September 6, 2012, the staff issued RAI 4.3-12, Parts (a) through (c), requesting 

the applicant provide the basis for the discrepancies identified by the staff in LRA Sections 

4.3.2.2 and A3.2.1.2 and Commitment No. 37. In addition, RAI 4.3-12, Part (d), requested the 

applicant to clarify the locations to be monitored for CUF using fatigue monitoring software and 

revise LRA Section A3.2.1.2 and Commitment No. 36 to address the discrepancy in monitored 

locations. Finally, RAI 4.3-12, Part (d), requested the applicant to explain and justify how 

pre-MOP insurge-outsurge transients were incorporated into the fatigue analyses of the 

pressurizer.

In its response to RAI 4.3-12, Part (a), dated October 11, 2012, the applicant clarified that the 

incorporation of the insurge-outsurge transient into the design analysis for the pressurizer lower 

head, surge nozzle, and heater well nozzles was completed after submittal of the May 3, 2012, 

LRA Amendment 2. The staff noted that LRA Section 4.3.2.2, LRA Section A3.2.1.2, and 

Commitment No. 37 have been revised as part of the response to RAI 4.3-12 to indicate the

fatigue analyses have been revised to incorporate the effect of insurge-outsurge transients on 

the pressurizer lower head, surge nozzle, and heater well nozzles at plant-specific conditions. 

The revision also demonstrated that the environmentally-adjusted fatigue usage factor (CUFen) 

are less than 1.0. In addition, the applicant indicated that metal fatigue of components 

associated with the pressurizer insurge-outsurge transients, including the effects of the reactor 

coolant environment on fatigue usage factors, will be managed for the period of extended 

operation in accordance with 10 CFR 54.21(c)(1)(iii). The staff finds these revisions acceptable 

because the LRA clearly identifies that re-analysis of the pressurizer components to include the 

effect of insurge-outsurge transients has been completed and that metal fatigue will be 

managed for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(iii). The 

staff’s review of the applicant’s aging management method is discussed below. The staff’s 

review of the applicant’s EAF analyses, including the effect of insurge-outsurge transients on 

the pressurizer lower head, surge nozzle, and heater well nozzles is documented in SER 

Section 4.3.4.2.
TIME-LIMITED AGING ANALYSES

4-45

In its response to RAI 4.3-12, Part (b), the applicant clarified that the only thermal zone affected 

by the insurge-outsurge transient is the pressurizer lower head and that the CUF values for the 

pressurizer lower head components in LRA Table 4.3-7, as revised by letter dated May 3, 2012, 

account for the insurge-outsurge transient. The staff noted that the other sentential locations 

identified for the pressurizer in LRA Table 4.3-7 were associated with the pressurizer spray, 

safety relief valve, or PORVs, not the pressurizer lower head. The staff finds it acceptable that 

the applicant clarified that all applicable pressurizer components have incorporated the effects 

of insurge-outsurge transients, and these locations are being managed for environmentally 

assisted fatigue.

In response to RAI 4.3-12, Part (c), the applicant stated that the insurge-outsurge analysis was

not complete when the LRA Amendment was submitted on May 3, 2012. The staff notes that 

LRA Section 4.3.2.2, LRA Section A3.2.1.2, and Commitment No. 37 have been revised as part 

of the applicant’s response to RAI 4.3-12. 

In response to RAI 4.3-12, Part (d), the applicant stated that, based on the completed 

insurge-outsurge analysis and the EAF screening results, the aging of the pressurizer lower 

head, surge nozzle, and heater well nozzles can be managed without SBF monitoring. Instead, 

managing fatigue for the pressurizer lower head, surge nozzle, and heater well nozzles will be 

accomplished with cycle counting. LRA Table 4.3-1 and LRA Appendix A3.2.1.2 were revised 

as part of the RAI response to remove CUF monitoring of the pressurizer lower head, 

pressurizer surge nozzle, and pressurizer heater well nozzles. In addition, the applicant also 

revised LRA Table A4-1 Commitment 36 to indicate that the commitment to implement SBF or 

CBF monitoring for pressurizer limiting locations is no longer applicable.

The applicant explained that these locations can be monitored by cycle counting because, when 

the revised CUF values that include the effects of insurge-outsurge transients are updated to 

include the maximum environmental adjustment factor (Fen) value for stainless steel, the 

resultant CUFen values are less than the design limit of 1.0. The staff noted that, by cycle 

counting the transients used in the fatigue analysis, the applicant is able to manage metal 

fatigue and ensure that the assumptions used in these fatigue analysis will not be exceeded 

without initiating corrective actions to assess the impact. Thus, the staff finds the use of cycle 

counting, as included in the Fatigue Monitoring Program, is an acceptable method to manage 

metal fatigue. The staff determined that these characteristics of the applicant’s Fatigue 

Monitoring Program are consistent with GALL Report AMP X.M1. The staff’s evaluation of the 

Fatigue Monitoring Program is documented in SER Section 3.0.3.2.22. 

The applicant stated in its response to RAI 4.3-12, Part (d), that insurge-outsurge transients 

before implementation of MOPs were derived from WCAP-12893, “Structural Evaluation of the 

Wolf Creek and Callaway Pressurizer Surge Lines, Considering the Effects of Thermal 

Stratification,” dated March 1991. The applicant clarified that the plant-specific applicability of 

these transients was addressed in WCAP-12893 through the use of surge line monitoring 

results, plant operating procedure and operator interviews, and plant historical records. The 

staff finds it reasonable that the applicant used WCAP-12893 to derive pre-MOP 

insurge-outsurge transients because this document was confirmed to be applicable based on 

plant-specific data. Since the occurrence of insurge-outsurge transients are concurrent with 

heatup and cooldown events, the staff finds it reasonable that the applicant determined the 

number of pre-MOP insurge-outsurge transients experienced through 1996 based on the 

baseline work to determine cycle counts. The staff’s review of the applicant’s baseline of 

transient cycle counts is documented in SER Section 4.3.1.2.2.
TIME-LIMITED AGING ANALYSES

4-46

The applicant stated in its response to RAI 4.3-12, Part (d), that the insurge-outsurge transients, 

after implementation of MOPs, are based on modified steam bubble method from WCAP-14950, 

“Mitigation and Evaluation of Pressurizer Insurge-Outsurge Transients,” dated February 1998. 

Furthermore, these generic transients from WCAP-14950 were compared to the plant-specific 

recorded data from October 1995 (date when automated cycle counting was initiated) to 

June 2010 and the insurge-outsurge transients were constructed to be representative of the 

site. The staff finds it acceptable that data from WCAP-14950 were used to construct post-MOP 

insurge-outsurge transients because the applicant compared the data to its plant-specific 

recorded data to ensure the transients were representative.

The staff noted that the actions in Commitment No. 36 and portions of Commitment No. 37 

related to pressurizer insurge-outsurge transients were completed by letters dated May 3, 2012, 

and October 11, 2012. The staff’s evaluation of the remaining portion of Commitment No. 37 is 

documented in SER Section 4.3.4.2.

The staff finds the applicant’s response to RAI 4.3-12 acceptable because the applicant revised 

the LRA to eliminate discrepancies in LRA Sections 4.3.2.2 and A3.2.1.2 and Commitment 

No. 37. The applicant sufficiently justified, as described above, the use of cycle counting to 

manage the pressurizer lower head components affected by insurge-outsurge transients, and 

the applicant adequately incorporated the occurrences of pre-MOP and post-MOP 

insurge-outsurge transients, as described above. Therefore, the staff’s concern described in 

RAI 4.3-12 is resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of metal fatigue on the intended functions of the pressurizer components affected by 

insurge-outsurge transients will be adequately managed for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the 

applicant has updated its fatigue analysis to incorporate insurge-outsurge transients and is 

crediting its Fatigue Monitoring Program to manage metal fatigue to ensure that the allowable 

design limits on fatigue usage are not exceeded during the period of extended operation; 

otherwise, the applicant will take corrective actions, in accordance with its program.

4.3.2.2.3 FSAR Supplement

LRA Section A3.2.1.2 provides the FSAR supplement summarizing the TLAA for pressurizer 

components affected by insurge-outsurge transients. The staff reviewed LRA Section A3.2.1.2, 

as amended by letter dated October 11, 2012, consistent with the review procedures in SRP-LR 

Section 4.3.3.2, which state that the reviewer verifies that the applicant has provided information 

to be included in the FSAR supplement that includes a summary description of the evaluation of 

the metal fatigue TLAA.

Based on its review of the FSAR supplement, as amended by letter dated October 11, 2012, the 

staff finds it meets the acceptance criteria in SRP-LR Section 4.3.2.2, and is therefore 

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address pressurizer components affected by insurge-outsurge 

transients, as required by 10 CFR 54.21(d).

4.3.2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on 

the intended functions of the pressurizer components affected by insurge-outsurge transients 
TIME-LIMITED AGING ANALYSES

4-47

will be adequately managed by the Fatigue Monitoring Program for the period of extended 

operation. The staff also concludes that the FSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.2.3 Steam Generator ASME Section III Class 1, Class 2 Secondary Side, and 

Feedwater Nozzle Fatigue Analyses

4.3.2.3.1 Summary of Technical Information in the Application

LRA Section 4.3.2.3 states that, “[a]lthough the ASME classification for the secondary side of 

the steam generators is specified to be Class 2, all pressure retaining parts of the steam 

generator, and thus both the primary and secondary pressure boundaries, are designed to 

satisfy the criteria specified in Section III of the ASME Code for Class 1 components.” 

Furthermore, the replacement steam generators (RSGs), which were installed during Refuel 14 

(Fall 2005), reduced the susceptibility to primary water stress-corrosion cracking (PWSCC) by 

eliminating all susceptible Alloy 600 and 82/182 material in the steam generators. LRA Table 

4.3-4 provides a list of the results from the Class 1 fatigue analyses of the RSG components, 

which used the design basis numbers of events assumed for a 40-year design life. The RSGs 

design lives end in 2045, which extends beyond the period of extended operation. 

The applicant dispositioned the TLAA for the steam generator ASME Code Section III Class 1, 

Class 2 secondary side, and feedwater nozzle fatigue analyses, in accordance with 

10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended operation.

4.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.3 and the metal fatigue TLAA for steam generator ASME 

Code Section III Class 1, Class 2 secondary side, and feedwater nozzle to verify, in accordance 

with 10 CFR 54.21(c)(1)(i), that the analysis remains valid during the period of extended 

operation.

The staff reviewed the applicant’s metal fatigue TLAAs for steam generator ASME Code 

Section III Class 1, Class 2 secondary side, and feedwater nozzle and the corresponding 

disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR 

Section 4.3.3.1.1.1. These procedures state that the operating transient experience and a list of 

the assumed transients used in the existing CUF calculations for the current operating term are 

reviewed to ensure that the number of assumed transients would not be exceeded during the 

period of extended operation.

LRA Section 4.3.2.3 states that the steam generators were installed during Refuel 14 

(Fall 2005), which extends the design lives of the replacement steam generators to fall 2045. 

The staff noted that the components associated with replacement steam generators were 

designed to satisfy the criteria specified in ASME Code Section III for Class 1 components. In 

addition, these components were designed and qualified for 40 years, which extends the design 

lives (Fall 2045) beyond the period of extended operation. Since these components were 

designed to ASME Code Section III, the staff noted that they were required to have a CUF value 

less than 1.0 for the design life (i.e., 40 years) to be qualified for service. The staff reviewed 

LRA Table 4.3-4, which provides the CUF values for replacement steam generator components 

designed to ASME Code Section III and noted that the 40-year CUF values were less than the 

ASME Code design limit of 1.0. Since the fatigue analyses for these components indicated 

CUF values are less than the ASME Code limit beyond the period of extended operation, the 

staff finds that these analyses will remain valid during the period of extended operation.
TIME-LIMITED AGING ANALYSES

4-48

The staff finds that the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), 

that the fatigue analyses for the replacement steam generators designed to ASME Code 

Section III remain valid for the period of extended operation. Additionally, the analyses meet the 

acceptance criteria in SRP-LR Section 4.3.2.1.1.1 because the design life of the replacement 

steam generator components and the associated Class 1, Class 2 secondary side, and 

feedwater nozzle fatigue analyses extend beyond the period of extended operation.

4.3.2.3.3 FSAR Supplement

LRA Section A3.2.1.3 provides the FSAR supplement summarizing the TLAA for the 

replacement steam generator components and the associated fatigue analyses. The staff 

reviewed LRA Section A3.2.1.3 consistent with the review procedures in SRP-LR 

Section 4.3.3.2, which state that the reviewer verifies that the applicant has provided information 

to be included in the FSAR supplement that includes a summary description of the evaluation of 

the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2 and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the replacement 

steam generator components and the associated fatigue analyses, as required by 

10 CFR 54.21(d).

4.3.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the Class 1, Class 2 secondary 

side, and feedwater nozzle fatigue analyses for the replacement steam generator components 

remain valid for the period of extended operation. The staff also concludes that the FSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d).

4.3.2.4 NRC Bulletin 88-11 Revised Fatigue Analysis of the Pressurizer Surge Line for 

Thermal Cycling and Stratification

4.3.2.4.1 Summary of Technical Information

LRA Section 4.3.2.4 states that the purpose of NRC Bulletin 88-11 was to (1) request that 

addressees establish and implement a program to confirm pressurizer surge line integrity in 

view of the occurrence of thermal stratification, and (2) require addressees to inform the NRC 

staff of the actions taken to resolve this issue.

The applicant stated that its pressurizer surge line is 14-inch diameter, schedule 160 piping, 

SA 376 Type 316, except the long-radius elbow, which is SA 376 Type 304, and that the surge 

line design was reanalyzed to the 1986 ASME Code in response to NRC Bulletin 88-11. This 

analysis was later reevaluated for effects of snubber removals, and the results of these 

analyses have been incorporated into the piping and main-loop nozzle code design reports. 

Furthermore, the LRA states that the analysis of thermal stratification effects at Callaway 

evaluated the following locations: 

Hot Leg Surge Nozzle: Westinghouse performed stress analyses of the reactor 

coolant loop (RCL) branch nozzles, including the effects of thermal stratification. 
TIME-LIMITED AGING ANALYSES

4-49

The fatigue result for the [35.6-cm] 14-in. pressurizer surge nozzle on hot leg 

loop 4 is 0.30, as shown in [LRA] Table 4.3-3, “ASME Class 1 Fatigue Analyses 

under the Fatigue Monitoring Program.” 

Pressurizer Surge Line: Westinghouse performed stress analyses of the 

auxiliary piping systems connected to the RCL, including the effects of thermal 

stratification. The fatigue result for the [35.6-cm] 14-in. pressurizer surge line is 

0.099, as shown in [LRA] Table 4.3-3, “ASME Class 1 Fatigue Analyses under 

the Fatigue Monitoring Program.”

The applicant dispositioned the TLAA for the revised fatigue analysis of the pressurizer surge 

line for thermal cycling and stratification, in accordance with 10 CFR 54.21(c)(1)(iii), that the 

effects of metal fatigue, including thermal cycling and stratification, on the intended functions will 

be adequately managed by the Fatigue Monitoring Program for the period of extended 

operation.

4.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.4 and the TLAA associated with the revised fatigue 

analysis of the pressurizer surge line for thermal cycling and stratification to verify, in 

accordance with 10 CFR 54.21(c)(1)(iii), that the effects of fatigue will be adequately managed 

by the Fatigue Monitoring Program for the period of extended operation.

The staff reviewed the applicant’s TLAAs associated with the revised fatigue analysis of the 

pressurizer surge line for thermal cycling and stratification and the corresponding disposition of 

10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR Section 4.3.3.1.1.3. 

These procedures state that the reviewer should verify the appropriateness of the applicant’s 

program for monitoring and tracking the number of critical thermal and pressure transients for 

the selected RCS components.

The staff noted that, to address NRC Bulletin 88-11, the 35.6-cm (14-in.) pressurizer surge line 

design was reanalyzed to the 1986 ASME Code in response to the thermal stratification 

concerns. 

The staff noted that the applicant’s response to Question 11 in “Callaway Plant Application of 

Proprietary Leak-Before-Break Methodology Reports and Draft Regulatory Guide DG-1108,” 

(nonproprietary letter) dated December 9, 2003 (ADAMS Accession No. ML033530468) stated 

that the value of the maximum ASME Code Section III, Class 1, CUF of the pressurizer surge 

line previously calculated under the effects of thermal stratification is 0.4. However, LRA 

Section 4.3.2.4 indicates that the fatigue results, including the effects of thermal stratification, for 

the 35.6-cm (14-in.) pressurizer surge nozzle on hot leg loop 4 and the 35.6-cm (14-in.) 

pressurizer surge line are 0.3 and 0.099, respectively. In addition, LRA Table 4.3-7, as 

amended by letter dated May 3, 2012, also indicates a CUF value of 0.3 for the surge line (hot 

leg surge nozzle). Based on the reported CUF values in the LRA, including LRA Amendment 2 

by letter dated May 3, 2012, and the applicant's response letter, dated December 9, 2003, it is 

not clear to the staff if the CUF values are referring to the same or different locations of the 

pressurizer. 

By letter dated September 6, 2012, the staff issued RAI 4.3-6, Part (a), requesting that the 

applicant clarify the specific locations that are represented by the CUF values of 0.099, 0.3, and 

0.4. In addition, the staff requested in RAI 4.3-6, Part (b), that the applicant provide the basis 

for recording a lower CUF value in LRA Section 4.3.2.4 and LRA Table 4.3-7, as amended by 
TIME-LIMITED AGING ANALYSES

4-50

letter dated May 3, 2012, if the CUF value of 0.4 refers to the same location as the 35.6-cm 

(14-in.) pressurizer surge nozzle on hot leg loop 4.

In its response to RAI 4.3-6, Part (a), dated October 11, 2012, the applicant clarified that the 

CUF values are associated with the pressurizer surge line and hot leg surge nozzles. 

Specifically, the applicant stated that the CUF value of 0.099 represents the maximum CUF in 

the surge line piping (i.e., locations between the two terminal ends that include the hot leg surge 

nozzle and pressurizer surge nozzle). Furthermore, the CUF value of 0.3 represents the hot leg 

surge nozzle and the CUF value of 0.4 represents the weld between the surge line piping and 

pressurizer surge nozzle.

The applicant clarified in response to RAI 4.3-6, Part (b), that the CUF value of 0.4, which was 

reported in the letter dated December 9, 2003, was the result of a supplement to its initial NRC 

Bulletin 88-11 analysis. Furthermore, the applicant clarified that a structural weld overlay was 

applied to this weld in 2007 and a fatigue crack growth analysis was performed in accordance 

with ASME Code Section XI. The staff confirmed that the applicant identified this fatigue crack 

growth analysis of the structural weld overlay as a TLAA in LRA Section 4.7.2. The staff’s 

evaluation of the applicant’s disposition for the fatigue crack growth analysis of the structural 

weld overlay is documented in SER Section 4.7.2.2.

The staff finds the applicant’s response to RAI 4.3-6 acceptable because the locations of the 

pressurizer associated with the CUF values identified by the staff were clarified, and the 

applicant reported the bounding CUF values in LRA Section 4.3.2.4 and LRA Table 4.3-7 for the 

pressurizer. In addition, the staff finds it appropriate that, since a structural weld overlay was 

applied and a fatigue crack growth analysis was performed for the pressurizer surge nozzle, the 

CUF value of 0.4 is no longer the licensing or design basis for this location. The staff’s concern 

described in RAI 4.3-6 is resolved.

The staff noted that although the CUF values for the hot leg surge nozzle and pressurizer surge 

line, including the effects of thermal stratification, are significantly less than the design limit 

of 1.0, the applicant has proposed to conservatively manage fatigue of these components with 

its Fatigue Monitoring Program. The staff’s review of the applicant’s Fatigue Monitoring 

Program is documented in SER Section 3.0.3.2.22. The staff determined that the program 

includes three monitoring methods (cycle counting, CBF, and SBF monitoring) that are capable 

of managing metal fatigue during the period of extended operation. The staff also determined 

that the monitoring methods progressively provide a more refined monitoring approach to 

manage metal fatigue to ensure that the applicable allowable design limits are not exceeded. 

The staff determined that these characteristics of the applicant’s Fatigue Monitoring Program 

are consistent with GALL Report AMP X.M1.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of metal fatigue on the intended functions of the pressurizer surge line and hot leg 

surge nozzle will be adequately managed for the period of extended operation. Additionally, it 

meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting 

its Fatigue Monitoring Program to manage metal fatigue to ensure that the allowable design 

limits on fatigue usage are not exceeded during the period of extended operation; otherwise, the 

applicant will take corrective actions, in accordance with its program.

4.3.2.4.3 FSAR Supplement

LRA Section A3.2.1.4 provides the FSAR supplement summarizing the revised fatigue analysis 

of the pressurizer surge line for thermal cycling and stratification. The staff reviewed LRA 
TIME-LIMITED AGING ANALYSES

4-51

Section A3.2.1.4, consistent with the review procedures in SRP-LR Section 4.3.3.2, which state 

that the reviewer verifies that the applicant has provided information to be included in the FSAR 

supplement that includes a summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address revised fatigue 

analysis of the pressurizer surge line for thermal cycling and stratification, as required by 

10 CFR 54.21(d).

4.3.2.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on 

the intended functions of the pressurizer surge line will be adequately managed by the Fatigue 

Monitoring Program for the period of extended operation. The staff also concludes that the 

FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.3.3 ASME Section III, Subsection NG, Fatigue Analysis of Reactor Pressure Vessel 

Internals

4.3.3.1 Summary of Technical Information in the Application

LRA Section 4.3.3 states that the RVIs were designed after the incorporation of Subsection NG 

into the 1974 Edition (no addenda) of ASME Code Section III. Plants designed after the 

incorporation of the Subsection NG have complete fatigue analyses of RVI component low-cycle 

and high-cycle fatigue usage. Thus, the Callaway RVIs meet Subsection NG in full. 

Specifically, for the RVI design basis for low-cycle fatigue, the LRA states that analyses of 

record for Callaway were confirmed to continue to satisfy the ASME Code Subsection NG 

requirements. The fatigue analyses were performed using the 40-year design transients in 

FSAR Table 3.9(N)-1 SP. The baffle, former, and barrel assemblies were qualified by fatigue 

tests, in accordance with ASME Code Section III, Subsection NG, Article II-1221 for the number 

of cycles and severity required by the design specification. The fatigue tests were used in lieu 

of a fatigue analysis; therefore, no CUF exists for these components. Maintaining those 

components within specified numbers of transients will ensure the tests remain valid. 

The applicant dispositioned the TLAA for the RVIs, in accordance with 10 CFR 54.21(c)(1)(iii), 

that the effects of metal fatigue on the intended functions will be adequately managed by the 

Fatigue Monitoring Program for the period of extended operation.

The LRA also states that protection from flow-induced vibration is ensured by satisfying the 

requirements of RG 1.20, as discussed in FSAR Sections 3.9(N).2.3, 3.9(N).2.4, and 

3.9(N).2.6 SP, and includes the results of experimental tests and analyses. The applicant 

reviewed the supporting references and did not identify any dependence on time. The 

high-cycle fatigue and flow-induced vibration stresses were not considered in the calculation of 

the CUFs for the components because the vibratory stresses are very small compared to 

thermal transient stresses, and the usage from high-cycle effects is insignificant. The applicant 

stated that the evaluation of high-cycle vibrational loads does not depend on the licensed period 

and is not a TLAA in accordance with 10 CFR 54.3(a), criterion 3. Furthermore, the LRA states 
TIME-LIMITED AGING ANALYSES

4-52

that the PWR Vessel Internals Program will address the aging effects in the reactor internal 

components, including those that could be induced by a flow-induced vibration mechanism.

In addition, the LRA states that a review of the Callaway licensing basis did not identify a 

40-year embrittlement analysis for RVIs.

4.3.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.3 and the TLAA for the fatigue design of the ASME Code 

Section III Subsection NG RPV internals to verify, in accordance with 10 CFR 54.21(c)(1)(iii), 

that the effects of fatigue will be adequately managed by the Fatigue Monitoring Program for the 

period of extended operation.

The staff reviewed the applicant’s metal fatigue TLAAs for the RVIs and the corresponding 

disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR 

Section 4.3.3.1.1.3. These procedures state that the reviewer should verify the appropriateness 

of the applicant’s program for monitoring and tracking the number of critical thermal and 

pressure transients for the selected RCS components.

The staff noted that the fatigue analyses were performed using the 40-year design transients in 

FSAR Table 3.9(N)-1 SP, which are those transients listed in LRA Table 4.3-2 and monitored by 

the Fatigue Monitoring Program. In addition, the staff noted that the baffle, former, and barrel 

assemblies were qualified by fatigue tests in accordance with ASME Code Section III, 

Subsection NG, Article II-1221 for the number of cycles and severity required by the design 

specification; therefore, no CUF exists for these components. The staff noted that the transients 

used in these fatigue waivers specified by the design specification are the same transients 

discussed in the applicant’s FSAR.

The staff reviewed LRA Table 4.3-5, which provides the CUF values for the RVIs, and noted 

that the 40-year CUF values were less than the ASME Code design limit of 1.0. The staff noted 

that the applicant monitors the transients used in the fatigue analysis and qualification tests of 

the RVIs with its Fatigue Monitoring Program. The staff determined that the program includes 

three monitoring methods (cycle counting, CBF monitoring, and SBF monitoring) that are 

capable of managing metal fatigue during the period of extended operation. The staff also 

determined that the monitoring methods progressively provide a more refined monitoring 

approach to manage metal fatigue to ensure that the applicable allowable design limits are not 

exceeded. The staff determined that these characteristics of the applicant’s Fatigue Monitoring 

Program are consistent with GALL Report AMP X.M1. The staff’s evaluation of the Fatigue 

Monitoring Program is documented in SER Section 3.0.3.2.22.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of aging related to fatigue analysis of the RVIs will be adequately managed for the 

period of extended operation. Additionally, the applicant's disposition meets the acceptance 

criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting its Fatigue Monitoring 

Program, which the staff determined in SER Section 3.0.3.2.22 is consistent with GALL Report 

AMP X.M1, to manage metal fatigue to ensure that the allowable design limits on fatigue usage 

are not exceeded during the period of extended operation; otherwise, the applicant will take 

corrective actions, in accordance with its program.

The applicant stated that protection from flow-induced vibration is ensured by satisfying the 

requirements of RG 1.20, as discussed in FSAR Sections 3.9(N).2.3, 3.9(N).2.4, and 

3.9(N).2.6 SP, and includes the results of experimental tests and analyses. The staff noted that 
TIME-LIMITED AGING ANALYSES

4-53

an analysis is only defined as a TLAA if all six criteria outlined in 10 CFR 54.3 are satisfied. The 

staff reviewed the FSAR and did not identify that design basis for the RVIs for high-cycle fatigue 

is dependent on the licensed life of the plant period. Thus, the staff finds that all six criteria for a 

TLAA were not met for the applicant’s evaluation of high-cycle fatigue for the RVIs. The staff 

finds the applicant’s determination that high-cycle fatigue of the RVIs is not a TLAA to be 

acceptable. Although high-cycle fatigue of the RVIs is not evaluated in the application as a 

TLAA, the staff noted that the applicant’s PWR Vessel Internals Program addresses the aging 

effects in the reactor internal components, including those that could be induced by a 

flow-induced vibration mechanism. The staff’s evaluation of the PWR Vessel Internals Program 

is documented in SER Section 3.0.3.1.5.

In addition, the LRA states that the applicant’s review of its licensing basis did not identify a 

40-year embrittlement analysis for RVIs. As described in the staff’s evaluation of this absence 

of a TLAA in SER Section 4.1.2.1.2, the staff noted that SRP-LR Section 3.1.2.2.3.3 states that 

“Ductility – Reduction in Fracture Toughness” is a plant-specific TLAA for B&W reactor internals 

to be evaluated for the period of extended operation, in accordance with the staff’s safety 

evaluation concerning Babcock and Wilcox Owners Group report number BAW-2248 (ADAMS 

Accession No. ML993490303). The staff reviewed the FSAR and confirmed that the applicant’s 

CLB does not contain or reference a 40-year embrittlement analysis for RVIs. In addition, the 

staff determined that BAW-2248A is not applicable to the applicant because it is a 

Westinghouse-designed PWR. The staff also noted that the applicant’s PWR Vessel Internal 

Program manages loss of fracture toughness and reduced material ductility for its RVIs. The 

staff’s evaluation of the PWR Vessel Internal Program is documented in SER Section 3.0.3.1.5.

4.3.3.3 FSAR Supplement

LRA Section A3.2.2 provides the FSAR supplement summarizing the metal fatigue TLAA for the 

RVIs. The staff reviewed LRA Section A3.2.2 consistent with the review procedures in SRP-LR

Section 4.3.3.2, which state that the reviewer verifies that the applicant has provided information 

to be included in the FSAR supplement that includes a summary description of the evaluation of 

the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is, therefore, acceptable. Additionally, the staff determines that 

the applicant provided an adequate summary description of its actions to address the metal 

fatigue TLAA for the RVIs, as required by 10 CFR 54.21(d).

4.3.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on 

the intended functions of the RVIs will be adequately managed by the Fatigue Monitoring 

Program for the period of extended operation. The staff also concludes that the FSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d).
TIME-LIMITED AGING ANALYSES

4-54

4.3.4 Effects of Reactor Coolant System Environment on Fatigue Life of Piping and 

Components (Generic Safety Issue 190)

4.3.4.1 Summary of Technical Information in the Application

LRA Section 4.3.4, as amended by letter dated May 3, 2012, states that LRA Table 4.3-6, 

“Summary of Fatigue Usage Factors at NUREG/CR-6260 Sample Locations,” is a summary of 

EAF of the NUREG/CR-6260 locations. The LRA states that the Fen relationships are calculated 

from NUREG/CR-6583 for carbon and low-alloy steels and from NUREG/CR-5704 for stainless 

steels, as appropriate for the material at each of these locations. The LRA further states that all 

of the locations specified in NUREG/CR-6260 for newer-vintage Westinghouse plants listed in 

Table 4.3-6 will be monitored by the Fatigue Monitoring Program. 

The applicant dispositioned the evaluations associated with EAF of the NUREG/CR-6260 

locations for a newer vintage Westinghouse plant in accordance with 10 CFR 54.21(c)(1)(iii),

that the effects of environmentally assisted fatigue on the intended functions will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation.

LRA Section 4.3.4, as amended by letter dated May 3, 2012, states that, to ensure that the 

limiting plant-specific EAF locations are identified, it performed a systematic review of all wetted 

RCPB components with an ASME Code Section III Class 1 fatigue analysis. This was done 

either to show that the NUREG/CR-6260 locations are bounding or to incorporate EAF into the 

licensing basis for those more limiting components. The LRA indicates that the methods in 

NUREG/CR-5704 (for austenitic stainless steels), NUREG/CR-6583 (for carbon and low-alloy 

steels), and NUREG/CR-6909 (for Ni-Cr-Fe steels) were used in calculating the Fen factors

LRA Table 4.3-7, “Sentinel Locations for EAF Monitoring,” identifies the final locations, including 

the NUREG/CR-6260 locations, that will be used as sentinel locations during the period of 

extended operation to manage EAF. The LRA states that those non-NUREG/CR-6260 

locations with an EAF CUF greater than 1.0 will be evaluated further using the same methods 

as those used to remove conservatisms for the NUREG/CR-6260 locations. The results of 

these final analyses will be incorporated into the Fatigue Monitoring Program by either counting 

the transients assumed or incorporating the stress intensities into a CBF or SBF portion of the

program. The applicant dispositioned the evaluations associated with EAF of the 

non-NUREG/CR-6260 locations in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of 

EAF on the intended functions will be adequately managed by the Fatigue Monitoring Program 

for the period of extended operation.

4.3.4.2 Staff Evaluation 

The staff noted that the applicant addressed the effects of the reactor coolant environment on 

component fatigue life, consistent with the guidance in the SRP-LR and the staff’s 

recommendations for resolving Generic Safety Issue No. 190 (GSI-190), dated 

December 26, 1999. The staff also noted that, consistent with Commission Order 

No. CLI-10-17, dated July 8, 2010, the evaluations associated with the effects of the reactor 

coolant environment on component fatigue life are not TLAAs in accordance with the definition 

of 10 CFR 54.3(a) because these evaluations are not in the applicant’s CLB. Nevertheless, the 

applicant has credited its Fatigue Monitoring Program to manage the effects of reactor coolant 

environment on component fatigue life. Therefore, the staff reviewed LRA Section 4.3.4 and the 

evaluations for EAF to confirm, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of 

reactor coolant environment on component fatigue life will be adequately managed for the 

period of extended operation.
TIME-LIMITED AGING ANALYSES

4-55

The staff reviewed the applicant’s EAF evaluations, as presented in the LRA and the 

corresponding disposition, consistent with the review procedures in SRP-LR Section 4.3.3.1.3, 

which state that the reviewer should confirm that the applicant has addressed the effects of the 

coolant environment on component fatigue life as AMPs are formulated in support of license 

renewal. SRP-LR Section 4.3.3.1.3 states that “if an applicant has chosen to assess the impact 

of the reactor coolant environment on a sample of critical components, the reviewer verifies 

[that] the critical components include a sample of high-fatigue usage locations.” SRP-LR

Section 4.3.3.1.3 also states that this sample of critical components with high-fatigue usage 

locations should include the locations identified in NUREG/CR-6260, as a minimum, as well as 

additional locations based on plant-specific considerations.

LRA Section 4.3.4 states that the NUREG/CR-6260 locations in LRA Table 4.3-6 with an EAF 

CUF below 1.0, when using the design basis CUF and the maximum Fen, require no further 

analysis. The staff reviewed LRA Table 4.3-6 and noted that these locations, which are all 

fabricated of low-alloy steel, include the RPV lower head to shell juncture, RPV inlet nozzle, and 

RPV outlet nozzle. The staff noted that the Fen value used for these locations was 2.45 and 

calculated using the NUREG/CR-6583. The staff noted that this is the maximum Fen value for 

low-alloy steel components exposed to a PWR reactor coolant, which is a low-oxygen 

environment. The staff noted that the applicant’s Water Chemistry Program maintains reactor 

coolant system hydrogen level to ensure that the PWR reactor coolant remains a low oxygen 

environment. Based on the applicant’s plant operation and Water Chemistry Program, the staff 

finds the applicant’s use of this Fen value appropriate for these low-alloy steel components.

LRA Section 4.3.4 states that the remaining NUREG/CR-6260 locations were re-evaluated with 

a refined fatigue analysis using NB-3200 methods in a three-dimensional (3-D) finite element 

analysis model using the design number of transients to reduce the CUF values. Furthermore, 

after this reanalysis the RHR inlet transition was the only location to pass the EAF CUF criterion 

of 1.0. The staff finds the use of NB-3200 methods in a 3-D finite element analysis model to 

reduce the RHR inlet transition EAF CUF to less than 1.0 acceptable because the use of 

NB-3200 is consistent with ASME Code Section III and the use of a 3-D finite element analysis 

model provides a more refined model to address the response of the component from the 

applied stress.

The staff noted that the RPV lower head to shell juncture, RPV inlet nozzle, RPV outlet nozzle 

and RHR inlet transition will be monitored by the CBF monitoring method of the Fatigue 

Monitoring Program, as indicated in LRA Table 4.3-1. Since these locations are monitored with 

CBF, the staff noted that the EAF CUF will be updated as transients occur. In addition, this 

provides an up-to-date cumulative fatigue usage of the component that is based on the design 

usage contribution for each transient occurrence. The staff finds the Fatigue Monitoring 

Program is capable of managing the EAF CUF of the RPV lower head to shell juncture, RPV 

inlet nozzle, and RPV outlet nozzle below 1.0. The staff’s review of the CBF monitoring method 

and the Fatigue Monitoring Program are documented in SER Section 3.0.3.2.22.

LRA Section 4.3.4 states that there are two options available to further reduce the EAF CUFs 

for the charging system nozzles, safety injection nozzles, and hot leg surge line nozzle that 

include calculating a strain-rate dependent Fen and/or calculating a CUF based on the 60-year 

projected number of transient events. The staff’s evaluation of each option is discussed below.

The strain-rate dependent Fen values are calculated for the significant load set pairs in the 

fatigue analyses using the integrated strain-rate method. The staff noted that the integrated 

strain-rate approach to determine the Fen values is rigorous because the strain-rate is computed 
TIME-LIMITED AGING ANALYSES

4-56

for multiple points along the tensile portion of the paired strain range resulting in a more refined 

Fen value. The staff finds the applicant’s approach to determine strain-rate dependent Fen

values reasonable because it used the strain-rate and water temperature that were calculated 

from the design transient specifications and stress analyses, which allows for a more refined 

value.

The applicant stated that load set pairs that produce no significant stress range or fatigue 

contribution were assigned the maximum Fen for the material. Since the applicant used the 

maximum Fen for load set pairs that produce no significant stress range or fatigue contribution, 

the staff finds this conservative. The LRA indicates that a dissolved oxygen content of less than 

0.05 ppm was assumed, which corresponds to a low-oxygen environment, for the charging 

system nozzles, safety injection nozzles, and hot leg surge line nozzle. The staff noted that 

these components are fabricated from stainless steel, thus, the use of a low dissolved oxygen 

environment yields higher Fen values, which the staff finds conservative.

The LRA indicates that, even with the use of the strain-rate dependent Fen values, the results for 

EAF CUF of the charging system nozzles, safety injection nozzles, and hot leg surge line nozzle 

were still greater than 1.0. The staff noted that the numbers of transients projected to 60 years 

of operation as provided in LRA Table 4.3-2 were used in order to further refine the EAF CUF 

values to less than 1.0. The staff’s review of the applicant’s 60-year projection methodology is 

documented in SER Section 4.3.1.2.2.

LRA Section 4.3.4 states that if the cycle count for a transient is not projected, then the full 

number of design basis events is used, with the exception of two transients, “inadvertent safety 

injection” and “loss of power” events, which were analyzed based on the number of events that 

occurred as of 2011. The LRA further states that the only EAF CUF calculation that is 

significantly affected by these transients is the safety injection nozzle. The staff noted that the 

projected safety injection nozzle EAF CUF is 0.74 and is monitored by the CBF monitoring 

method of the Fatigue Monitoring Program, as indicated in LRA Table 4.3-1. This location is 

analyzed for the numbers of “inadvertent safety injection” and “loss of power'' events to date, 

since it is monitored with CBF, which updates the EAF CUF and will be updated as additional 

events occur. Thus, the staff finds the Fatigue Monitoring Program is capable of managing the 

EAF CUF of the safety injection nozzle less than 1.0. The staff’s review of the CBF monitoring 

method and the Fatigue Monitoring Program are documented in SER Section 3.0.3.2.22.

The staff noted that, with the use of 60-year cycle projections and strain-rate dependent Fen 

values, the calculated hot leg surge line nozzle EAF CUF is 0.765. The staff noted that this 

location is being monitored by the cycle counting method of the Fatigue Monitoring Program. 

The staff’s review of the cycle counting method and the Fatigue Monitoring Program are 

documented in SER Section 3.0.3.2.22. The staff determined that this method will monitor 

transient occurrences to ensure that the number of assumed in transients in the hot leg surge 

line nozzle EAF analysis will not be exceeded through the period of extended operation. 

Otherwise, corrective actions will be taken. The staff finds the use of cycle counting for the hot 

leg surge line nozzle acceptable because it ensures the EAF analysis remains valid or it will 

identify that corrective actions are necessary to prevent the calculated EAF CUF from being 

exceeded.

The staff noted that LRA Table 4.3-3 states that the CUF value for the Class 1 piping of 

“Normal/Alternate Charging - Loops 1 & 4” is 0.93, whereas LRA Table 4.3-7, as amended by 

letter dated May 3, 2012, states that the “Normal Charging Nozzles, Loop 1” and “Alternate 

Charging Nozzles, Loop 4” have CUF values of 0.90. These locations identified in LRA 
TIME-LIMITED AGING ANALYSES

4-57

Table 4.3-7 are the sentinel locations for EAF monitoring for the “Charging” thermal zone within 

the chemical and volume control system (CVCS). Based on the information in the LRA tables, it 

was not clear to the staff why the normal and alternate charging nozzles would bound Class 1 

piping of “Normal/Alternate Charging - Loops 1 & 4,” given that the CUF values of the Class 1 

piping of “Normal/Alternate Charging - Loops 1 & 4” is higher.

By letter dated September 6, 2012, the staff issued RAI 4.3-9 requesting the applicant to 

provide justification that the normal and alternate charging nozzles are sentinel locations for the 

“Charging” thermal zone within the CVCS. As part of the justification, the applicant was 

requested to include the materials, transients experienced, system configuration, water 

chemistry, and other factors when comparing the Class 1 piping and nozzles.

In its response to RAI 4.3-9 dated October 11, 2012, the applicant clarified that the CUF value 

of 0.9 for the charging nozzle was more recently computed in response to high letdown flow, 

which focused exclusively on the charging nozzle, since it was determined to be the controlling 

location. In addition, the applicant stated that the CUF value for the charging nozzle taken from 

the same design report revision as the charging piping CUF value of 0.93 is equal to 0.95. The 

applicant also confirmed that the charging piping and charging nozzle are constructed of 

stainless steel, and that the CUF values of both are based on the same design transients in 

LRA Table 4.3-2 and the same system configuration that rotates between normal and auxiliary 

charging paths.

Since the charging piping and nozzle were fabricated from the same material and experienced 

the same design transients and the same system rotation between normal and auxiliary 

charging paths, the staff finds it reasonable that the charging nozzle that has a higher CUF 

value than that of the charging piping, when compared from the same design report revision, 

represents the bounding location for considering EAF. The staff finds the applicant’s response 

acceptable because the applicant gave sufficient justification, as described above, that the 

charging nozzle was appropriately selected as the “sentinel location” for considering EAF for the 

charging zone of the CVCS. The staff’s concern described in RAI 4.3-9 is resolved.

The staff noted that, in some instances, multiple loops on a particular system may have the 

same CUF value, and in other instances, they have different CUF values; thus, the basis for 

multiple loops having the same CUF value is not clear. The LRA did not annotate or explain if 

the CUF values, for entries of multi-loop systems in LRA Tables 4.3-3 to 4.3-7, are intended to 

demonstrate that the CUF value of one loop bounds the “calculated” CUF value of another, or to

demonstrate that the CUF value of one loop represents all other identical or less limiting loops. 

Without a clear indication of the CUF values of multi-loop systems, the staff cannot confirm the 

applicant’s conclusion that LRA Table 4.3-7 identifies the final locations, including the 

NUREG/CR-6260 locations that will be used as sentinel locations during the period of extended 

operation to manage EAF.

By letter dated September 6, 2012, the staff issued RAI 4.3-7 requesting the applicant to identify 

any components or locations in LRA Tables 4.3-3 to 4.3-7 for which the CUF value in the 

design-basis calculation is the same for each loop in a multi-loop system. In addition, the 

applicant was requested to identify any components or locations in the aforementioned LRA 

Tables for which (1) a CUF value of one loop was used to bound any “calculated” CUF values of 

another loop in a multi-loop system, including a basis for each circumstance and (2) the CUF 

value of one loop represented all other identical or less limiting loops, including a basis for each 

circumstance.
TIME-LIMITED AGING ANALYSES

4-58

In its response to RAI 4.3-7 dated October 11, 2012, the applicant provided a list of 10 systems 

with multiple loops from LRA Table 4.3-3 and 4 systems with multiple loops from LRA 

Table 4.3-7 in which the maximum CUF value from the design basis calculation is the same for 

each loop in a multi-loop system. The applicant confirmed that each loop from these systems 

has been independently analyzed for fatigue. Since the applicant confirmed that each loop of 

these systems were independently analyzed for fatigue and the maximum CUF value from the 

design basis calculation is the same for each loop, the staff finds the locations and CUF values 

identified in LRA Tables 4.3-3 and 4.3-7 to be appropriate.

The applicant stated in its response that the maximum CUF for the “Spray/Aux. Spray Loop 

1 & 2” location in LRA Table 4.3-3 was used to bound all CUF values in this multi-branch 

system. The applicant also explained that the location of the maximum CUF of 0.84 is in the 

common section of piping leading to the pressurizer spray nozzle. Since the location of the 

maximum CUF value is shared by both loops on a common section of piping, the staff finds it 

reasonable that this CUF value of 0.84 was used to represent this multi-branch system. 

The applicant stated that the maximum CUF for the “Pressurizer Safety and Relief Valve Piping” 

location in LRA Tables 4.3-3 and 4.3-6 was used to bound all CUF values in this multi-branch 

system. The applicant indicated that the maximum CUF of 0.975 is in the safety valve piping 

and the maximum CUF in the relief valve piping is 0.970. The staff reviewed FSAR 

Section 5.1.3 and noted that the pressurizer safety and relief valve piping share similar functions 

and, thus, experience similar thermal transients. In addition, the staff noted in LRA Table 4.3-7 

that the pressurizer safety and relief valve piping are fabricated of stainless steel. Since these 

systems experience similar transients and are fabricated of the same material, the staff finds it 

reasonable that the maximum CUF of 0.975 for the safety valve piping was used to be 

representative of this multi-branch system.

The applicant provided a list of components, with associated CUF values, for components 

and/or locations in LRA Tables 4.3-3, 4.3-4, 4.3-6 and 4.3-7 in which one model represents 

multiple plant locations. The applicant clarified that these components and/or locations that 

represent multiple plant locations have identical geometry, material, and the thermal transients 

for the locations that share the analyses. Thus, the staff finds it reasonable for these 

components that one CUF value is representative of identical components and/or locations.

The staff finds the applicant’s response acceptable because the applicant clarified and provided 

sufficient justifications, as described above, (1) when a CUF value in the design-basis 

calculation is the same for each loop in a multi-loop system; (2) when a CUF value of one loop 

was used to bound the “calculated” CUF values of another loop; and (3) when a CUF value of 

one loop represented all other identical or less limiting loops. In addition, the clarification assists 

the staff in determining if the applicant selected the appropriate “sentinel” locations to manage 

EAF, as discussed below. The staff’s concern described in RAI 4.3-7 is resolved.

The staff noted that the projected normal and alternate charging nozzles EAF CUFs based on 

the SBF algorithm are 0.57 and 0.53, respectively. The LRA states that the SBF usage factors 

were benchmarked against NB-3200 methods consistent with RIS 2008-30, as discussed in 

LRA Section 4.3.1.1. The staff’s review of the applicant’s benchmarking evaluation for the 

normal and alternate charging nozzles is documented in SER Section 4.3.1.1.2. The staff 

determined that the benchmarking evaluation for the normal and alternate charging nozzles 

demonstrated that SBF can be used for these nozzles and that the concerns identified in 

RIS 2008-30 are not applicable for these nozzles. The staff’s review of the SBF monitoring 

method and the Fatigue Monitoring Program is documented in SER Section 3.0.3.2.22. The 
TIME-LIMITED AGING ANALYSES

4-59

staff determined that the SBF monitoring method periodically calculates cumulative fatigue 

usage based on the conditions that are actually occurring at the applicant’s site during 

transients to ensure the design limit is not exceeded through the period of extended operation.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of EAF on the intended functions of the NUREG/CR-6260 locations for a newer 

vintage Westinghouse plant will be adequately managed for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.3 because the applicant 

has demonstrated that its Fatigue Monitoring Program with the use of the cycle counting, CBF, 

and SBF monitoring methods, as described above, is capable of managing EAF to ensure that 

the allowable design limits on fatigue usage are not exceeded during the period of extended 

operation; otherwise, the applicant will take corrective actions in accordance with its program.

LRA Section 4.3.4, as amended by letter dated May 3, 2012, states that the CUF for wetted 

RCPB locations were categorized based on the strain rate of the dominant transient, which was 

determined with a qualitative assessment based on experience and not a quantitative stress 

analysis. In addition, it states that this estimated strain rate was used to calculate an estimated 

Fen. This estimated Fen was then averaged with the maximum Fen for that material type to 

calculate the average Fen, which was used with the design basis CUFs to calculate the 

estimated EAF CUF. The LRA indicated that the estimated Fen value was based on 

NUREG/CR-5704 for austenitic stainless steels, NUREG/CR-6583 for carbon and low alloy 

steels and NUREG/CR-6909 for Ni-Cr-Fe steels. These estimated EAF CUFs were then 

organized according to their system, thermal zone, and material type. LRA Section 4.3.4 

defines a thermal zone as a collection of piping and/or vessel components which undergo 

essentially the same group of thermal and pressure transients during plant operations.

The staff noted that since the estimated strain rate was determined based on a qualitative 

assessment, judgment of the appropriate strain rate must be made based on knowledge of, at a 

minimum, the transient, system and/or thermal zone in question. However, the applicant did not 

provide the details of how this qualitative assessment was performed for its plant nor was it 

justified that this approach was appropriate or conservative for its plant. In addition, the staff 

noted that since the estimated EAF CUFs were organized according to their system, thermal 

zone and material type, to have a meaningful comparison of the EAF CUFs, it is important that 

the CUFs were assessed similarly (e.g., amount of rigor in calculating CUF) and used the same 

fatigue curves in ASME Code, Section III, Appendix I.

In addition, the staff noted that LRA Section 4.3.4, as amended by letter dated May 3, 2012, 

indicates that an initial screening list may have been reduced by using one of the following 

methods:

• One thermal zone can bound another thermal zone in a system.

• One material in a thermal zone can bound other materials in the same thermal zone.

• One material in a thermal zone can bound other materials in another thermal zone.

Since the initial screening list may have been reduced by using one of the methods described 

above, which is based on the CUF, Fen, thermal zone and material type, the staff noted that to 

have a meaningful comparison to screen EAF CUFs, it is important that the CUFs were 

assessed similarly (i.e., amount of rigor in calculating CUF) and used the same fatigue curves in 

ASME Code Section III, Appendix I. In addition, the applicant did not provide specific examples 

of how/when these methods were used to reduce the initial screening list; therefore, it is not 
TIME-LIMITED AGING ANALYSES

4-60

clear how each method was applied and a basis was not provided to support that these 

methods are appropriate and conservative.

Therefore, by letter dated September 6, 2012, the staff requested the applicant in RAI 4.3-20, 

Part (a), to describe the qualitative assessment that was used to categorize the CUF for wetted 

RCPB locations based on the strain rate of the dominant transient and provide the basis that 

this assessment is appropriate or conservative for the Callaway plant.

In its response dated October 11, 2012, the applicant stated a qualitative estimate of the strain 

rate for the controlling fatigue transient(s) was determined based on experience with its 

corresponding plant system, and these categorizations of strain rate were guided by transient 

descriptions described in system design documents. In addition, based on experience with 

fatigue analyses of many plant components, a strain-rate category was selected to represent 

each component. The applicant explained that this selection was based on ranking the 

identified transients that would govern the CUF of the component with respect to how quickly 

the maximum and minimum stress states would be established. 

The staff finds it appropriate that the categorization of strain rate was based on plant-specific 

experience from the corresponding plant system and the transient descriptions from the system 

design documents. The staff also finds the ranking with respect to how quickly the maximum 

and minimum stress states are established to be acceptable because it establishes an 

estimated Fen value for the component that supports the calculation of reasonable average Fen 

values, which is further discussed below, used to identify potential EAF monitoring locations. 

RAI 4.3-20, Part (a), is resolved.

In addition, by letter dated September 6, 2012, the staff requested the applicant in RAI 4.3-20, 

Part (b), to provide the reason that the method for calculating the average Fen (i.e., average of 

the estimated Fen and the maximum Fen for the material type) is appropriate and conservative for 

the plant-specific conditions. 

In its response dated October 11, 2012, the applicant stated the average Fen (average of the 

estimated Fen and maximum Fen) is appropriate and conservative because the two-part average 

Fen is based on experience with performing detailed Fen analyses. The applicant explained that, 

in general, the effective Fen from a detailed analysis is similar to the Fen value computed for just 

the controlling transient pairs, but only slightly offset due to contributions from the 

less-significant fatigue pairs. Thus, the applicant determined that choosing an average Fen 

halfway between the estimated Fen and the maximum Fen for a given material provides 

assurance that the average Fen is higher than the effective Fen. In addition, the applicant stated 

that the resulting estimated Uen values are compared to a conservative threshold value of 0.8 for 

inclusion in the ranking of EAF monitoring locations. 

The staff noted that LRA Section 4.3.4, as amended by letter dated April 26, 2013, states that 

the estimated Fen is based on assuming a low dissolved oxygen environment, the maximum 

fluid/metal temperature, and maximum sulfur concentration, and is based on the methods in 

NUREG/CR-5704 (stainless steels and nickel alloys) and NUREG/CR-6583 (carbon and 

low-alloy steel). The staff finds the applicant’s assumptions for dissolved oxygen to be 

appropriate because the applicant’s water chemistry program maintains a low-dissolved oxygen 

environment. In addition, the staff finds the applicant’s assumption on fluid/metal temperature 

and sulfur concentration to be conservative because the use of maximum values will result in a 

larger Fen value.
TIME-LIMITED AGING ANALYSES

4-61

The staff finds the applicant’s use of an average Fen in the ranking of EAF monitoring locations 

reasonable and acceptable because (1) in general, the average Fen is greater than the 

calculated Fen in a detailed EAF analysis, (2) the applicant set a Uen threshold value of 0.8 for 

inclusion into the ranking of EAF monitoring locations, which accounts for the variances in the 

average Fen and the calculated Fen in a detailed EAF analysis, and (3) the applicant made 

appropriate or conservative assumptions for dissolved oxygen, fluid/metal temperature and 

sulfur concentration in the calculation of Fen values, as described above. RAI 4.3-20, Part (b), is 

resolved.

Furthermore, by letter dated September 6, 2012, the staff requested the applicant in RAI 4.3-20, 

Part (c), to provide the basis for ranking or comparing the EAF CUFs to one another to 

determine an EAF monitoring location if EAF CUFs (1) were not organized according to their 

system, thermal zone, and material type; (2) were not assessed similarly (e.g., amount of rigor 

in calculating CUF); and (3) did not use the same fatigue curves in ASME Code Section III 

Appendix I in order to provide a meaningful comparison.

In its response dated October 11, 2012, the applicant explained that, based on the ASME Code 

edition used in the fatigue analyses, it assumed that the same fatigue curves for each material 

used for the analyses were relied upon for the screening process. In addition, the applicant 

explained that the level of analytical rigor by the fatigue analyst was not specifically reviewed; 

however, the CUF values used in the screening were developed from the same generation of 

analyses and are expected to have been performed using the same level of rigor (i.e., elastically 

determined stresses with the same transient list and severity using the same ASME Code, 

Section III, Appendix I fatigue curve). The applicant clarified that no elastic-plastic evaluations, 

which would have skewed the ranking results, were found for these components. The applicant 

determined that, based on analytical experience and engineering judgment, the relative design 

report CUF values of the components indicate that any transient lumping used in the various 

analyses did not skew the screening and ranking results. Thus, a consistent technical basis has 

been used to perform the EAF screening and identify appropriate EAF monitoring locations.

The staff identified four assumptions in the applicant’s response to Part (c) of RAI 4.3-20 by 

letter dated October 11, 2012, and in its response to Part (a) of RAI 4.3-21 (discussed below), 

as revised by letter dated December 13, 2012, that were made when determining the EAF 

locations to be monitored by the Fatigue Monitoring Program. The staff noted that the applicant 

has not demonstrated that the Uen values of its systems were calculated with the same level of 

rigor or conservatism. Without demonstrating that the Uen values share a common calculational 

basis, the staff noted that the resulting ranking and comparisons may not determine the 

appropriate EAF monitoring locations for the Fatigue Monitoring Program. Based on these 

issues, by letter dated March 26, 2013, the staff issued RAIs 4.3-22 through 4.3-27 requesting 

that the applicant provide additional information to demonstrate that the values for 

environmental fatigue usage in its methodology for identifying “sentinel locations” are based on 

a normalized scale, such that the resulting ranking and comparisons are appropriate. The staff 

identified this as Open Item 4.3.4-1. In the discussion that follows, RAIs 4.3-22 through 4.3-27 

and the associated responses are discussed and evaluated in the closure of OI 4.3.4-1.

RAI 4.3-22 requested the applicant, for each assumption identified in the RAI responses and 

any other assumptions made in its EAF screening evaluation, to provide plant-specific situations 

that are based on the applicant’s data and analyses to further justify that these assumptions 

would allow meaningful and valid comparisons among calculated Uen values at the applicant's 

facility. 
TIME-LIMITED AGING ANALYSES

4-62

In its response dated April 26, 2013, to RAI 4.3-22, the applicant stated its use of Assumptions 

#1 through #3 is limited to the same generation of analyses. The applicant also confirmed that 

Assumptions #1 through #4 discussed in its response represent all the assumptions made when 

performing the CUF and Uen comparison to determine EAF monitoring locations. The staff’s 

review of Assumptions #1 through #4 is documented below.

Assumption #1. Same fatigue curve for each material was used for the analyses.

In its response dated April 26, 2013, the applicant stated that all fatigue calculations are 

performed to the ASME Code, although different editions were used. The response to 

RAI 4.3-25 (in a letter dated April 26, 2013, as discussed below) addresses how the ASME 

fatigue curve edition affects the fatigue results. The use of a different fatigue curve (e.g., the 

EAF fatigue curves from NUREG/CR-6909 for Ni-Cr-Fe steels) would be a deviation from the 

ASME Code, which would be recorded in the design reports. The staff noted that a comparison 

of CUF values calculated based on non-ASME and ASME fatigue curves would not be a direct 

comparison and would require additional consideration/evaluation in order to compare them on 

an equivalent basis. The applicant confirmed that no non-ASME fatigue curves were used in its 

plant design; thus, the applicant determined that in the absence of the identification of another 

fatigue curve, the same ASME fatigue curve was used for all components with the same 

generation of analyses. 

The staff finds it appropriate that the applicant considered the type of fatigue curve (i.e., ASME 

or non-ASME) used in the calculation of CUF values and ensured that only ASME fatigue 

curves were used, thus ensuring the ability to compare CUF values for locations of the same 

material without additional consideration/evaluation on an equivalent basis. Therefore, the 

staff’s concern of the potential use of non-ASME fatigue curves and the comparison of CUF 

values calculated based on non-ASME and ASME fatigue curves without additional 

consideration/evaluation is resolved. Further discussion regarding the staff’s review of the 

ASME Code fatigue curves is discussed in its evaluation of RAI 4.3-25.

Assumption #2. The analyses have been performed using the same level of rigor.

In its response to RAI 4.3-22 dated April 26, 2013, the applicant stated that the most important 

aspect of the “level of rigor” is whether an elastic or elastic-plastic fatigue analysis was 

performed and that any deviation from the typical elastic analysis is identified in the design 

report. The applicant explained that when more rigorous elastic-plastic fatigue analyses are 

performed, this is considered in the review; however, the screening is performed using the 

results of the elastic fatigue analysis in order to keep the same “level of rigor” in the comparison. 

The staff noted that the methods to perform an elastic-plastic fatigue analysis and an elastic 

fatigue analysis are very distinct from each other; thus, it is inappropriate to compare CUF 

values calculated from these two types of analyses. The staff also noted that other aspects that 

may impact the “level of rigor” in fatigue analyses are the input transients, and whether they are 

design, actual, or lumped transients, which are addressed in Assumption #3. The applicant 

confirmed that the screening is based on the design-basis analyses which only use the design 

transients. The staff finds it appropriate that the applicant consistently considered CUF values 

that were calculated using an elastic fatigue analysis to ensure that screening and ranking 

results were not artificially skewed based on the distinct calculational methods in an 

elastic-plastic fatigue analysis. Thus, the staff finds its concern associated with fatigue analyses 

using a different “level of rigor” is resolved.

Assumption #3. Any transient lumping used in the various analyses has not skewed the 

screening and ranking results.
TIME-LIMITED AGING ANALYSES

4-63

In its response to RAI 4.3-22 dated April 26, 2013, the applicant stated that transient lumping 

might promote some fatigue usage values to higher rankings and result in these components 

being skewed upward. However, the applicant clarified that this skewing will not affect the 

identification of the leading component, either because (1) all of the components used the same 

lumping set (particularly when comparing components from the same design report) or (2) the 

leading component does not use lumping, thus any lumping in the bounded location will not 

affect the top of the ranking. The staff noted that its concern is not associated with whether or 

not the applicant’s fatigue analyses used transient lumping. Rather, the staff’s concern is 

associated with whether or not the applicant compared CUFs that were calculated with lumped 

transients with CUFs that were not calculated with lumped transients.

In order to verify that that the lumping will not affect the top of the rankings in each thermal 

zone, the applicant reviewed all bounded locations. Based on the applicant’s review it was 

determined that AF monitoring locations were either based on a “common basis stress 

evaluation,” which is not affected by any lumping, or all of the components being compared 

used the same lumping set, which also does not affect the ranking. Since a review was 

performed to confirm that in all situations in which one location bounds another that any 

transient lumping was consistent between the locations, the staff finds that its concern that the 

comparison of CUF values that were calculated with or without transient lumping may impact 

screening and ranking results is resolved. The staff’s review of the applicant’s implementation 

of a “common basis stress evaluation” for determining EAF monitoring location is documented 

below in its evaluation of the applicant’s response to RAI 4.3-23.

Assumption #4. The comparison of CUFs across multiple thermal zones is valid.

In its response to RAI 4.3-22 dated April 26, 2013, the applicant stated that the examples 

provided in its response to RAI 4.3-21, Part (a), are the only instances where one thermal zone 

bounds another. The staff’s review of each of these examples is discussed below.

Example #1 involved the “pressurizer safety and relief valve piping” thermal zone bounding the 

“pressurizer upper head” thermal zone. The applicant provided its justification for this example; 

however, the applicant ultimately included the locations for the “pressurizer upper head” thermal 

zone to the list of locations in LRA Table 4.3-7 that will be monitored for EAF during the period 

of extended operation. The staff confirmed that the stainless steel pressurizer upper instrument 

nozzle and low-alloy steel pressurizer shell at support lug were added to LRA Table 4.3-7 as 

locations that will be monitored for EAF by the Fatigue Monitoring Program. The staff finds the 

addition of the stainless steel pressurizer upper instrument nozzle and low-alloy steel 

pressurizer shell at support lug acceptable because both locations were included for EAF 

monitoring instead of relying on bounding different locations associated with the pressurizer 

thermal zones.

Example #2 involved the replacement steam generator (RSG) “tubesheet” thermal zone 

bounding the “replacement steam generator primary head” thermal zone. The applicant stated 

that the low-alloy steel RSG primary manway drain tube in the RSG primary head thermal zone 

is bounded by the low-alloy steel RSG tubesheet (continuous region) in the tubesheet thermal 

zone. The applicant confirmed that both thermal zones were analyzed within the same 

generation of analysis during the RSG design project, which was performed by the same 

vendor. The applicant also confirmed that the transients used in these analyses were not 

lumped; these locations are exposed to the same transients in terms of number and severity; 

consistent material properties were used, and the same ASME Code edition was used. The 

staff finds this example in which the low-alloy steel RSG primary manway drain tube is bounded 
TIME-LIMITED AGING ANALYSES

4-64

by the low-alloy steel RSG tubesheet (continuous region) acceptable because the variables that 

can affect the CUF value (e.g., transient lumping, transient occurrences and severity, material 

properties, and ASME Code edition) were consistent between the analyses for these locations. 

Thus, the staff finds that it is reasonable to rank the CUF values for these components and 

determine the bounding location for EAF monitoring.

Based on its review, the staff finds the applicant has addressed its concerns associated with 

comparing and determining EAF monitoring locations based on Uen values because the 

applicant justified, as discussed above in Assumptions #1 to #4, that the comparison of 

components shared a common calculational basis. RAI 4.3-20, Part (c), RAI 4.3-21, Parts (a) 

through (c), and RAI 4.3-22 are resolved.

Finally, by letter dated September 6, 2012, the staff requested the applicant in RAI 4.3-20, 

Part (d) to provide the basis for not considering the fatigue curve in Figure A.3 of 

NUREG/CR-6909 for screening and determining an EAF monitoring location if it was not used in 

determining the Fen of Ni-Cr-Fe steels.

In its response dated October 11, 2012, as amended by letter dated December 13, 2012, the 

applicant stated the EAF screening was revised to not use the equations in NUREG/CR-6909 

for the Fen for Ni-Cr-Fe; instead, the revised screening calculation would use NUREG/CR-5704 

to compute Fen values for Ni-Cr-Fe material while using ASME Code determined CUF values. 

The applicant clarified that this approach to use NUREG/CR-5704 for nickel alloy components is 

only for the EAF screening and that further refinement of these factors can be achieved in future 

analysis using the methods in NUREG/CR-6909 for Ni-Cr-Fe material for individual

components. The Fen formula in NUREG/CR-5704 relied on the austenitic steels ASME design 

fatigue curves that are also applicable to nickel alloys; thus, the staff noted that 

NUREG/CR-5704 is also applicable to nickel alloys.

The staff finds it acceptable that NUREG/CR-5704 was used to determine an average Fen value 

for nickel alloy components for the purposes of EAF screening because (1) the Fen formula in 

NUREG/CR-5704 is applicable to nickel alloys, (2) Fen values calculated with NUREG/CR-5704 

yield more conservative Fen values when compared to Fen values calculated with 

NUREG/CR-6909, (3) use of the ASME fatigue curve instead of the fatigue curve in 

NUREG/CR-6909 for nickel alloys ensures the EAF screening and ranking was performed on a 

consistent basis. In addition, the staff finds it appropriate that during the refinement of Uen, as 

part of the Fatigue Monitoring Program, the applicant will use NUREG/CR-6909 to calculate the 

Uen value, which is consistent with the GALL Report. RAI 4.3-20, Part (d), is resolved.

The staff also issued RAI 4.3-21, Parts (a) through (i), by letter dated September 6, 2012,

requesting that the applicant, for each screening method described in the LRA, provide two 

examples of the method used to reduce the initial screening list, including a reason that this 

method was appropriate and conservative for each situation. The applicant was also requested 

to justify each screening method and specifically address any factors or criteria that are 

applicable when implementing screening methods. 

The staff reviewed the applicant’s response to RAI 4.3-21, Parts (a) through (c) (in the 

applicant’s letter dated October 11, 2012), and noted that the applicant’s response to RAI 

4.3-22, in a letter dated April 26, 2013, specifically related to “Assumption #4,” addresses the 

staff’s concerns identified in RAI 4.3-21, Parts (a) through (c), related to comparing CUF values 

across multiple thermal zones. Thus, the staff’s evaluation of the applicant’s “One Thermal 
TIME-LIMITED AGING ANALYSES

4-65

Zone can bound another Thermal Zone in a System” method for reducing the initial screening 

list for EAF monitoring is documented in the evaluation of RAI 4.3-22 (see Assumption #4 

above).

In addition, in its response to RAI 4.3-21 by letter dated October 11, 2012, as amended by letter 

dated December 13, 2012, the applicant provided the only examples in which it used the other 

two of its screening methods, which include that “One material in a Thermal Zone can bound 

other materials in the same Thermal Zone” and “One material in a Thermal Zone can bound 

other materials in another Thermal Zone,” to reduce the initial screening list for EAF monitoring. 

By letter dated April 26, 2013, the applicant amended LRA Section 4.3.4 so that these two 

methods were no longer used in its evaluation for reducing the initial screening list for EAF 

monitoring. The staff confirmed that locations that were associated with these examples for 

reducing the initial screening list have been added as EAF monitoring locations in LRA 

Table 4.3-7, as amended by letter dated April 26, 2013. Thus, the staff finds RAI 4.3-21, 

Parts (d) through (i) and the associated applicant responses are no longer applicable and are 

moot. 

In its letter dated December 13, 2012, in response to RAI 4.3-21, the applicant revised LRA 

Section 4.3.4 stating that a location that can be shown to be bounded by another location on a 

“common basis stress evaluation” may be removed from the EAF monitoring list. The applicant 

provided a qualitative explanation that this judgment relies upon the comparison of transients in 

terms of severity and/or number of occurrences. In order for the staff to determine whether the 

“common basis stress evaluation” is appropriate or valid for the applicant’s facility, additional 

information is needed related to the scope, parameters considered, and assumptions involved. 

By letter dated March 26, 2013, the staff issued RAI 4.3-23 requesting the applicant to provide 

additional information regarding the process used for the “common basis stress evaluation” and 

whether plant design, material fabrication, and geometry of components were considered. In 

addition, the applicant was requested to justify any use of a “common basis stress evaluation” 

other than in the chemical and volume control system (CVCS).

In its response dated April 26, 2013, the applicant confirmed that the “common basis stress 

evaluation” is based on transient severity, including analytical features (ASME Section III 

NB-3600 versus NB-3200), and number of transient occurrences. In addition, the applicant 

stated that other conditions, such as the dissolved oxygen level and strain-rate, are based on 

consistent assumptions and are used to calculate the Fen component of Uen. The applicant 

explained that the “common basis stress evaluation” is based on a qualitative assessment of the 

stresses applied to the components, which must be the same material, and these evaluations 

are appropriate to its plant because all of the CUF values were taken from the design reports 

that incorporate plant-specific geometric characteristics and transients. The staff’s evaluation of 

each instance the applicant used a “common basis stress evaluation” to identify an EAF 

monitoring location is documented below.

By letter dated December 13, 2012, the applicant amended LRA Section 4.3.4 to provide an 

example where a “common basis stress evaluation” was performed in the CVCS. The applicant 

stated that the charging nozzle, which experiences transients in the CVCS and reactor coolant 

system (RCS) thermal zones, will bound the fatigue behavior of other CVCS locations. The 

applicant explained that the charging nozzle CVCS transients have a reflood feature where the 

nozzle temperature would experience a step increase from the CVCS transient temperature to 

the reactor coolant system cold leg temperature. In addition, the applicant confirmed that no 

other CVCS component experiences this reflood shock from the cold leg. The staff finds it 

reasonable that CVCS locations are bounded by the charging nozzles because (1) the charging 
TIME-LIMITED AGING ANALYSES

4-66

nozzle experiences significant temperature variations from the reflood shock that are not 

experienced in all other CVCS components, and (2) the charging nozzle experiences transients 

from two thermal zones whereas all other CVCS components experience transients only from 

the CVCS thermal zone. Thus, the fatigue usage accumulated at the charging nozzle will be 

greater than that of all other CVCS components.

The applicant stated in its response to RAI 4.3-23 that two additional locations outside the 

CVCS system used a “common basis stress evaluation.” The staff’s evaluation of these 

additional locations is documented below.

The applicant stated that the stainless steel RCS hot leg piping is bounded by its attached 

nozzles based on a “common basis stress evaluation.” The applicant clarified that the attached 

nozzles are subjected to transients from two thermal zones (the hot leg thermal zone and one 

other thermal zone). Specifically, the surge line thermal zone affects the stainless steel hot leg 

surge nozzle; the hot leg safety injection thermal zone affects the stainless steel hot leg safety 

injection nozzles; and the residual heat removal (RHR) hot leg thermal zone affects the 

stainless steel RHR hot leg nozzles. The applicant stated that all other hot leg locations are 

subjected only to the hot leg thermal zone transients. The staff finds it reasonable that the 

stainless steel RCS hot leg piping is bounded by the attached stainless steel nozzle 

components and that these three nozzle components are included as an EAF monitoring 

location because the nozzle components experience transients from an additional thermal zone 

other than the hot leg thermal zone; thus, the fatigue usage accumulated at the nozzle 

components will be greater than that of the attached stainless steel RCS hot leg piping.

The applicant also stated that the stainless steel pressurizer spray nozzle bounds the stainless 

steel pressurizer spray piping and the stainless steel spray line nozzle at the cold legs based on 

a “common basis stress evaluation.” 

For the first instance, the applicant stated that the limiting location in the pressurizer spray line 

piping thermal zone is at the pressurizer spray nozzle, which is now under a structural weld 

overlay (SWOL). This SWOL covers both the nozzle-to-safe-end dissimilar metal butt-weld and 

the safe-end-to-piping stainless steel butt-weld; the applicant also stated that the highest fatigue 

locations are under this overlay and are qualified for fatigue by a crack growth analysis. The 

staff’s evaluation of the applicant’s SWOL TLAA is documented in SER Section 4.7.2.2. The 

applicant stated that the next highest fatigue location is located in the spray piping near the toe 

of the overlay, and the SWOL analysis states that the current fatigue analysis of the spray 

nozzle without the SWOL is conservative relative to the toe of the SWOL on the piping. The 

applicant stated that the pressurizer spray line piping’s next limiting location is in the auxiliary 

spray line and the staff confirmed that this location is already identified as an EAF monitoring 

location. The staff finds it reasonable that the stainless steel pressurizer spray line piping is 

bounded by the attached stainless steel pressurizer spray nozzle because nozzles typically

experience temperature and pressure changes due to the transients that are greater than 

connected piping, and the SWOL analysis determined the nozzle CUF was conservative when 

compared to the CUF of the toe of the SWOL on the piping. 

For the second instance, the applicant stated that the pressurizer spray nozzle will experience 

transients from two thermal zones (pressurizer upper head and spray line piping) and will be 

subjected to significant thermal transients during pressurizer spray initiation-and-termination and 

during auxiliary spray initiation-and-termination. In addition, the spray events are much less 

severe at the spray line nozzle at the cold legs as the temperature at the nozzle remains 

constant during a spray event and will primarily experience RCS transients (e.g., heatup and 
TIME-LIMITED AGING ANALYSES

4-67

cooldown). The staff finds it reasonable that the stainless steel spray line nozzle at the cold 

legs is bounded by the stainless steel pressurizer spray nozzle because the pressurizer spray 

nozzle experiences significant temperature variations from pressurizer spray and auxiliary spray 

initiations and terminations within the pressurizer upper head and spray line piping thermal 

zones, whereas the temperature at the spray line nozzle at the cold legs remains constant 

during a spray event. Thus the fatigue usage accumulated at the pressurizer spray nozzle will 

be greater than that of the spray line nozzle at the cold legs.

The applicant explained that the RCS 2-inch crossover leg loops 1 & 2 drain nozzles were 

previously bounded by the charging nozzle based on a “common basis stress evaluation.” 

However, the applicant deleted this because there is not a sufficient overlap of the transients. 

Therefore, the RCS 2-inch crossover leg loops 1 & 2 drain nozzles were added as an EAF 

monitoring location. The staff confirmed that the RCS 2-inch crossover leg loops 1 & 2 drain 

nozzles were added to LRA Table 4.3-7. 

Based on its review, the staff finds the applicant’s “common basis stress evaluation” reasonable 

because (1) it provides a comparison of two locations of the same material based only on 

transient severity and number of transient occurrences in order to provide a qualitative 

indication of which location is more sensitive to metal fatigue, and (2) this evaluation was based 

on the applicant’s plant-specific design reports, which incorporate system geometric 

characteristics and transients. In addition, the staff finds the applicant demonstrated for its 

plant-specific design that the implementation of the “common basis stress evaluation,” only for 

those instances identified above, was reasonable in determining a bounding location for EAF 

monitoring during the period of extended operation. RAI 4.3-23 is resolved.

In its response dated October 11, 2012, to Part (d) of RAI 4.3-21, as revised by letter dated

December 13, 2012, the applicant provided an example supporting one of its screening 

principles that one material can bound other materials in the same thermal zone. The applicant 

indicated that those plant-specific locations with Uen greater than 1.0 will be evaluated further 

using the same methods as those to remove conservatisms for NUREG/CR-6260 locations 

described in LRA Section 4.3.4. The staff noted, however, that the applicant has not justified 

that the low-alloy steel components would remain bounded by the stainless steel components 

after the EAF analysis has been refined to reduce the Uen of the stainless steel components. In 

addition, the applicant has not explained how — nor justified that — the refinement of a higher 

Uen in LRA Table 4.3-6 of one material would ensure the reduction of Uen for a bounded location 

of another material. By letter dated March 26, 2013, the staff issued RAI 4.3-24 requesting the 

applicant justify that the refinement of a higher Uen in LRA Table 4.3-6 of one material would 

ensure the reduction of the Uen for a bounded location of another material, such that the 

conclusion that one material bounds other materials in the same thermal zone will remain valid.

In its response to RAI 4.3-24 by letter dated April 26, 2013, the applicant stated that the 

example provided in the RAI 4.3-21, Part (d), response dated December 13, 2012, is the only 

instance where a location of one material bounds the location of another material. In this case, 

the staff noted that the stainless steel pressurizer instrument nozzle bounds the low-alloy steel 

pressurizer shell at support lug in the pressurizer upper head thermal zone. The applicant 

stated that, in order to ensure that the refinement of a higher Uen of one material will bound the 

Uen of another material, both locations were added to the list of EAF monitoring locations in LRA 

Tables 4.3-6 and 4.3-7. The staff confirmed that the pressurizer instrument nozzle and 

pressurizer shell at support lug are identified in LRA Table 4.3-7 as EAF monitoring locations. 

The staff finds the inclusion of the stainless steel pressurizer instrument nozzle and low-alloy 

steel pressurizer shell at support lug as EAF monitoring locations acceptable because the 
TIME-LIMITED AGING ANALYSES

4-68

applicant included locations from applicable materials for the thermal zones associated with the 

pressurizer. The staff noted that the applicant also revised LRA Section 4.3.4 such that the 

provision of “one material in a thermal zone can bound other materials in the same thermal 

zone” was removed. 

In its response to RAI 4.3-24, the applicant also stated that the Fatigue Monitoring Program will 

be enhanced such that the EAF monitoring locations, when refined, will be revisited to confirm 

that the bounding environmentally assisted fatigue susceptible locations are updated 

appropriately and remain bounded consistent with the refined analysis. The applicant stated 

that the commitment in LRA Table A4-1, No. 31, and LRA Section B3.1 are updated to confirm 

that the bounding environmentally assisted fatigue susceptible locations are updated 

appropriately and remain bounded consistent with the refined analysis. By letter dated August 

2, 2013, the applicant revised its response to RAI 4.3-24 and LRA Section A2.1 to state that the 

sentinel location analysis, when refined, will be revisited to confirm that the bounding 

environmentally assisted fatigue susceptible sentinel locations are updated appropriately and 

remain bounded consistent with the refined analysis. The staff finds this revision to LRA

Section A2.1 acceptable because the FSAR supplement explicitly provides a summary 

description as to the actions the applicant will take to confirm that the environmentally assisted 

fatigue susceptible locations, as provided in LRA Table 4.3-7, are updated appropriately and 

remain bounded consistent with any analysis performed to refine Uen values less than 1.0 for 

these EAF monitoring locations. 

Based on its review, the staff finds the applicant response to RAI 4.3-24, as amended by letter 

August 2, 2013, acceptable because (1) the applicant will no longer use the screening principle 

that one material can bound other materials in the same thermal zone, and (2) the applicant’s 

Fatigue Monitoring Program, when enhanced, will ensure that bounding EAF monitoring 

locations are updated appropriately and remain bounded consistent with the refined analysis. 

RAI 4.3-24 is resolved.

The staff noted that the elastic modulus for the austenitic stainless steel fatigue curve in 

Figure I-9.2 of the ASME Code Section III, Appendix I, changed from 26×106 psi in the 1980 

edition to 28.3×106 psi in the 1983 edition. It is not clear to the staff whether this change in the 

stainless steel material property in the aforementioned ASME Code Section III editions has 

been considered in the Uen comparison by the applicant. 

By letter dated March 26, 2013, the staff issued RAI 4.3-25 requesting the applicant identify all 

the stainless steel components that were designed to ASME Code editions that were issued 

after the 1980 edition. The applicant was also requested to clarify whether any stainless steel 

component designed after the 1983 edition of the ASME Code has been used to bound another 

stainless steel component that was designed to the 1980 or earlier ASME Code edition.

In its response to RAI 4.3-25 by letter dated April 26, 2013, the applicant stated that all ASME 

Class 1 stainless steel components in its plant were analyzed to ASME Code editions that are 

pre-1980 except for the pressurizer lower head. The applicant also stated that the pressurizer 

lower head was evaluated as a unique thermal zone with one EAF monitoring location identified 

and that location is not used to bound any locations outside the pressurizer lower head thermal 

zone. 

Based on its review, the staff finds the applicant response to RAI 4.3-25 acceptable because the 

applicant demonstrated that the differences in the fatigue design curve and elastic modulus 

between the 1980 and 1983 editions of the ASME Code, Section III, did not impact the 
TIME-LIMITED AGING ANALYSES

4-69

comparison of Uen values for stainless steel locations since any comparisons were consistently 

made to fatigue analyses performed to the 1980 edition or the 1983 edition. RAI 4.3-25 is 

resolved.

In its response to RAI 4.3-21, Part (d), by letter dated October 11, 2012, as amended by letter 

dated December 13, 2012, the applicant revised LRA Table 4.3-7 indicating two Ni-Cr-Fe 

components (RPV bottom head instrument tubes and RSG tube-to-tubesheet connection) as 

EAF monitoring locations. The staff noted that LRA Table 3.1.2-3 identifies nickel alloy 

pressurizer safe ends that are exposed to the reactor coolant environment with the aging effects 

of cumulative fatigue damage. The staff did not identify any reference to these nickel alloy 

pressurizer safe ends as EAF monitoring locations in LRA Table 4.3-7; thus, it was not clear to 

the staff how these components were bounded by other stainless steel pressurizer locations 

identified in LRA Table 4.3-7.

By letter dated March 26, 2013, the staff issued RAI 4.3-26 requesting that the applicant identify 

the nickel alloy components in the pressurizer safe ends and demonstrate how the nickel alloy 

locations have been bounded by other pressurizer locations identified in LRA Table 4.3-7.

In its response to RAI 4.3-26 by letter dated April 26, 2013, the applicant stated that the nickel 

alloy locations in the pressurizer are in the weld materials associated with the pressurizer safety 

and relief nozzles, the pressurizer spray nozzle, and the pressurizer surge nozzle. The 

applicant also stated that all of these locations in the nozzles have had a preemptive SWOL 

applied over the nickel alloy material, that these SWOLs are supported by fracture mechanics 

analyses, and that periodic inspections are consistent with ASME Code Section XI as the 

means to address aging in the overlaid welds.

The staff noted that an SWOL effectively mitigates the effect of metal fatigue because any 

initiated crack due to metal fatigue will not grow beyond the critical crack size before the 

inspection interval determined by the fracture mechanics analyses. Thus, the staff finds that 

inspections will be performed at sufficient intervals, which are supported by the fracture 

mechanics analyses, before the component can no longer perform its pressure boundary 

intended function. In addition, the staff noted that, since the SWOLs have been applied to these 

components, the overlay maintains the pressure boundary of the component instead of the 

nickel alloy material. The staff evaluation of the applicant’s TLAA associated with the 

pressurizer SWOLs is documented in SER Section 4.7.2.2. The staff finds it reasonable that 

environmentally assisted fatigue is not an aging effect requiring management for these nickel 

alloy safe ends since their intended function to maintain the reactor coolant pressure boundary 

is now being performed by the SWOLs, which are being managed for age-related degradation.

Based on its review, the staff finds the applicant’s response to RAI 4.3-26 acceptable because 

the applicant clarified that the aging effect of cumulative fatigue damage for the nickel alloy 

pressurizer safe end components is managed as part of the SWOLs by the facture mechanics 

TLAA and environmentally assisted fatigue is not applicable. RAI 4.3-26 is resolved.

LRA Section 4.3.4, as amended by letter dated December 13, 2012, also indicates that the 

60-year projected Uen is 0.74 for the safety injection nozzle and the 60-year projected cycle 

counts are the same as the numbers of cycles to date for three transients assumed in the EAF 

analysis. The staff noted that, when using the CBF monitoring method, the incremental fatigue 

usage for each transient can be accumulated to provide a fatigue usage as the components are 

being monitored during the period of extended operation. Furthermore, the incremental fatigue 

usage was supported by an ASME Code Section III fatigue analysis with an assumed number of 

occurrences for each transient. However, the staff noted the incremental fatigue usage may 
TIME-LIMITED AGING ANALYSES

4-70

change after the number of occurrences of a transient had exceeded that assumed in the 

fatigue analysis due to the transient-pairing provision in ASME Code Section III 

Paragraph NB-3222.4(e)(5).

By letter dated March 26, 2013, the staff issued RAI 4.3-27, requesting that the applicant clarify 

how the incremental fatigue usage and fatigue accumulation will be tracked when the cycle 

count is beyond those assumed in the fatigue analysis and justify that, prior to reaching the 

“fatigue-usage action limit,” incremental fatigue usage for additional occurrences beyond those 

assumed in the fatigue analysis will be calculated in accordance with the ASME Code. The 

applicant was also requested to clarify whether the safety injection nozzle is the only location 

that was analyzed for the number of transient cycles to date and justify that the implementation 

of a “fatigue-usage action limit” would ensure that corrective action will be initiated before 

exceeding the design limit.

In its response to RAI 4.3-27 by letter dated April 26, 2013, the applicant stated that the safety 

injection nozzle is the only CBF monitored location which used the number of transient cycles to

date. The applicant explained that CBF is not limited by the number of cycles assumed in the 

ASME Code fatigue analysis because this monitoring method utilizes the stress intensity for 

each transient, which are generated with the ASME Section III methods. The applicant clarified 

that the stress intensities are paired in accordance with ASME Code Section III Paragraph 

NB-3222.4(e)(5), but the pairing is performed according to the actual numbers of transients that 

have occurred and not necessarily identical to the pairing order in the design analysis. 

The staff noted that the use of CBF is effectively calculating a fatigue usage in accordance with 

ASME Code Section III Paragraph NB-3222.4(e)(5) on an ongoing basis, which is consistent 

with the recommendations in the “detection of aging effects” program element of GALL Report 

AMP X.M1, which states that the program provides for updates of the fatigue usage calculations 

on an as-needed basis. Thus, the staff finds that the applicant clarified how the incremental 

fatigue usage and fatigue accumulation will be tracked and determined it is consistent with the 

recommendations in GALL Report AMP X.M1.

The staff also noted that the premise of CBF is to calculate a fatigue usage based on those 

stress intensities, but not the assumed numbers of cycles, which were calculated in the ASME 

Code fatigue analysis. The staff noted that since the number of cycles assumed in the analysis 

was not relied on in the CBF monitoring method, the staff’s concern regarding whether the 

fatigue usage calculation will be determined consistent with the transient-pairing provision in 

ASME Code Section III Paragraph NB-3222.4(e)(5) is resolved. 

The applicant stated that the cycle count will only be allowed to increase beyond the number 

assumed in the fatigue analysis if the CUF and/or the Uen can be assured to be less than the 

“fatigue-usage action limit” using the CBF monitoring method. Furthermore, the applicant 

explained that these incremental fatigue usage values are calculated and tracked against the 

“fatigue-usage action limit” to ensure corrective action is taken prior to fatigue accumulation 

exceeding the ASME Code allowable fatigue limit of 1.0. 

The “acceptance criteria” program element of GALL Report AMP X.M1 states that the 

acceptance criterion is maintaining the cumulative fatigue usage below the design limit through 

the period of extended operation, with consideration of the reactor water environmental fatigue 

effects described in the program description and scope of program. Thus, the staff finds it 

conservative that the applicant set the fatigue-usage action limit such that actions are taken 

before the design limit of 1.0 is exceeded and is consistent with the recommendations in GALL 

Report AMP X.M1. 
TIME-LIMITED AGING ANALYSES

4-71

Based on its review, the staff finds the applicant response to RAI 4.3-27 acceptable because the 

applicant (1) clarified that the CBF monitoring method and calculation of the fatigue usage does 

not rely on the numbers of cycles assumed in the analysis, (2) explained that CBF monitoring 

method is not inconsistent with the provision in ASME Code Section III, and (3) justified that the 

implementation of a “fatigue-usage action limit” for CBF would ensure that corrective action will 

be initiated before exceeding the design limit of 1.0. RAI 4.3-27 is resolved.

Based on its review, as described above, the staff finds the applicant has justified its approach 

and its determination of locations that require monitoring for environmentally assisted fatigue of 

the reactor coolant pressure boundary during the period of extended operation. Thus, Open 

Item 4.3.4-1 is closed.

LRA Section 4.3.4, as amended by letter dated May 3, 2012, indicates that those 

non-NUREG/CR-6260 locations with an EAF CUF greater than 1.0 will be evaluated further 

using the same methods as those used to refine the EAF CUF for the NUREG/CR-6260 

locations described above. The staff noted that the methods used to refine the EAF CUF are 

not restricted to only those locations identified in the NUREG/CR-6260 and the staff’s review of 

these methods are described above. The LRA states that the results of these final analyses for 

the non-NUREG/CR-6260 locations will be incorporated into the Fatigue Monitoring Program by 

either counting the transients assumed or incorporate the stress intensities into a CBF ability of 

the program. The staff’s review of the of cycle counting method, CBF and SBF methods are 

discussed in its review of the Fatigue Monitoring Program as documented in SER 

Section 3.0.3.2.22. The staff determined that the cycle counting method will ensure a fatigue 

analysis remains valid by ensuring the assumptions in the analysis are not exceeded. In 

addition, the staff determined that the CBF and SBF monitoring methods will ensure that the 

accumulated fatigue usage, including the effects of reactor coolant, of a component resulting 

from transient occurrences will not exceed the design limit of 1.0.

The staff finds that the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), 

that the effects of reactor coolant environment on component fatigue life will be adequately 

managed for the period of extended operation. Additionally, the applicant’s disposition meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.3 because the applicant has demonstrated 

that the impact of the reactor coolant environment on critical components has been adequately 

addressed and will be managed by the Fatigue Monitoring program. Therefore, the applicant’s 

EAF evaluations will remain valid, and the ASME Code limit of 1.0 will not be exceeded during 

the period of extended operation or corrective actions will be taken.

4.3.4.3 FSAR Supplement

LRA Section A3.2.3, as amended by letter dated October 17, 2013, provides the FSAR 

supplement summarizing the environmentally assisted fatigue evaluations for NUREG/CR-6260 

locations and non-NUREG/CR-6260 reactor coolant pressure boundary locations. In addition, 

LRA Section A3.2.3 states that reactor vessel internals locations with fatigue usage calculations will 

be evaluated for the effects of the reactor water environment. The staff noted that LRA Section 

A3.2.3 clearly identifies the NUREG reports, which are consistent with those identified in the 

GALL Report, that will be used to address environmentally assisted fatigue for reactor coolant 

pressure boundary and reactor vessel internal components. The staff reviewed LRA Section 

A3.2.3 consistent with the review procedures in SRP-LR Section 4.3.3.2, which state that the 

reviewer verifies that the applicant has provided information to be included in the FSAR 

supplement that includes a summary description of the evaluation of the metal fatigue TLAA.
TIME-LIMITED AGING ANALYSES

4-72

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2 and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the 

environmentally assisted fatigue evaluations for NUREG/CR-6260 locations and 

non-NUREG/CR-6260 reactor coolant pressure boundary locations, as required by 

10 CFR 54.21(d).

4.3.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has acceptably demonstrated, 

in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of environmentally assisted fatigue 

on the intended functions of the monitored NUREG/CR-6260 locations will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation. In addition, 

the staff concludes that the applicant has acceptably demonstrated, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of environmentally assisted fatigue on the intended 

functions of the monitored non-NUREG/CR-6260 reactor coolant pressure boundary locations 

will be adequately managed by the Fatigue Monitoring Program for the period of extended 

operation. The staff also concludes that the FSAR supplement contains an appropriate 

summary description of the environmentally assisted fatigue evaluations, as required by 

10 CFR 54.21(d).

4.3.5 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction 

Factor in ANSI B31.1 and ASME Section III Class

4.3.5.1 Summary of Technical Information in the Application

LRA Section 4.3.5 states that piping within the scope of license renewal “that is designed to 

American National Standards Institute (ANSI) B31.1 or ASME Code Section III Class 2 and 3 

requires the application of a stress range reduction factor to the allowable stress range 

(expansion and displacement) to account for thermal cyclic conditions.” The LRA also states 

that “[n]one of ANSI B31.1 or the ASME Code Section III Subsections NC and ND for Class 2 

and 3 piping invokes fatigue analyses. If the number of full-range thermal cycles is expected to 

exceed 7,000, these codes require the application of a stress range reduction factor to the 

allowable stress range for expansion stresses (secondary stresses).”

With the exception of reactor coolant sample lines, these piping and components within the 

scope of license renewal clearly do not operate in a cycling mode that would expose the piping 

to more than three thermal cycles per week (i.e., to more than 7,000 cycles in 60 years.) For 

the reactor coolant sample lines, a survey of plant piping systems found that some reactor 

coolant sample lines may be subject to more than 7,000 thermal cycles. Review of operating 

practice at Callaway indicates that RCS samples are taken weekly from the hot leg during 

operation. The LRA states that, therefore, none of the lines associated with this sample location 

will exceed 7,000 cycles during the period of extended operation. 

The applicant dispositioned the TLAA for the existing analyses of ANSI B31.1 or ASME Code 

Section III Class 2 and 3 piping within the scope of license renewal for which the allowable 

range of secondary stresses depends on the number of assumed thermal cycles, 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

4-73

4.3.5.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.5 and the TLAA for ANSI B31.1 or ASME Code Section III 

Class 2 and 3 piping for which the allowable range of secondary stresses depends on the 

number of assumed thermal cycles to verify, in accordance with 10 CFR 54.21(c)(1)(i), that the 

analysis remains valid during the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition of 

10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.3.3.1.2.1. 

These procedures state that the operating transient experience and a list of the assumed 

transients used in the existing CUF calculations for the current operating term are reviewed to 

ensure that the number of assumed transients would not be exceeded during the period of 

extended operation.

LRA Section 4.3.5 provides a list of several systems and states that these systems are subject 

to thermal fatigue effects and were therefore included in the aging management review (AMR) 

results presented in LRA Section 3. Specifically, the main feedwater system and boron recycle 

system were included as part of this list of systems subject to thermal fatigue effects. However, 

the staff noted that LRA Tables 3.4.2-3 and 3.3.2-28 did not provide AMR results for 

components subject to “cumulative fatigue damage.” It is also not clear whether there are 

additional systems and components that are subject to an AMR for “cumulative fatigue 

damage,” in accordance with 10 CFR 54.21(a)(1), and were not included in the LRA.

By letter dated September 6, 2012, the staff issued RAI 4.3-10 requesting the applicant to 

provide the appropriate AMR results for components subject to thermal fatigue effects for the 

main feedwater system and boron recycle system and to justify any AMR results with 

"cumulative fatigue damage" as an aging effect that were excluded.

In its response to RAI 4.3-10 dated October 11, 2012, the applicant revised LRA 

Tables 3.3.2-28 and 3.4.2-3 to include the applicable AMR items for piping components subject 

to the thermal effects of fatigue and confirmed that there were no other AMR items that needed 

to be added to the LRA. The staff noted that LRA Section 4.3.5 states that the applicant 

performed a review to identify components that may be subject to significant thermal fatigue 

effects that were then included in the AMR results. In its RAI response, the applicant stated that 

systems or portions of systems with low operating temperatures are not subject to significant 

thermal fatigue effects. The staff finds this reasonable because the differences in fluid 

temperature between operating temperatures and the minimum exposure temperature for these 

plant systems would not induce stresses that cause fatigue damage.

The staff finds the applicant’s response acceptable because the LRA was revised to include 

AMR items subject to thermal fatigue, in accordance with 10 CFR 54.21(a)(1), and the applicant 

sufficiently justified, as described above, that systems with low operating temperatures are not 

subject to fatigue damage. The staff’s concern described in RAI 4.3-10 is resolved.

LRA Section 4.3.5 states that, with the exception of reactor coolant sample lines, piping and 

components within the scope of license renewal do not operate in a cycling mode that would 

expose them to more than 7,000 cycles in 60 years. The staff noted that transient cycles that 

are likely to produce full-range thermal cycles in balance-of-plant Class 2, 3, and B31.1 piping 

within the scope of license renewal, with the exception of reactor coolant sample lines, are plant 

heatups, plant cooldowns, and reactor trips. The staff also noted that these same plant systems 

may be affected by temperature variations that are coincident with other design transients for 

the plant that can cause part-range thermal cycles.
TIME-LIMITED AGING ANALYSES

4-74

The staff reviewed the number of occurrences for plant transients expected for 60 years of 

operation provided in LRA Table 4.3-2 to ensure the full thermal range transient cycle limit of 

7,000 will not be exceeded. The staff noted that even if the part-range thermal cycles are 

conservatively assumed to be full-range thermal cycles, the total number of design basis 

thermal events expected to occur in a 60-year life is approximately 1,600 cycles. The staff’s 

review of the applicant’s 60-year projection methodology is documented in SER 

Section 4.3.1.2.2. Thus, based on its review, the staff finds it reasonable that the full-range 

thermal cycle limit of 7,000 — used in the applicant’s design basis fatigue evaluations 

associated with the ANSI B31.1 and ASME Code Section III Class 2 and 3 piping — will not be 

exceeded and includes margin to account for unanticipated transient occurrences during the 

period of extended operation. 

LRA Section 4.3.5 states that a review of FSAR Table 9.3-3 SP and the Callaway chemistry 

schedule identified that the only sample piping within the scope of license renewal that meets 

the temperature screening criteria, and could possibly exceed 7,000 cycles, is the RCS hot leg 

sample piping. The LRA also states that a review of operating practice at Callaway indicates 

that RCS samples are taken weekly from the hot leg during operation.

The staff reviewed FSAR Table 9.3-3 SP and noted that it provides the “typical sampling 

frequency” for the primary sampling systems. Specifically, the table lists a frequency of three 

per week or one per week for the RCS hot legs sample (loop 1 or 3). Based on information 

presented in the LRA and in FSAR Table 9.3-3 SP, the sampling frequency of the RCS hot legs 

sample (loop 1 or 3) is not clear to the staff. The FSAR indicates that the sampling frequency 

can be up to 3 per week, and it appears that the Callaway chemistry schedule indicates a 

sampling frequency of once per week.

By letter dated September 6, 2012, the staff issued RAI 4.3-11 requesting the applicant to 

provide the basis for the discrepancy in sampling frequency between the FSAR and the LRA. 

The staff also requested the applicant to confirm that, other than RCS samples taken weekly 

from the hot leg during operation, no other thermal cycles are likely to produce full-range or 

part-range thermal cycles in the sampling lines.

In its response to RAI 4.3-11 dated October 11, 2012, the applicant stated that FSAR 

Table 9.3-3 SP identifies 3 times per week as the “typical sampling frequency,” and this is 

reflected in the design calculations for the hot leg sample lines, which the staff noted involved 

the application of a stress range reduction factor of 0.9 that permits up to 14,000 thermal cycles. 

The staff noted that, although the FSAR and design calculation permit a sampling frequency up 

to 3 times a week, the applicant confirmed that current practice at its site is to draw one sample 

from the hot leg sampling lines per week. The applicant stated that the sole function of the RCS 

hot leg sample piping is to obtain RCS hot leg samples, and it confirmed that there are no other 

functions or events of the nuclear sampling system that are likely to produce full-range or 

part-range thermal cycles. 

The staff finds the applicant’s response acceptable because the applicant confirmed that its 

practice is to sample the hot leg sample lines weekly, even though the FSAR and design 

calculation account for sampling the line up to 3 times per week. Additionally, the applicant 

confirmed that no other functions or events of the sampling line are likely to produce a full-range 

or part-range thermal cycles. Thus, the staff determined that approximately 3,120 cycles are 

expected to occur in the hot leg sample lines, which is significantly less than the 14,000 cycles 

permitted by the design analysis. The staff noted that there is margin to account for unexpected 
TIME-LIMITED AGING ANALYSES

4-75

or unscheduled sampling cycles from the RCS hot leg sample line through the period of 

extended operation. The staff’s concern described in RAI 4.3-11 is resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the TLAAs for ANSI B31.1 or ASME Code Section III Class 2 and 3 piping for which the 

allowable range of secondary stresses depends on the number of assumed thermal cycles 

remain valid for the period of extended operation. Additionally, the applicant’s analysis meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.2.1 because, for those components subject to 

thermal fatigue described above, the cycle limit established in the design analysis is not 

expected to be exceeded based on the projected total number of full thermal range transients 

through the period of extended operation and includes margin to account for unanticipated 

transient cycles.

4.3.5.3 FSAR Supplement

LRA Section A3.2.4 provides the FSAR supplement summarizing the TLAA for ANSI B31.1 or 

ASME Code Section III Class 2 and 3 piping. The staff reviewed LRA Section A3.2.4 consistent 

with the review procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that 

the applicant has provided information to be included in the FSAR supplement that includes a 

summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA for 

ANSI B31.1 or ASME Code Section III Class 2 and 3 piping, as required by 10 CFR 54.21(d).

4.3.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the TLAA for ANSI B31.1 or 

ASME Code Section III Class 2 and 3 piping remains valid for the period of extended operation. 

The staff also concludes that the FSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.6 Fatigue Design of Spent Fuel Pool Liner and Racks for Seismic Events

4.3.6.1 Summary of Technical Information in the Application

LRA Section 4.3.6 states that the replacement spent fuel pool racks and liner are designed to 

the stress limits of, and analyzed in accordance with, ASME Code Section III, Division 1, 

Subsection NF, 1989 Edition.

These analyses are described in FSAR Section 9.1A.4.3.5.4 SP, and the spent fuel pool racks 

were replaced in 1999 and were analyzed for fatigue effects of one safe-shutdown earthquake 

(SSE) and 20 operating basis earthquakes (OBE). The analysis calculated a CUF of 0.404 and 

included a fatigue evaluation of the pool liner for the loads imposed by the new racks. The 

analysis uses the same 20 OBE, plus 1 SSE events. In addition, the analysis calculated a CUF 

caused by seismic events of less than 0.00352 for the liner.

The applicant dispositioned the TLAA for the fatigue design of spent fuel pool liner and racks for 

seismic events, 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

4-76

4.3.6.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.6 and the TLAA for the fatigue design of spent fuel pool 

liner and racks for seismic events to verify, in accordance with 10 CFR 54.21(c)(1)(i), that the 

analysis remains valid during the period of extended operation. 

The staff reviewed the applicant’s TLAAs for the fatigue design of spent fuel pool liner and racks 

for seismic events and the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with 

the review procedures in SRP-LR Section 4.3.3.1.1.1. These procedures state that the 

operating transient experience and a list of the assumed transients used in the existing CUF 

calculations for the current operating term are reviewed to ensure that the number of assumed 

transients would not be exceeded during the period of extended operation.

The staff noted that the two transients associated with the fatigue design of spent fuel pool liner 

and racks are 20 OBE and 1 SSE events, neither of which has occurred at the applicant’s site at 

the time of the LRA submittal. The staff reviewed FSAR Section 3.7(B).1.1 SP and noted that 

the seismic input for its site assumed an acceleration of 0.20g in the design response spectra 

for both the horizontal and vertical directions of the SSE. The OBE design response spectra 

values were taken as 60 percent of the SSE.

Since the fatigue design of spent fuel pool liner and racks was based, in part, to the occurrence 

of 20 OBE events and no OBE events have occurred at the time of the LRA submittal, the staff 

finds that there is sufficient margin with regard to the number of OBE events cycles that the 

figure will not be exceeded during the period of extended operation.

The staff noted that 10 CFR 54.35, “Requirements during term of renewed license,” requires, in 

part, that during the term of a renewed license, licensees shall be subject to, and shall continue 

to comply with, all NRC regulations contained in 10 CFR Part 100, “Reactor Site Criteria,” and 

the appendices to this part. Furthermore, 10 CFR Part 100, Appendix A, “Seismic and Geoligic 

Siting Criteria for Nuclear Power Plants,” Section V(a)(2), states that if vibratory ground motion 

exceeds that of the OBE, shutdown of the plant is required. Before resuming operations, the 

regulations require that plants must demonstrate to the staff that no functional damage has 

occurred to those features necessary for continued operation without undue risk to the health 

and safety of the public. The staff noted that since the acceleration resulting from the SSE 

would be greater than that of an OBE, provisions described in 10 CFR Part 100 Appendix A are 

applicable to any seismic events beyond the level of OBE, such as an SSE. Thus, the staff 

finds that the applicant’s compliance with 10 CFR Part 100 and its appendices ensure that the 

SSCs would not experience more than one SSE event without a demonstration to the staff that 

no functional damage has occurred to those features necessary for continued operation without 

undue risk to the health and safety of the public, as required by the rule.

The staff finds it reasonable that the number of occurrences for an SSE transients would not be 

exceeded during the period of extended operation because (1) no SSE event has occurred at 

the applicant’s site at the time of the LRA submittal, and (2) the applicant must comply with 

10 CFR Part 100, Appendix A, Section V(a)(2).

The staff finds that the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), 

that the analyses for the fatigue design of spent fuel pool liner and racks for seismic events

remain valid for the period of extended operation. Additionally, the analyses meet the 

acceptance criteria in SRP-LR Section 4.3.2.1.1.1 because, for OBE events and an SSE event, 

the number of assumed transients will not be exceeded during the period of extended operation, 

as described above.
TIME-LIMITED AGING ANALYSES

4-77

4.3.6.3 FSAR Supplement

LRA Section A3.2.5 provides the FSAR supplement summarizing the fatigue design of spent 

fuel pool liner and racks for seismic events. The staff reviewed LRA Section A3.2.5, consistent 

with the review procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that 

the applicant has provided information to be included in the FSAR supplement that includes a 

summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2 and is, therefore, acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the fatigue design 

of spent fuel pool liner and racks for seismic events, as required by 10 CFR 54.21(d).

4.3.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the analyses for the fatigue 

design of spent fuel pool liner and racks for seismic events remain valid for the period of 

extended operation. The staff also concludes that the FSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.7 Fatigue Design and Analysis of Class 1E Electrical Raceway Support Angle Fittings 

for Seismic Events

4.3.7.1 Summary of Technical Information in the Application

LRA Section 4.3.7 states that the design of Class 1E electrical raceway included a fatigue 

evaluation of the effects of operating basis and OBE and SSE loads. The LRA states that a 

CUF was calculated based on tests of typical designs to failure, and the number of fatigue 

cycles to failure was divided by a factor of safety of 1.5 to establish an allowable number of 

fatigue cycles for design. The LRA also states that “[t]he design assumed the number of OBE 

and SSE events recommended by [Institute for Electrical and Electronics Engineers] 

(IEEE) 344-1975, which states that the maximum number of OBE and SSE events plausible 

during a plant lifetime is [five] and [one], respectively.”

The applicant dispositioned the TLAA for the fatigue design of Class 1E electrical raceway 

support angle fittings for seismic events, in accordance with 10 CFR 54.21(c)(1)(i), that the 

analyses remain valid for the period of extended operation.

4.3.7.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.7 and the TLAA for the fatigue design of Class 1E electrical 

raceway support angle fittings for seismic events to verify, in accordance with 

10 CFR 54.21(c)(1)(i), that the analysis remains valid during the period of extended operation. 

The staff reviewed the applicant’s TLAAs for the fatigue design of Class 1E electrical raceway 

support angle fittings for seismic events and the corresponding disposition of 

10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.3.3.1.1.1. 

These procedures state that the operating transient experience and a list of the assumed 

transients used in the existing CUF calculations for the current operating term are reviewed to 

ensure that the number of assumed transients would not be exceeded during the period of 

extended operation.
TIME-LIMITED AGING ANALYSES

4-78

The staff noted that the two transients associated with the fatigue design of Class 1E electrical 

raceway support angle fittings are 750 OBE cycles and 150 SSE cycles, neither of which has 

occurred at the applicant’s site at the time of the LRA submittal. The staff reviewed FSAR 

Section 3.7(B).1.1 SP and noted that the seismic input for its site assumed an acceleration 

of 0.20g in the design response spectra for both the horizontal and vertical directions of the 

SSE. The OBE design response spectra values were taken as 60 percent of the SSE.

Since the fatigue design of Class 1E electrical raceway support angle fittings was based, in part, 

to the occurrence of 200 OBE cycles, and no OBE cycles have occurred at the time of the LRA 

submittal, the staff finds that there is sufficient margin with regard to the number of OBE cycles 

that the figure will not be exceeded during the period of extended operation.

The staff noted that 10 CFR 54.35 requires, in part, that during the term of a renewed license, 

licensees shall be subject to, and shall continue to comply with, all Commission regulations 

contained in 10 CFR Part 100 and the appendices to this part. Furthermore, 10 CFR Part 100 

Appendix A, Section V(a)(2) states that if vibratory ground motion exceeds that of the OBE, 

shutdown of the plant is required. Before resuming operations, the plant must demonstrate to 

the staff that no functional damage has occurred to those features necessary for continued 

operation without undue risk to the health and safety of the public. The staff noted that since 

the acceleration resulting from the SSE would be greater than that of an OBE, provisions 

described in 10 CFR Part 100, Appendix A, are applicable to any seismic events beyond the 

level of OBE, such as a SSE. Thus, the staff finds that the applicant’s compliance with 

10 CFR Part 100 and its appendices ensure that SSCs would not experience more than one 

SSE event without a demonstration to the staff that no functional damage has occurred to those 

features necessary for continued operation without undue risk to the health and safety of the

public, as required by the rule. 

The staff finds it reasonable that the number of occurrences for an SSE transients would not be 

exceeded during the period of extended operation because (1) no SSE event has occurred at 

the applicant’s site at the time of the LRA submittal, and (2) the applicant must comply with 

10 CFR Part 100, Appendix A, Section V(a)(2). 

The staff finds that the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), 

that the analyses for the fatigue design of Class 1E electrical raceway support angle fittings for 

seismic events remain valid for the period of extended operation. Additionally, the analyses 

meet the acceptance criteria in SRP-LR Section 4.3.2.1.1.1 because, for OBE events and an 

SSE event, the number of assumed transients will not be exceeded during the period of 

extended operation, as described above.

4.3.7.3 FSAR Supplement

LRA Section A3.2.6 provides the FSAR supplement summarizing the fatigue design of Class 1E 

electrical raceway support angle fittings for seismic events. The staff reviewed LRA 

Section A3.2.6, consistent with the review procedures in SRP-LR Section 4.3.3.2, which state 

that the reviewer verifies that the applicant has provided information to be included in the FSAR 

supplement that includes a summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2 and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the fatigue design 

of Class 1E electrical raceway support angle fittings for seismic events, as required by 

10 CFR 54.21(d).
TIME-LIMITED AGING ANALYSES

4-79

4.3.7.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the analyses for the fatigue 

design of Class 1E electrical raceway support angle fittings for seismic events remain valid for

the period of extended operation. The staff also concludes that the FSAR supplement contains 

an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.8 Fatigue Analyses of Class 2 Heat Exchangers

4.3.8.1 Summary of Technical Information in the Application

LRA Section 4.3.8 describes the applicant’s TLAA for fatigue of its ASME Code Class 2 heat 

exchangers. The LRA states that the shell and tube sides of the regenerative heat exchanger, 

and the tube side of the letdown, letdown reheat, RHR, and excess letdown heat exchangers 

are designed and constructed to ASME Code Section III Class 2 1974 Edition. The LRA also 

states that, as required by the design specification, thermal fatigue analyses were performed, in 

accordance with ASME Code Section III, Paragraph NB-3222.4, to qualify the heat exchangers

to the Code design requirements. The LRA provides a list of transients that were used in the 

fatigue evaluations of the regenerative, letdown, and letdown reheat heat exchanger 

components. In addition, the LRA also provides a list of transients that were used in the fatigue 

evaluation of the RHR exchanger components.

The LRA provides a separate discussion of each heat exchanger as discussed below:

Regenerative Heat Exchanger. The LRA states that the fatigue analysis of the regenerative 

heat exchanger evaluated the tubesheets, the shell side nozzles, the tube side nozzles, and the 

cross shell juncture. The LRA also states that the analysis found the most limiting fatigue usage 

factor of 0.50 at the outlet tubesheet and the analysis of the regenerative heat exchanger also 

contains a fatigue waiver for the tubeside inlet nozzle. The LRA further states that the thermal 

analysis of the shell side nozzles, the tubeside outlet nozzle, and cross shell junction indicated 

these areas are not subject to fatigue. Finally, the LRA states that the transients used in this 

analysis will be counted by the Fatigue Monitoring Program.

The applicant dispositioned the TLAA for the fatigue design of the regenerative heat exchanger

in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on the intended 

functions will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation.

Letdown Heat Exchanger. The LRA states that the fatigue analysis for the letdown heat 

exchanger indicated a maximum CUF of 1.84 for the flange and is the result of a recent 

reanalysis to account for operation with a letdown flow of 140 gallons per minute (gpm). The 

LRA discusses the evaluation performed by the applicant to reduce the 60-year CUF to 0.894. 

The fatigue analyses of the other components in the letdown heat exchanger included the 

tubesheet, tube side nozzles, and the studs. The LRA states that these components have 

CUFs of 0.910, 0.843, and 0.635, respectively. The LRA discusses the evaluation performed by 

the applicant that increases the CUF to 0.995, 0.880, and 0.696 for these components through 

the period of extended operation. 

The applicant dispositioned the TLAA for the fatigue design of the letdown heat exchanger in 

accordance with 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the 

period of extended operation.
TIME-LIMITED AGING ANALYSES

4-80

Letdown Reheat Heat Exchanger. The LRA states that the fatigue analysis for the letdown 

reheat heat exchanger indicated a maximum CUF of 4.431 for the studs and is the result of a 

recent reanalysis to account for operation with a letdown flow of 140 gpm. The LRA discusses 

the evaluation performed by the applicant to reduce the CUF to 0.503. The fatigue analysis of 

the letdown reheat heat exchanger evaluated the shell and tube side nozzles and the tubesheet. 

The LRA states that these components have maximum CUFs of 0.054 and 0.47, respectively. 

The LRA discusses the evaluation performed by the applicant that increases the CUFs to 0.57 

for the tubesheet and 0.0563 for the tube side nozzles. 

The applicant dispositioned the TLAA for the fatigue design of the letdown reheat heat 

exchanger in accordance with 10 CFR 54.21(c)(1)(ii), that the analysis has been projected to 

the end of the period of extended operation.

Residual Heat Removal Heat Exchangers. The LRA states that the fatigue analysis for the RHR 

heat exchangers explains that a fatigue analysis is not necessary for the associated transients 

since they are very weak. The LRA also states that, when these transients were put through the 

criteria of ASME Code Section III, Paragraph NB-3222.4(d), it was concluded that a detailed 

fatigue analysis is not required. The LRA further states that all of these transients except 

“pressurization” are monitored by the Fatigue Monitoring Program. The specification describes 

the “pressurization” event as pressurization to the design pressure, at the design temperature, 

which can coincide with plant cooldown and plant heatup.

The applicant dispositioned the TLAA for the fatigue design of the residual heat removal heat 

exchangers in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on the 

intended functions will be adequately managed by the Fatigue Monitoring Program for the 

period of extended operation.

Excess Letdown Heat Exchanger. The LRA state that the fatigue analysis of the excess 

letdown heat exchanger calculated a component maximum CUF of 0.154. The LRA states that 

based on the design specification, the excess letdown heat exchanger is designed for 100 

operating cycles, which facilitates unusual maintenance or repair operations which require 

isolation of the normal letdown path. The LRA also states that Callaway has initiated excess 

letdown approximately 49 times over the past 11 years and if this sample is extrapolated, then 

270 excess letdown initiation transient events would be anticipated for 60 years, resulting in a 

CUF of 0.415. The LRA further states that while the number of cycles is greater than the 

specified value, it is below the maximum allowable of 650. 

The applicant dispositioned the TLAA for the fatigue design of the excess letdown heat 

exchanger in accordance with 10 CFR 54.21(c)(1)(ii), that the analysis has been projected to 

the end of the period of extended operation.

4.3.8.2 Staff Evaluation 

The staff reviewed LRA Section 4.3.8 and the TLAAs for the fatigue design of the Class 2 

letdown heat exchanger, letdown reheat heat exchanger and excess letdown heat exchanger to 

confirm, in accordance with 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the 

end of the period of extended operation. The staff also confirmed, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of fatigue for the Class 2 RHR heat exchangers and 

regenerative heat exchanger will be adequately managed by the Fatigue Monitoring Program for 

the period of extended operation.
TIME-LIMITED AGING ANALYSES

4-81

The staff reviewed the applicant’s TLAAs for the fatigue design of the Class 2 letdown heat 

exchanger, letdown reheat heat exchanger and excess letdown heat exchanger and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.3.3.1.1.2. These procedures state that the revised CUF calculations are 

reviewed to ensure that the CUF remains less than or equal to 1.0 at the end of the period of 

extended operation. The staff also reviewed the applicant’s TLAA for the fatigue design of the 

Class 2 RHR heat exchangers and regenerative heat exchanger and the corresponding 

disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR 

Section 4.3.3.1.1.3. These procedures state that the reviewer should confirm the 

appropriateness of the applicant’s program for monitoring and tracking the number of critical 

thermal and pressure transients for the selected components.

Regenerative Heat Exchanger. LRA Section 4.3.8 states that the regenerative heat exchanger 

tubesheets, shell side nozzles, tube side nozzles, and cross shell juncture were evaluated as 

part of the fatigue analysis. Furthermore, the analysis determined that the most limiting fatigue 

usage factor was 0.50 at the outlet tubesheet. The applicant stated that the only transients that 

contribute to the CUF for this component are 200 cycles of the “letdown flow shutoff with prompt 

return to service” transient and 100 cycles of the “charging flow shutoff with prompt return to 

service” transient. 

The analysis of the regenerative heat exchanger also contains a fatigue waiver for the tube side 

inlet nozzle in which 200 cycles of the “letdown flow shutoff with prompt return to service” 

transient, 100 cycles each of the “charging flow shutoff with prompt return to service” and the 

“charging and letdown shutoff and return to service transients,” and 200 cycles each of the plant 

heatup and cooldown transients were used. The staff reviewed LRA Table 4.3-2, which 

provides a listing of transients that are monitored by the Fatigue Monitoring Program, and 

confirmed that the transients used for the CUF for the outlet tubesheet and those used for the 

fatigue waiver of the tube side inlet nozzle are included.

The staff determined that the program includes three monitoring methods (cycle counting, CBF 

monitoring, and SBF monitoring) that are capable of managing metal fatigue during the period of 

extended operation. The staff also determined that the use of these three monitoring methods 

progressively provides a more refined monitoring approach to manage metal fatigue to ensure 

that the applicable allowable design limits are not exceeded. The staff determined that these 

characteristics of the applicant’s Fatigue Monitoring Program are consistent with GALL Report 

AMP X.M1. Specifically, for the regenerative heat exchanger the applicant’s program ensures 

that the numbers of transients actually experienced during the period of extended operation 

remain below the assumed number in the fatigue analysis and waiver or corrective actions will 

be taken. The staff’s evaluation of the Fatigue Monitoring Program is documented in SER 

Section 3.0.3.2.22.

In addition, the analysis indicated that the shell side nozzles, the tube side outlet nozzle, and 

cross shell junction are areas that are not subject to fatigue. The staff finds it appropriate that 

the analysis for the regenerative heat exchanger was reviewed by the applicant to confirm that 

the shell side nozzles, the tube side outlet nozzle, and cross shell junction are not subject to 

fatigue.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of aging related to fatigue analysis of regenerative heat exchanger will be adequately 

managed for the period of extended operation. Additionally, the applicant's disposition meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting its 
TIME-LIMITED AGING ANALYSES

4-82

Fatigue Monitoring Program, which the staff determined in SER Section 3.0.3.2.22 is consistent 

with GALL Report AMP X.M1, to manage metal fatigue to ensure that the allowable design limits 

on fatigue usage are not exceeded during the period of extended operation; otherwise, the 

applicant will take corrective actions in accordance with its program.

Letdown Heat Exchanger. LRA Section 4.3.8 provides a list of eleven transients and its 

associated design cycles that may have been used in the fatigue analysis of Class 2 heat 

exchangers. Specific to the letdown heat exchanger fatigue analysis, the staff noted that 

Transients 1, 2, 4, 5, 6, 7, 8, 9, and 10 were used. The applicant stated that Transients 1, 2, 8, 

9, and 10 are monitored by the Fatigue Monitoring Program. The staff noted that these five 

transients will be cycle counted, as part of the Fatigue Monitoring Program, and involves 

initiating corrective actions if the cycle count for any one transient approaches an action limit. 

The staff’s evaluation of cycle counting monitoring method and the Fatigue Monitoring Program 

is documented in SER Section 3.0.3.2.22. The applicant stated that Transients 5 and 7 each 

with design cycles of 24,000 are load-following events. Since the design numbers of cycles for 

these transients are for a plant designed for load-following operation and the applicant does not 

operate as a load-following plant, the staff finds it reasonable that these transients are not 

monitored and that it is not credible for the occurrences of these transients to approach the 

design limit of 24,000 during the period of extended operation. The staff’s evaluation of 

Transients 4 and 6 is discussed below.

LRA Section 4.3.8 states that the fatigue analysis for the letdown heat exchanger indicated a 

maximum CUF of 1.84 for the flange, which is driven mainly by the load-following transient, 

Transient 4, “charging flow step decreased and return to normal.” The applicant stated that 

since it does not practice load-following operation, the number of cycles expected to be 

experienced is a small fraction of the number of assumed. The LRA provides an evaluation in 

which the assumed number of this transient was dropped by an order of magnitude and the 

CUF dropped to 0.894.

The staff noted that the “charging flow step decreased and return to normal” transient with a 

design limit of 24,000 cycles was based on load-following operation. Thus, it may be 

reasonable to conclude that because the applicant’s site does not practice load-following 

operation, there will be a margin between the design limit and the expected number of cycles for 

this transient through the period of extended operation. However, since the applicant reduced 

the number of cycles for this transient from 24,000 by an order of magnitude (i.e., 2,400), it is 

not clear to the staff if there is still a margin between the design number and expected number 

of cycles through the period of extended operation (i.e., approximately (3 cycles per 

month) x (12 months per year) x (60 years of operation) = 2,160 cycles). Therefore, the staff 

requires additional information to confirm the adequacy of the applicant’s disposition in 

accordance with 10 CFR 54.21(c)(1)(ii), that the CUF of 0.894 for the letdown heat exchanger 

flange has been projected to be valid through the period of extended operation. 

By letter dated September 6, 2012, the staff issued RAI 4.3-14 requesting the applicant provide 

the reason that there is sufficient margin to conclude that the TLAA has been projected to 

remain valid through the period of extended operation (i.e., 10 CFR 54.21(c)(1)(ii)), given that 

the CUF value of 0.894 may no longer be valid if the 3-occurrence-per-month assumption 

through the period of extended operation is exceeded.

In its response dated October 11, 2012, the applicant clarified that following an increase in 

reactor power, temperature increases and the reactor coolant expands causing the pressurizer 

level to rise. The applicant stated that to compensate for this, the charging flow rate decreases 
TIME-LIMITED AGING ANALYSES

4-83

while the letdown flow remains constant. The applicant also stated that, originally, the plant 

load was assumed to change twice per day (one increase and one decrease), with an 

80 percent capacity factor, which equates to 24,000 “charging flow step decrease and return to 

normal” transients. The staff noted that this original design is meant for a load-following plant. 

However, since the applicant operates its plant as base-loaded, it stated that the plant will 

normally experience power changes only at the beginning and at the end of a cycle. Based on 

these assumptions, the staff noted that since the applicant operates on an 18-month refueling 

cycle, there would be an estimated 80 load changes over a 60-year life. The staff noted that 

there is margin between this estimated 80 load changes and the 2,400 occurrences used in the 

revised analysis to accommodate any unforeseen operating issues that would necessitate a 

power reduction or increase. 

The staff finds it reasonable that the “charging flow step decrease and return to normal” 

transient is not monitored because there is significant margin between the estimated number of 

transient occurrences through 60 years based on the applicant’s base-loaded operating 

practices and the 2,400 cycles used in the analysis to account for operating issues that would 

require or have required a power reduction or increase.

The staff finds the applicant’s response acceptable because the applicant provided sufficient 

justification, as described above, that the number of “charging flow step decrease and return to 

normal” cycles assumed in the revised fatigue analysis of the letdown heat exchanger will not 

be exceeded during the period of extended operation and there is margin to account for 

unanticipated occurrences. The staff’s concern described in RAI 4.3-14 is resolved.

LRA Section 4.3.8 states that the fatigue analyses of the letdown heat exchanger also include 

the tubesheet, tube side nozzles, and the studs, with CUF values of 0.910, 0.843, and 0.635, 

respectively. It also discusses that Transient 6, “letdown flow step decrease and return to 

normal,” with a design limit of 2,000 cycles, is not a normal operating event with the plant at 

power, but was included in the analysis for conservatism. Furthermore, it states that this 

transient was assumed to occur approximately once a week for 40 years, and if this assumption 

is extended through the period of extended operation, then 3,000 events will be assumed to 

occur and the CUF will increase to 0.995, 0.880, and 0.696, respectively.

Additional information regarding the CUF contribution for each of the transients in the original 

fatigue analysis for this component is required for the staff to verify the adequacy of the TLAA 

disposition. ASME Code Section III, Paragraph NB-3222.4(e)(5), Step 1 indicates that 

transients shall be paired to produce a total stress difference range greater than the stress 

difference range of the individual cycles. It is not clear to the staff if the applicant has performed 

a CUF re-calculation consistent with the ASME Code to arrive at the conclusion that, through 

the period of extended operation, with 3,000 cycles of this transient assumed to occur, the CUF 

values will increase to 0.995, 0.880, and 0.696. Furthermore, the technical basis to support the 

assumptions that this transient occurs approximately once a week for 40 years and can be 

extended to 3,000 cycles for 60 years is not clear to the staff. In addition, it is not clear to the 

staff if these assumptions are conservative.

By letter dated September 6, 2012, the staff issued RAI 4.3-15, Part (a), requesting the 

applicant provide the CUF contribution, as documented in the original fatigue evaluation, for 

each of the transient pairing (including number of cycles used in each pairing) consistent with 

the provisions in ASME Code Section III, Paragraph NB-3222.4(e)(5). The staff also requested, 

in Part (b), that the applicant confirm that the CUF value has been recalculated consistent with 

ASME Code Section III Paragraph NB-3222.4(e)(5), to reach its assumption that the “letdown 
TIME-LIMITED AGING ANALYSES

4-84

flow step decrease and return to normal” transient can be extended to 3,000 cycles for 60 years. 

In Part (c), the staff requested that the applicant justify the assumptions that the "letdown flow 

step decrease and return to normal" transient occurs approximately once a week for 40 years 

and can be extended to 3,000 cycles for 60 years. 

In its response to RAI 4.3-15, Part (a), dated October 11, 2012, the applicant provided the CUF 

contributions from the tube side nozzle, tubesheet and stud stress report as documented in the 

original fatigue evaluation for the letdown heat exchanger, for each of the transient pairings

(including number of cycles used in each pairing). The applicant also confirmed that the 

letdown heat exchanger CUF will be less than 1.0 if the number of “letdown flow step decrease 

and return to normal” transient events is increased to 3,000 cycles, consistent with ASME Code 

Section III, Paragraph NB-3222.4(e)(5). The staff noted that ASME Code Section III, 

Paragraph NB-3222.4(e)(5) provides the required procedures to analyze cyclic loading. 

In its response to RAI 4.3-15, Part (b), the applicant stated that the letdown heat exchanger 

tubesheet CUF contribution by the “letdown flow decrease and return to normal” transient would 

increase from 0.169 (0.144 + 0.018 + 0.007) to 0.2535 (1.5 x (0.144 + 0.018 + 0.007)). In 

addition, the applicant stated that this will increase the CUF from 0.910 to 0.995 and the 

response also provided the CUF contribution for each transient pair. 

Based on staff’s review of Table 4, “Tubesheet Fatigue Table for the Letdown Heat Exchanger” 

in the applicant’s response, the CUF contribution from the third transient pair “#6 letdown flow 

decrease and return to normal [254 °C to 143 °C] (490 °F to 290 °F)” and “#6 letdown flow 

decrease and return to normal [60 °C to 193 °C] (140 °F to 380 °F)” would increase to 0.224 

[(0.144/1,800) x 2,800]. Thus, the CUF contribution by the “letdown flow decrease and return to 

normal” transient would increase from 0.169 to 0.2615 (0.224 + 1.5 x (0.018 + 0.007)), as 

opposed to the applicant’s conclusion of 0.2535. 

The staff noted that this will increase the CUF from 0.910 to over 1.00. The staff noted that the 

CUF value must not exceed 1.0, which is the ASME Code Section III CUF requirement. The 

staff noted that the applicant must demonstrate that the recalculated CUF value will not exceed

1.0 through the period of extended operation to support the TLAA disposition in accordance with 

10 CFR 54.21(c)(1)(ii). 

By letter dated November 21, 2012, the staff issued RAI 4.3-15a requesting that the applicant 

justify that the recalculated CUF value does not exceed 1.0 assuming 3,000 cycles of “letdown 

flow decrease and return to normal” transient will occur through the period of extended 

operation. 

In its response to RAI 4.3-15a dated December 13, 2012, the applicant provided an updated 

Table 5, “Tubesheet Fatigue Table for the Letdown Heat Exchanger.” The applicant identified 

and corrected another error in the original design report, which affected the 7th transient pairing 

(“letdown flow increase and return to normal” at “[207 °C to 137 °C] (405 °F to 279 °F)” and 

“[143 °C to 207 °C] (290 °F to 405 °F)”), and resulted in an updated CUF of 0.903.

The applicant continued to explain that the 7th transient pairing erroneously includes 24000 

events of “letdown flow increase and return to normal” at “(405°F to 279°F)” & “(290°F to 

405°F).” The staff noted that when the number of “letdown flow decrease and return to normal” 

events is increased to 3000, as described in LRA Section 4.3.8, the number of paired events 

would decrease to 21000 events for the 7th transient. 
TIME-LIMITED AGING ANALYSES

4-85

The staff noted that, based on the corrected transient pairing and the corrected error identified 

by the staff in RAI 4.3-15a, the updated CUF for 60 years does not exceed the Code design limit 

of 1.0. The staff reviewed the information in the applicant’s response, including the updated 

Table 5, “Tubesheet Fatigue Table for the Letdown Heat Exchanger,” and determined that the 

calculation was performed consistent with ASME Code Section III NB-3222.4(e)(5).

In its response to RAI 4.3-15, Part (c), dated October 11, 2012, the applicant also stated that the 

“letdown flow step decrease and return to normal” transient is assumed to occur 2,000 times 

during the 40-year plant design life and if the number of events were extended through the 

period of extended operation, then 3,000 events will be assumed to occur. The applicant also 

explained that the letdown flow rate can be changed manually by switching from one letdown 

orifice to another or by valving in an additional orifice. The applicant stated that letdown flow is 

normally only changed to initiate maximum purification or to make boron concentration changes 

associated with load follow and plant shutdown, and both of these operations would normally 

involve an increase in letdown flow. Finally, the applicant stated that letdown flow reductions 

“do not support the typical operation” of the plant, and there are currently no plans to implement 

a letdown flow reduction below nominal letdown flow (75 gpm). The staff reviewed FSAR 

Section 9.3.4.2.3.2 SP and noted that the letdown flow would be 120 gpm during normal 

operation with maximum purification. 

The staff noted that since the applicant currently operates its plant on 18-month refueling cycles, 

it can be expected that approximately 40 cycles would occur in a 60-year timeframe because of 

plant shutdowns. The staff finds it reasonable that the applicant’s assumed margin 

(approximately 2,960 cycles) accounts for the expected occurrences of the “letdown flow step 

decrease and return to normal” transient through the period of extended operation.

The staff finds the applicant’s responses to RAIs 4.3-15 and 4.3-15a acceptable because the 

CUFs for the letdown heat exchanger (tubesheet, tube-side nozzle and stud) were recalculated 

and shown to be less than the design limit of 1.0 consistent with ASME Code Section III NB 

3222.4(e)(5) and the applicant sufficiently justified, as described below, its assumption to 

increase the number of cycles for Transient 6 to 3,000. The staff’s concerns described in 

RAIs 4.3-15 and 4.3-15a are resolved.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis for the letdown heat exchanger has been projected to the end of the period of extended 

operation. Additionally, it meets the acceptance criteria of SRP-LR Section 4.3.2.1.1.2 because 

the applicant has demonstrated that the number of operating cycles anticipated for 60 years of 

operation for the letdown heat exchanger will not be exceeded through the period of extended 

operation with sufficient margin to account for unanticipated operating cycles and the 

recalculated CUF values are less than the design limit of 1.0.

Letdown Reheat Heat Exchanger. LRA Section 4.3.8 provides a list of eleven transients and its 

associated design cycles that may have been used in the fatigue analysis of Class 2 heat 

exchangers. Specifically, Transients 1, 2, 4, 5, 6, 7 and 11 were used in the letdown reheat 

heat exchanger fatigue analysis. The applicant stated that Transients 1 and 2 are monitored by 

the Fatigue Monitoring Program. The staff noted that these two transients will be cycle counted, 

as part of the Fatigue Monitoring Program, and involves initiating corrective actions if the cycle 

count for any one transient approaches an action limit. The staff’s evaluation of cycle counting 

monitoring method and the Fatigue Monitoring Program is documented in SER 

Section 3.0.3.2.22. The applicant stated that Transients 4 and 5 each with design cycles of 

24,000 are load-following events. Since the design numbers of cycles for these transients are 
TIME-LIMITED AGING ANALYSES

4-86

for a plant designed for load-following operation and the applicant does not operate as a 

load-following plant, the staff finds it reasonable that these transients are not monitored and that 

it is not credible for the occurrences of these transients to approach the design limit of 24,000 

during the period of extended operation. The staff’s evaluation of Transients 6, 7, and 11 are 

discussed below.

LRA Section 4.3.8 states that the fatigue analysis for the letdown reheat heat exchanger 

indicated a maximum CUF of 4.431 for the studs, which is driven mainly by the load-following 

transients, “letdown flow step increase and return to normal” and “load follow boration.” 

Furthermore, the LRA states that it does not practice load-following operation and the assumed 

number of these transients was dropped by an order of magnitude and the CUF dropped to 

about 0.503.

The staff noted that the Transient 7, “letdown flow step increase and return to normal,” and 

Transient 11, “load follow boration,” each with a design limit of 24,000 cycles, were based on 

load-following operation; thus, it may be reasonable to conclude that because the applicant’s 

site does not practice load-following operation there will be margin between the design limit and 

the expected number of cycles for these transients. However, since the applicant reduced the 

number of cycles for these transients from 24,000 by an order of magnitude (i.e., 2,400), it is not 

clear to the staff if there is still a margin between the design number and expected number of 

cycles through the period of extended operation. Thus, the staff requires additional information 

to verify the adequacy of the applicant’s disposition in accordance with 10 CFR 54.21(c)(1)(ii), 

that the CUF of 0.503 for the letdown reheat heat exchanger studs has been projected to be 

valid through the period of extended operation.

By letter dated September 6, 2012, the staff issued RAI 4.3-16 requesting the applicant provide 

the basis that there is sufficient margin to conclude that the TLAA has been projected to remain 

valid through the period of extended operation (i.e., 10 CFR 54.21(c)(1)(ii)), given that the CUF 

value of 0.503 may no longer be valid if, for each transient (“letdown flow step increase and 

return to normal” and “load follow boration”), a three-occurrence-per-month assumption through 

the period of extended operation is exceeded.

In its response to RAI 4.3-16 dated October 11, 2012, the applicant stated that the letdown 

reheat heat exchanger is part of the boron thermal regeneration (BTR) system and is used to 

heat the BTR system process fluid flowing through the shell side. The applicant stated that the 

“letdown flow step increase and return to normal” and “load follow boration” transients are 

load-following transients and they are meant to compensate for changes in the RCS water 

volume and boron concentration that accompany load changes. The staff noted that the 

applicant’s original plant design assumed that it would be a load-following plant. However, 

since the applicant operates its plant as base-loaded, it stated that, ideally, the plant will 

experience power changes only at the beginning and at the end of a cycle. Based on these 

assumptions, the staff noted that since the applicant operates on an 18-month refueling cycle 

there would be an estimated 80 load changes over a 60-year life. The staff noted that there is 

margin between this estimated 80 load changes and the 2,400 occurrences used in the revised 

analysis to accommodate any unforeseen operating issues that would necessitate a power 

reduction or increase. 

The staff finds it reasonable that “letdown flow step increase and return to normal” and “load 

follow boration” transients are not monitored because there is significant margin between the 

estimated number of transients occurrences through 60 years, based on the applicant’s 
TIME-LIMITED AGING ANALYSES

4-87

base-loaded operating practices, and the 2,400 cycles used in the analysis to account for 

operating issues that would require or have required a power reduction or increase. 

The staff finds the applicant’s response acceptable because the applicant provided sufficient 

justification, as described above, that the number of “letdown flow step increase and return to 

normal” and “load follow boration” transient cycles assumed in the revised fatigue analysis of 

the letdown reheat exchanger will not be exceeded during the period of extended operation and

there is a margin to account for unanticipated occurrences. The staff’s concern described in 

RAI 4.3-16 is resolved.

LRA Section 4.3.8 states that the fatigue analyses of the letdown reheat heat exchanger also 

include the shell and tube side nozzles and tubesheet, with CUF values of 0.054 and 0.47, 

respectively. The LRA discusses the transients that were included in the fatigue analyses for 

these components, the transients that will be monitored by the Fatigue Monitoring Program and 

the transients that will not be monitored. Specifically, for the Transient 6, “letdown flow step 

decrease and return to normal,” with a design limit of 2,000 cycles, if the number of events is 

extended through the period of extended operation, then 3,000 events will be assumed to occur 

and the CUFs will increase to 0.57 for the tubesheet and 0.0563 for the tube side nozzles. 

Additional information regarding the CUF contribution for each of the transients in the original 

fatigue analysis for this component is required for the staff to verify the adequacy of the TLAA 

disposition. ASME Code Section III Paragraph NB-3222.4(e)(5) Step 1 indicates that transients 

shall be paired to produce a total stress difference range greater than the stress difference 

range of the individual cycles. It is not clear to the staff if the applicant has performed a CUF 

recalculation, consistent with the ASME Code, to arrive at the conclusion that, through the 

period of extended operation with 3,000 cycles of this transient assumed to occur, the CUF

values will increase to 0.57 for the tubesheet and 0.0563 for the tube side nozzles. 

Furthermore, the technical basis to support the assumption that this transient can be extended 

to 3,000 cycles for 60 years is not clear to the staff. In addition, it is not clear to the staff if this 

assumption is conservative.

By letter dated September 6, 2012, the staff issued RAI 4.3-17 requesting, in Part (a), that the 

applicant provide the CUF contribution, as documented in the original fatigue evaluation, for 

each of the transient pairing (including number of cycles used in each pairing) consistent with 

the provisions in ASME Code Section III, Paragraph NB-3222.4(e)(5). The applicant was also 

requested, in Part (b), to confirm that the CUF value has been recalculated consistent with 

ASME Code Section III, Paragraph NB-3222.4(e)(5), and was requested in Part (c) to justify its 

assumption that the “letdown flow step decrease and return to normal” transient can be 

extended to 3,000 cycles for 60 years. The applicant was requested, in Part (d), to clarify the

nozzles CUFs that are not affected by the increase for this transient.

In its response to RAI 4.3-17, Parts (a) and (b), dated October 11, 2012, the applicant provided 

the CUF contributions from the tube side nozzle and tubesheet stress report as documented in 

the original fatigue evaluation for the letdown reheat heat exchanger, for each of the transient 

pairing (including number of cycles used in each pairing) consistent with ASME Code 

Section III, Paragraph NB-3222.4(e)(5).

The applicant also confirmed that the letdown reheat heat exchanger CUF will be less than 1.0 if 

the number of “letdown flow step decrease and return to normal” transient events is increased to 

3,000 cycles, consistent with ASME Code Section III, Paragraph NB-3222.4(e)(5). The staff 

noted that ASME Code Section III, Paragraph NB-3222.4(e)(5) provides the required 

procedures to analyze cyclic loading. The applicant stated that the LRA incorrectly states 0.57 
TIME-LIMITED AGING ANALYSES

4-88

as the increased CUF for the tubesheet and that the LRA was revised to identify the corrected 

CUF value of 0.50 for the tubesheet.

In its response to RAI 4.3-17, Part (c), the applicant also stated in its response that the “letdown 

flow step decrease and return to normal” transient is assumed to occur 2,000 times during the 

40-year plant design life and if the number of events were extended through the period of 

extended operation, then 3,000 events will be assumed to occur. The applicant also explained 

that the letdown flow rate can be changed manually by switching from one letdown orifice to 

another or by valving in an additional orifice. However, it is only normally changed to initiate 

maximum purification or to affect boron concentration changes associated with load follow and 

plant shutdown and there are currently no plans to implement a letdown flow reduction below 

nominal letdown flow (75 gpm). The staff reviewed FSAR Section 9.3.4.2.3.2 SP and noted that 

the letdown flow would be 120 gpm during normal operation with maximum purification. The 

applicant stated that the letdown flow reduction does not support the typical operation of the 

plant, such as to commence maximum purification or load following operation. 

The staff noted that since the applicant currently operates its plant on 18-month refueling cycles, 

it can be expected that approximately 40 cycles occur because of plant shutdowns. In addition, 

since the applicant does not operate as a load-following plant or operate in such a manner to 

normally initiate maximum purification, the staff finds it reasonable that there is margin 

(approximately 2,960 cycles) to account for occurrences of the “letdown flow step decrease and 

return to normal” transient through the period of extended operation.

In response to RAI 4.3-17, Part (d), the applicant revised the letdown reheat heat exchanger 

portion of LRA Section 4.3.8 to delete the statement “[t]he nozzles CUFs are not affected by this 

increase.” The staff noted this statement was referring to the original design fatigue analyses 

and the applicant confirmed that these analyses are not the “current” fatigue analysis used to 

support the LRA. The staff finds the revision of LRA Section 4.3.8 acceptable because the 

confusion as to whether the tube side nozzles CUFs were affected by the increase of the 

“letdown flow step decrease and return to normal” transient to 3,000 cycles has been 

eliminated. 

The staff finds the applicant’s response acceptable because the CUFs for the letdown reheat 

heat exchanger were recalculated and shown to be less than the design limit of 1.0 consistent 

with ASME Code Section III, Paragraph NB-3222.4(e)(5) and the applicant sufficiently justified, 

as described above, its assumption to increase the number of cycles for Transient 6 to 3,000. 

The staff’s concern described in RAI 4.3-17 is resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that 

the analysis for the letdown reheat heat exchanger has been projected to the end of the period 

of extended operation. Additionally, it meets the acceptance criteria of SRP-LR 

Section 4.3.2.1.1.2 because the applicant has demonstrated that the number of operating cycles 

anticipated for 60 years of operation for the letdown reheat heat exchanger will not be exceeded 

through the period of extended operation with sufficient margin to account for unanticipated 

operating cycles and the recalculated CUF values are considerably less than the design limit of 

1.0 (i.e., 0.50 for the tubesheet and 0.0563 for the tube side nozzles).

Residual Heat Removal Heat Exchangers. LRA Section 4.3.8 provides a list of transients that 

were in the design specification for RHR heat exchangers. It also states that the fatigue 

analysis for the RHR heat exchangers explained that a fatigue analysis is not necessary for 

these transients since they are very weak and when these transients were put through the 

criteria of ASME Code Section III, Paragraph NB-3222.4(d), it was concluded that a detailed 
TIME-LIMITED AGING ANALYSES

4-89

fatigue analysis is not required. The LRA continues to explain that all of these transients except 

“pressurization” are monitored by the Fatigue Monitoring Program and that the design 

specification describes the “pressurization” event as pressurization to the design pressure, at 

the design temperature and “can” coincide with plant cooldown and plant heatup. Based on this 

statement, the staff needed to confirm if the “pressurization” transient can also coincide with 

transients other than plant cooldown and plant heatup.

By letter dated September 6, 2012, the staff issued RAI 4.3-18, Part (a), requesting that the 

applicant confirm that the “pressurization” transient can only coincide with plant cooldowns and 

plant heatups and cannot coincide with any other transient. The applicant was also requested, 

in Part (b), to clarify if the “pressurization” transient will definitively coincide with each and every 

occurrence of the identified transient(s).

In its response to RAI 4.3-18, Part (a), dated October 11, 2012, the applicant clarified that the 

RHR system can only be placed in service below a RCS temperature of 177 °C (350 °F) and a 

RCS pressure less than 450 psig and these pressure and temperature conditions require a plant 

cooldown or heatup. Therefore, the applicant determined that the plant cooldown and plant 

heatup will conservatively account for the “pressurization” transient of the RHR heat 

exchangers. The staff reviewed the FSAR Section 1.2.9.2 and noted that the RHR systems is 

designed to remove heat from the reactor coolant at a controlled rate when the reactor coolant 

pressure is less than 450 psig and the temperature is from 177 °C (350 °F) to 60 °C (140 °F).

Based on the RHR system design, the staff finds it reasonable that the “pressurization” 

transient, as used in the RHR heat exchanger fatigue analysis, is considered to coincide with a 

plant cooldown cycle or a plant heat up cycle. In addition, since the total number of design 

cycles for plant cooldowns and plant heatups (400 total cycles) is equal to the number of design 

cycles for the “pressurization” transient (400 cycles); the staff finds its reasonable that

monitoring of plant heatup and cooldown cycles with the Fatigue Monitoring Program will ensure 

the design limit on the “pressurization” transient will not be exceeded during the period of 

extended operation. 

Based on the acceptability of the applicant’s response to RAI 4.3-18, Part (a), as described 

above, Part (b) of the request is moot.

The staff finds the applicant’s response acceptable because the applicant confirmed that the 

“pressurization” transient coincides with a plant heat up or plant cooldown and the Fatigue 

Monitoring Program, as described above, ensures that the design limit of the “pressurization” 

transient will not be exceeded during the period of extended operation. The staff’s concern 

described in RAI 4.3-18 is resolved.

The staff determined that the Fatigue Monitoring Program includes three monitoring methods 

(cycle counting, CBF monitoring and SBF monitoring) that are capable of managing metal 

fatigue during the period of extended operation. The staff also determined that the use of these 

three monitoring methods progressively provides a more refined monitoring approach to 

manage metal fatigue to ensure that the applicable allowable design limits are not exceeded. 

The staff determined that these characteristics of the applicant’s Fatigue Monitoring Program 

are consistent with GALL Report AMP X.M1. Specifically for the RHR heat exchangers, the 

applicant’s program ensures that the numbers of transients actually experienced during the 

period of extended operation remain below the assumed number in the fatigue waiver or 

corrective actions will be taken. The staff’s evaluation of the Fatigue Monitoring Program is 

documented in SER Section 3.0.3.2.22.
TIME-LIMITED AGING ANALYSES

4-90

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of aging related to fatigue waiver of RHR heat exchangers will be adequately 

managed for the period of extended operation. Additionally, the applicant's disposition meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting its 

Fatigue Monitoring Program, which the staff determined in SER Section 3.0.3.2.22 is consistent 

with GALL Report AMP X.M1, to manage metal fatigue to ensure that the allowable design 

cycles established in the fatigue waiver are not exceeded during the period of extended 

operation; otherwise, the applicant will take corrective actions in accordance with its program.

Excess Letdown Heat Exchanger. LRA Section 4.3.8 states that excess letdown heat 

exchanger calculated a component maximum CUF of 0.154. In addition, based on the design 

specification this heat exchanger is designed for 100 operating cycles. The staff noted that 

these operating cycles are meant to facilitate unusual maintenance or repair operations which 

require isolation of the normal letdown path. The applicant stated that it has initiated excess 

letdown approximately 49 times over the past 11 years and if this sample is extrapolated, then 

270 excess letdown initiation transient events would be anticipated for 60 years, which results in 

a CUF of 0.415.

By letter dated December 13, 2012, as part of its response to RAI 4.3-2a the applicant provided 

Table 1, “Accumulation Rates that Support the 60-Year Projections,” which clarified that the 

excess letdown heat exchanger operation transient did not rely on a short-term and long-term 

weighting of transient occurrences for the 60-year projection. The applicant’s Table 1 in 

RAI 4.3-2a response also clarified that a linear extrapolation was used that encompassed

transient occurrence from initial plant start-up until 2011 to determine the 60-year projection. 

The staff’s evaluation of RAI 4.3-2a is documented in SER Section 4.3.1.2.2. The staff finds the 

linear extrapolation of the excess letdown heat exchanger operation transient conservative 

because it takes into account early plant operation when transient occurrences were common, 

which was prior to the applicant incorporating operating practices to reduce transient 

occurrences at Callaway. The staff finds it reasonable that the applicant will continue to 

improve its ability to operate its plant based on operating experience and limit the number of 

operating cycles to facilitate unusual maintenance or repair operations that require isolation of 

the normal letdown path. In addition, the staff finds that there is sufficient margin between the 

applicant’s anticipated number of operating cycles for 60 years of operation (270) compared to 

the allowable of number of operating cycles (650) that equate to the a CUF limit of 1.0 to 

account for unanticipated operating cycles that would require isolation of the normal letdown 

path.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that 

the analysis for the excess letdown heat exchanger has been projected to the end of the period 

of extended operation. Additionally, it meets the acceptance criteria of SRP-LR 

Section 4.3.2.1.1.2 because the applicant has demonstrated that the number of operating cycles 

anticipated for 60 years of operation will be less than the design through the period of extended 

operation with sufficient margin to account for unanticipated operating cycles.

4.3.8.3 FSAR Supplement

LRA Section A3.2.7 provides the FSAR supplement summarizing the TLAA for Class 2 heat 

exchangers. The staff reviewed LRA Section A3.2.7 consistent with the review procedures in 

SRP-LR Section 4.3.3.2, which state that the reviewer verifies that the applicant has provided 

information to be included in the FSAR supplement that includes a summary description of the 

evaluation of the metal fatigue TLAA.
TIME-LIMITED AGING ANALYSES

4-91

Based on its review of the FSAR supplement, as amended by letters dated October 11, 2012, 

and December 13, 2012, the staff finds it meets the acceptance criteria in SRP-LR Section 

4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the applicant 

provided an adequate summary description of its actions to address the TLAA for Class 2 heat 

exchangers, as required by 10 CFR 54.21(d).

4.3.8.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the TLAAs for the letdown heat, letdown 

reheat, and excess letdown heat exchangers have been projected to the end of the period of 

extended operation. The staff also concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of metal fatigue on the intended functions of the 

regenerative heat exchangers and RHR heat exchangers, will be adequately managed by the 

Fatigue Monitoring Program for the period of extended operation. The staff also concludes that 

the FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.4 Environmental Qualification (EQ) of Electric Equipment

4.4.1 Summary of Technical Information in the Application

LRA Section 4.4 describes the applicant’s TLAA for the evaluation of EQ for the period of 

extended operation. The applicant stated that the EQ of Electric Equipment Program is 

consistent with the requirements of NUREG-0588, Revision 1, “Interim Staff Position on 

Environmental Qualification of Safety-Related Electrical Equipment,” Category I and is also 

committed to RG 1.89, Revision 0, “Environmental Qualification of Certain Electric Equipment 

Important to Safety for Nuclear Power Plants,” dated November 1974. The LRA states that 

“[t]he EQ [of Electric Equipment] manages applicable component thermal, radiation, and cyclic 

aging effects through the aging evaluations for the current operating license using methods for 

qualification for aging and accident conditions established by 10 CFR 50.49(f).” In addition, the 

LRA states that “re-analysis of an aging evaluation to extend the qualification of components is 

performed on a routine basis as part of the EQ [of Electric Equipment].” The LRA further states 

that “important attributes of reanalysis include analytical methods, data collection and reduction 

methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance 

criteria are not met).”

The applicant dispositioned the TLAA for EQ of the electric equipment, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of thermal, radiation, and cyclical aging on the intended 

functions will be adequately managed by the EQ of Electrical Components Program for the 

period of extended operation.

4.4.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for EQ of the electric equipment and the corresponding 

disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR 

Section 4.4.3.1.3, which state that an applicant must demonstrate the effects of aging on the 

intended function(s) will be adequately managed for the period of extended operation.

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 
TIME-LIMITED AGING ANALYSES

4-92

specifications during and following design basis accidents. The 10 CFR 50.49 EQ of the 

Electric Equipment Program is a TLAA for purposes of license renewal. These components 

have a qualified life equal to or greater than the current operating term and are covered by a 

TLAA. The TLAA of 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 loss-of-coolant accident (LOCA), a high-energy line break 

(HELB), or post-LOCA environment. EQ equipment comprises safety-related and 

nonsafety-related equipment, the failure of which could prevent satisfactory accomplishment of 

any safety-related function and necessary post-accident monitoring equipment.

As required by 10 CFR 54.21(c)(1), the applicant must provide a list of EQ electrical equipment 

TLAAs. The applicant shall demonstrate one of the following for each type of EQ equipment 

TLAAs: (1) that the analyses remain valid for the period of extended operation, (2) that the 

analyses have been projected to the end of the period of extended operation, or (3) that the

effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation.

The staff reviewed LRA Sections 4.4 and B3.2, “Environmental Qualification (EQ) of Electrical 

Components,” plant basis documents, and additional information provided to the staff. It also 

interviewed plant personnel to verify whether the applicant provided adequate information to 

meet the requirement of 10 CFR 54.21(c)(1). For electrical equipment, the applicant used 

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 the GALL 

Report, plant EQ programs that implement the requirements of 10 CFR 50.49 are considered 

acceptable AMPs under license renewal 10 CFR 54.21(c)(1)(iii). GALL Report AMP X.E1, 

“Environmental Qualification (EQ) of Electric Components,” provides a means to meet the 

requirements of 10 CFR 54.21(c)(1)(iii). The staff reviewed the applicant’s EQ of Electric 

Equipment Program to determine whether it will ensure that the electrical and I&C components 

covered under this program will continue to perform their intended functions, consistent with the 

CLB, for the period of extended operation.

The staff’s evaluation of the components qualification focused on how the EQ of Electric 

Equipment Program manages the aging effects to meet the requirements, in accordance with 

10 CFR 50.49. The staff conducted an audit of the information provided in LRA Sections 4.4 

and B.3.2 and the program basis documents. LRA Section B3.2 discusses the component 

reanalysis attributes, including analytical models, data collection and reduction methods, 

underlying assumptions, acceptance criteria, and corrective actions. On the basis of its audit

and evaluation of the AMP as documented in SER Section 3.0.3.1.19, the staff finds that the EQ 

of Electric Equipment Program, which the applicant claimed to be consistent with GALL Report 

AMP X.E1, is consistent with the GALL Report. Therefore, the staff concludes that the 

applicant’s EQ of Electric Equipment TLAA is implemented per the requirements of 

10 CFR 54.21(c)(1)(iii). 

The staff noted that LRA Section 4.4, “Environmental Qualification (EQ) of Electric Equipment,” 

includes a discussion of mechanical EQ and states that the qualification for some mechanical 

equipment extends beyond 40 years. The LRA also states that the EQ of Electric Equipment 

TLAA also manages the aging of mechanical components.

However, SRP-LR Section 4.4, “Environmental Qualification (EQ) of Electric Equipment,” 

Subsection 4.4.1, “Areas of Review,” states that some nuclear power plants have mechanical 
TIME-LIMITED AGING ANALYSES

4-93

equipment that was qualified in accordance with the provisions of Criterion 4 of Appendix A to 

10 CFR Part 50. If a plant has qualified mechanical equipment, it is typically documented in the 

plant’s master EQ list. If this qualified mechanical equipment requires the performance of a 

TLAA, it should be performed in accordance with the provisions of SRP-LR Section 4.7, “Other 

Plant-Specific Time-Limited Aging Analysis.” If a TLAA of qualified mechanical equipment is 

necessary, it usually involves the environmental effects on components such as seals, gaskets, 

lubricants, hydraulic fluid, or diaphragms. 

The inclusion of mechanical components in EQ of Electric Equipment TLAA is inconsistent with 

the guidance provided in SRP-LR Section 4.4.1, “Areas of Review.” In addition LRA Table 3.6-1, 

Item 3.6.1.001, does not identify mechanical equipment as a component type for the EQ of 

Electric Equipment TLAA. By letter dated August 23, 2012, the staff issued RAI 4.4-1 

requesting the applicant to explain why EQ of mechanical components is included in LRA 

Section 4.4, “Environmental Qualification (EQ) of Electric Components,” contrary to the 

guidance provided in SRP-LR 4.4.1 with regard to TLAAs for mechanical components and 

associated AMR items. The staff also requested the applicant to explain the discrepancy 

between LRA Sections B3.2, 4.4, A2.2, and A3.3 with regard to the inconsistency in the 

application of aging management of EQ of mechanical components. In addition, the staff 

requested the applicant to explain why the component type (electrical equipment) in LRA 

Table 3.6-1, Item 3.6.1-1, is inconsistent with LRA Section 4.4 that includes electrical and 

mechanical components.

In response letter dated September 20, 2012, the applicant stated that it has revised the 

following LRA sections as shown in LRA Amendment 10, to address the following:

(1) The EQ of mechanical equipment discussion was removed from Section 4.4, 

“Environmental Qualification (EQ) of Electric Components,” and a new Section 4.7.10, 

“Mechanical Environmental Qualification,” was created.

(2) The environmental qualification of mechanical equipment discussion was removed from 

Appendix A3.3, “Environmental Qualification (EQ) of Electric Components,” and a new 

Section A3.6.10, “Mechanical Environmental Qualification,” was created.

(3) Appendix A2.2 and Appendix B3.2 for the Environmental Qualification of Electrical 

Components Program were updated to be consistent with the mechanical [EQ] 

disposition in Section 4.7.10.

(4) Table 3.6.2-1 was revised to include a line for mechanical environmental qualification 

components. Further evaluation 3.6.2.2.1 also was revised to identify mechanical [EQ]

components.

(5) Section 2.5.1.15 was added for mechanical environmental qualification components, and 

conforming changes were incorporated in Section 2.5 and Section 2.1.2.3.2.

(6) Conforming changes were made to Table 4.1-1, List of TLAAs.

The staff finds the applicant response acceptable because the removal of mechanical EQ from 

LRA Section 4.4 and the creation of a new LRA Section 4.7.10 for mechanical EQ is consistent 

with the guidance provided in SRP-LR Section 4.4.1, which states that a TLAA for mechanical 

components should be performed under the provision of SRP-LR Section 4.7, “Other 

Plant-Specific Time-Limited Aging Analysis.” The staff also finds the associated LRA changes 

consistent with the addition of a separate TLAA for mechanical EQ. The staff evaluation of LRA 

Section 4.7.10, “Mechanical Environmental Qualification,” is provided in SER Section 4.7.10. 

The staff’s concern described in RAI 4.4-1 is resolved.
TIME-LIMITED AGING ANALYSES

4-94

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of thermal, radiation, and cyclical aging on the intended functions of the electric

equipment will be adequately managed for the period of extended operation. 

Additionally, the changes meet the acceptance criteria in SRP-LR Section 4.4.2.1 because the 

applicant’s EQ of Electrical Components Program is capable of programmatically managing the 

qualified life of components within the scope of the program for license renewal. The continued 

implementation of the EQ of Electrical Components Program provides assurance that the aging 

effects will be managed and that components within the scope of the EQ of Electric Equipment 

TLAA will continue to perform their intended functions for the period of extended operation.

4.4.3 FSAR Supplement

LRA Section A2.2 provides the FSAR supplement summarizing the EQ of Electric Equipment 

TLAA. The staff reviewed LRA Section A2.2, as revised in LRA Amendment 10, consistent with 

the review procedures in SRP-LR Section 4.4.3.2, which state that the reviewer verifies that the 

applicant has provided information to be included in the FSAR supplement that includes a 

summary description of the evaluation of the EQ of electrical equipment TLAA.

Based on its review of the EQ of Electrical Components FSAR supplement, the staff finds that 

LRA Section A2.2, as revised in LRA Amendment 10, meets the acceptance criteria in SRP-LR 

Section 4.4.2.2. Additionally, the staff determines that the applicant provided an adequate 

summary description of its actions to address the EQ of electric equipment TLAA for the period 

of extended operation, as required by 10 CFR 54.21(d).

4.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of thermal, radiation, 

and cyclical aging on the intended functions of the electric equipment will be adequately 

managed by the EQ of Electrical Components Program for the period of extended operation. 

The staff also concludes that the FSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.5 Concrete Containment Tendon Prestress

4.5.1 Summary of Technical Information in the Application

LRA Section 4.5, as amended by the applicant’s LRA Amendment 37 in its letter dated 

June 17, 2014, describes the applicant’s TLAA for its post-tensioned concrete containment 

structure with a cylindrical wall, a hemispherical dome, and a flat foundation slab. The LRA 

states that the post-tensioned tendons compress the concrete and permit the structure to 

withstand design basis accident internal pressures. The LRA also states that the Callaway 

post-tensioning system consists of 86 vertical, inverted U-shaped tendons, 135 cylinder hoop 

tendons, and 30 dome hoop tendons (for a total of 165 horizontal hoop tendons). The LRA 

further states that the vertical tendons extend through the full height of the cylindrical walls, are 

draped over the dome, and are anchored at the bottom of the base slab. The cylinder hoop 

tendons are anchored at buttresses located 240 degrees apart. The 30 hemispherical dome 

hoop tendons start at the springline and continue up to an approximate 45-degree vertical angle 

from the springline. Collectively, the inverted U-shaped vertical tendons and the horizontal 

dome tendons prestress the hemispherical dome. 
TIME-LIMITED AGING ANALYSES

4-95

The LRA states that the tendons are made of approximately 170 high-strength steel wires 0.64 

centimeters (0.25 in.) in diameter and have an ultimate strength of approximately 1,000 tons. 

The LRA also states that the applied prestressing load is transferred to the structure through 

steel bearing plates embedded in concrete and the tensioned steel tendons relax with time while 

the concrete structure, which the tendons hold in compression, both creeps and shrinks. 

The LRA states that tendon surveillances are performed under the Inservice Inspection Program 

per ASME Code Section XI, Subsection IWL, to ensure the integrity of the containment pressure 

boundary under design basis accident loads. The LRA also states that the acceptance criteria 

compare the measured individual tendon forces against the predicted lower limit (PLL) force 

lines, and the surveillance includes separate regression analyses for the vertical and horizontal 

tendon groups. The LRA further states that the analyses are used to confirm whether average 

prestress forces are expected to remain above their minimum required values (MRVs) for the 

remainder of the licensed operating period.

The LRA states that PLL and the regression analyses predict the future performance of the 

post-tensioning system to the end of design life and are TLAAs. The LRA also states that the 

tendon surveillance results from 2010, the 25-year tendon surveillance, found no significant 

abnormal degradation and no lift-off values from this surveillance below the predicted force line. 

The discussion below reviews the three parameters used in the implementation of the tendon 

surveillance program: MRV, PLL force lines, and the regression analysis.

Minimum Required Value. The LRA states that the MRV is the average tendon prestress force 

used in the prestressed concrete containment design analysis. The design prestress must 

account for the loss of prestressing force after the initial tensioning, in accordance with 

RG 1.35.1, “Determining Prestressing Forces for Inspection of Prestressed Concrete 

Containments.” The LRA also states that the MRV is the acceptance criterion for the average 

tendon prestressing force over the entire plant life; it does not vary with the plant life. The 

applicant concluded that the MRV is not a TLAA because is not in accordance with Criterion 3 of 

10 CFR 54.3(a), which states that TLAA for the purposes of this part “involve time-limited 

assumptions defined by the current operating term; for example, 40 years.”

Predicted Lower Limit. The LRA, as amended by LRA Amendment 37 dated June 17, 2014,

states:

[t]he Concrete Containment Tendon Prestress program (Section B3.3), which is 

part of the ASME Section XI, Subsection IWL lnservice Inspection program, 

manages loss of tendon prestress. Predicted force lines are incorporated in the 

Concrete Containment Tendon Prestress program to identify any abnormal 

degradation in tendon prestressing force, 

The amended LRA also states that the predicted loss lines determine the PLL force lines, which 

form the acceptance criteria for measured forces in individual tendons, and the calculations of 

PLL lines are consistent with RG 1.35.1, “Determining Prestressing Forces for Inspection of 

Prestressed Concrete Containments.” The amended LRA further states that “actual measured 

values for each tendon are compared to their respective PLL values, with acceptance criteria 

consistent with ASME Section XI, Subsection IWL requirements.” 

The applicant dispositioned the TLAA for the PLL lines in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the PLL lines, developed as acceptance criteria for 

the prestress force losses in individual tendons of the concrete containment prestressing 
TIME-LIMITED AGING ANALYSES

4-96

system, will be adequately managed by the Concrete Containment Tendon Prestress Program 

for the period of extended operation.

Regression Analysis. The LRA states that the lift-off trend lines are necessary to demonstrate 

that the tendon prestressing force will remain above the MRV at least until the next scheduled 

surveillance. The LRA also states that the tendon surveillances are scheduled every 5 years. 

The trend lines are calculated by regression of individual tendon lift-off data and are, therefore, 

consistent with NRC Information Notice (IN) 99-10, Revision 1, “Degredation of Prestressing 

Tendon Systems in Prestressed Concrete Containments,” dated October 7, 1999. The 

regression analysis trend lines indicate lift offs in excess of the MRV for at least 60 years. The 

IWL Inspection Report includes the results through the 2010, 25-year surveillance.

LRA Table 4.5-1, “Vertical Tendon Regression Analysis,” and Table 4.5-2, “Horizontal Tendon 

(Cylinder and Dome) Regression Analysis,” summarize the input data (i.e., selected tendons, 

age and time stressed, lift-off force) from the 1st-year surveillance performed in 1985 to the last 

(25th-year surveillance) performed in 2010. 

LRA Figure 4.5-1, “Regression Analysis of Vertical Tendons,” and Figure 4.5-2, “Regression 

Analysis of Horizontal Tendons,” plot the table surveillance data and the resulting regression 

analyses, along with the MRV.

The LRA further states that the current analysis demonstrates that the average tendon 

prestresses in each of the vertical group and hoop tendon group will remain above their MRV 

through 60 years of operation; therefore, the analysis is valid for the period of extended 

operation. 

The applicant dispositioned the TLAA for the regression analyses in accordance with 

10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended operation.

4.5.2 Staff Evaluation

The staff reviewed FSAR-Standard Plant (SP) Section 1.2.5.1.1, “Containment Structure,” and 

confirmed that the containment structure is a prestressed, post-tensioned concrete structure 

with a cylindrical wall, a hemispherical dome, and a flat foundation slab. The wall and dome 

form a prestressed, post-tensioned system consisting of horizontal tendons in the wall and 

inverted U-shaped vertical tendons in the wall and dome. The staff also reviewed FSAR-SP 

Appendix 3.8A, “Computer Programs Used for Structural and Seismic Analyses,” 

Section 3.8A.1.2, “Bechtel CE 239 Hemispherical Dome Tendon Analysis (TENDON),” and 

confirmed that the dome hoop tendons extend from the springline into the dome region up to 

45 degrees latitude.

The staff further reviewed FSAR-SP Section 3.8.1.1.2, “Post-Tensioning System,” and 

confirmed the applicant’s statements as presented in LRA Section 4.5. In addition, the staff 

reviewed the summary presented in FSAR-SP Appendix 3A, “Conformance to NRC Regulatory 

Guides – Regulatory Guide 1.35, Revision 3, dated April 1979,” which states that inservice 

inspection of ungrouted tendons in prestressed concrete containment structures for the 

post-tensioning system follows the guidance of Bechtel Topical Report BC-TOP-5-A, Revision 3, 

“Prestressed Concrete Nuclear Reactor Containment Structures,” February 1975 

(BC-TOP-5-A), as modified by RG 1.35, Revision 3, “Inservice Inspection of Ungrouted Tendons 

in Prestressed Concrete Containments.” Details of the Tendon Surveillance Program are in 

FSAR-SP Section 16.6.1.2, “Containment Vessel Structural Integrity Limiting Condition of 
TIME-LIMITED AGING ANALYSES

4-97

Operation” which is outlined in TS 5.5.6 and further described in LRA Section B3.3, “Concrete 

Containment Tendon Prestress [Program].” 

The staff noted that the applicant’s tendon surveillance program, inspection frequencies, and 

acceptance criteria are in accordance with Section Xl, Subsection IWL of the ASME Boiler and 

Pressure Vessel (B&PV) Code and applicable addenda, as required by 10 CFR 50.55a, except 

where an exemption or relief has been authorized by the staff. Both the FSAR-SP and the 

applicant’s Concrete Containment Tendon Prestress Program discuss the PLL force lines, the 

MRV, and the regression analyses. These quantities are further reviewed and discussed in the 

appropriate sections for each of the staff’s evaluations below.

Minimum Required Value. The staff reviewed the applicant’s claim that the MRV (average 

tendon prestress force used in the concrete containment design analysis) is not a TLAA. The 

staff also reviewed BC-TOP-5-A and noted that the report provides guidance for calculating 

average stresses for each tendon group (vertical and horizontal) before any losses and, 

subsequently, to anticipated losses, such as slip at the anchorage and elastic shortening when 

seating the tendons. RG 1.35.1 provides guidance in establishing the predicted forces. The 

average initial seating force at the anchorage, therefore, is the MRV that serves as the 

acceptance criterion for the average tendon prestressing force over the entire plant life (i.e., it 

does not vary with the plant life). 

The staff finds that the applicant has demonstrated that the MRV is not a TLAA because it does 

not satisfy 10 CFR 54.3(a), Criterion (3), which states that TLAAs must involve time-limited 

assumptions defined by the current operating term.

Predicted Lower Limit. The staff reviewed LRA Section 4.5 (as amended by LRA 

Amendment 37) regarding the Predicted Lower Limit TLAA and the corresponding disposition of 

10 CFR 54.21(c)(iii), consistent with the review procedures in SRP-LR Section 4.5.3.1.3, which 

states that the reviewer verifies the applicant has identified the appropriate program in the GALL 

Report (i.e., AMP X.S1, “Concrete Containment Tendon Prestress”) and has in place a program 

consistent with the corresponding generic program in the GALL Report. 

The staff confirmed that the PLL calculated data for the TLAA, are developed from the loss of 

prestress model consistent with RG 1.35.1 and compared to measured lift-off force values as 

discussed in the applicant’s Concrete Containment Tendon Prestress program in accordance 

with Section XI, Subsection IWL of the ASME Code, using edition and addenda as required by 

10 CFR 50.55a. The staff evaluated and documented the applicant’s proposed enhancement to 

the Concrete Containment Tendon Prestress program (see Commitment No 32) in SER 

Section 3.0.3.2.23.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the PLL 

lines, developed as acceptance criteria for the prestress force losses in individual tendons of the 

concrete containment prestressing system, will be adequately managed for the period of 

extended operation. Additionally, this meets the acceptance criteria in 

SRP-LR Section 4.5.2.1.3 because the applicant has in place an AMP consistent (after 

enhancements) with GALL Report AMP X.S1 to adequately manage the development of the 

PLL lines for tendon prestress loss during the period of extended operation.

Regression Analysis. The staff reviewed LRA Section 4.5 regarding the regression 

analysis-based trend lines and the corresponding disposition of 10 CFR 54.21(c)(i), consistent 

with the review procedures in SRP-LR Section 4.5.3.1.1, which state that the trend line of the 

measured prestressing force shows that the existing analysis will cover the period of extended 
TIME-LIMITED AGING ANALYSES

4-98

operation. The staff also reviewed LRA Table 4.5-1, “Vertical Tendon Regression Analysis,” 

and LRA Table 4.5-2, “Horizontal Tendon (Cylinder and Dome) Regression Analysis,” and the 

corresponding figures, Figure 4.5-1, “Regression Analysis of Vertical Tendons,” and Figure 

4.5-2, “Regression Analysis of Horizontal Tendons,” and noted that trend lines are calculated by 

regression of individual tendon lift-off data. The staff confirmed that the reported lift-off forces in 

the LRA are as those listed in the audited Document No. CA-N1042-500, “Final Report for the 

Callaway Nuclear Plant 25th Year Containment Building Tendon Surveillance.” 

The staff then examined the LRA aforementioned figures and noted that the applicant 

considered the information provided in IN 99-10, Revision 1, Attachment 3, “Comparison and 

Trending of Prestressing Forces,” by using each sampled tendon’s lift-off force as a data point 

instead of the group averages at the scheduled surveillance intervals. The staff noted that this 

approach provides the true representation of the variability of the tendon forces (lift-off forces) 

with respect to time sought by IN 99-10, Revision 1, Attachment 3. Based on the applicant’s 

regression analysis, the lift-off forces will remain above the MRV for at least 60 years.

The staff finds the applicant has demonstrated in accordance with 10 CFR 54.21(c)(1)(i), that 

the regression analysis for the horizontal (hoop) and vertical tendon trend lines is valid for the 

period of extended operation.

4.5.3 FSAR Supplement

Minimum Required Value. The staff concludes that no FSAR supplement is required for the 

calculated MRV because the MRV is not time dependent but a constant quantity throughout the 

plant life and, hence, does not require a TLAA.

Predicted Lower Limit. LRA Section A3.4, as amended by LRA Amendment 37 dated 

June 17, 2014, provides the FSAR supplement summarizing the PLL force lines TLAA. The 

staff reviewed amended LRA Section A3.4 consistent with the review procedures in SRP-LR 

Section 4.5.3.2, which state that the reviewer verifies that the applicant has provided information 

to be included in the FSAR supplement that includes a summary description of the evaluation of

the tendon prestress TLAA.

The staff also noted that the applicant plans to enhance the Concrete Containment Tendon 

Prestress program and this TLAA through a common commitment (see Commitment No. 32), as 

discussed in SER Section 3.0.3.2.23.

Based on its review of the FSAR supplement, as amended by LRA Amendment 37 dated 

June 17, 2014, the staff finds that it meets the acceptance criteria in SRP-LR Section 4.5.2.2, 

and is therefore acceptable. Additionally, the staff determines that the applicant provided an 

adequate summary description of its actions to address PLL force lines, as required by 

10 CFR 54.21(d).

Regression Analysis. LRA Section A3.4 Concrete Containment Tendon Prestress provides the 

FSAR supplement summarizing the regression analysis trend lines TLAA. The staff reviewed 

LRA Section A3.4 consistent with the review procedures in SRP-LR Section 4.5.3.2 which state 

that the reviewer verifies that the applicant has provided information to be included in the FSAR 

supplement that includes a summary description of the evaluation of tendon prestress TLAA.

Based on its review of the FSAR supplement, the staff finds that it meets the acceptance criteria 

in SRP-LR Section 4.5.2.2 and is, therefore, acceptable. Additionally, the staff determines that 
TIME-LIMITED AGING ANALYSES

4-99

the applicant provided an adequate summary description of its actions to address the tendon 

prestress regression analysis trend lines, as required by 10 CFR 54.21(d).

4.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated that the MRV 

is not a TLAA because it does not satisfy 10 CFR 54.3(a)(3). The staff concludes that the 

applicant has provided an acceptable demonstration, in accordance with 10 CFR 54.21(c)(1)(i), 

that the trend lines based on regression analysis for the horizontal and vertical tendon groups 

remain valid for the period of extended operation. The staff also concludes that the applicant 

has provided an acceptable demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the 

PLL force lines will be adequately managed by the Concrete Containment Tendon Prestress 

Program for the period of extended operation. The staff also concludes that the FSAR 

supplement contains an appropriate summary description of the TLAA evaluations, as required

by 10 CFR 54.21(d).

4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analyses

LRA Section 4.6 describes the applicant’s TLAA of the containment structure liner plate, 

containment access hatches, and leak chase channels. The LRA states that the Callaway 

prestressed concrete containment vessel is designed to Bechtel Topical Report BC TOP-5-A, 

Revision 3. The LRA states that the containment is poured against a steel membrane liner 

designed to BC-TOP-1 Revision 1. The LRA states that the Callaway containment liner and 

other metal containment (MC) components (e.g., containment penetrations) were “designed to 

stress limit criteria of BC-TOP-1 Revision 1, independent of the number of load cycles, and 

require no fatigue analyses, with the exception of the main steam and feedwater penetrations, 

the containment access hatches, and the leak chases.” The staff’s evaluation of the applicant’s 

claim that Callaway’s metal containment liner requires no fatigue analysis is documented in 

SER Section 4.1.2.1.2. The staff’s evaluation of the applicant’s fatigue analyses for the main

steam and feedwater penetrations, the containment access hatches, and the leak chases is 

documented is SER Section 4.6.1 and 4.6.2 below.

4.6.1 Design Cycles for the Main Steam Line and Feedwater Penetrations

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 states that BC-TOP-1 accounts for cyclical loads in the design of the main 

steam penetrations. The LRA states that “[t]hese cyclic loads include: 10 steady state 

operating thermal gradient plus steam pipe rupture cyclic loads (BC-TOP-1, Part II, “Loading 

Condition IV”) and 100 lifetime steady state operating thermal gradient plus normal operating 

cyclic loads; i.e., Startup-Shutdown (BC-TOP-1, Part II, “Loading Condition V”).”

The LRA states that the analyses in BC-TOP-1 do not qualify the components on a generic 

basis, but represent an acceptable method in which to demonstrate the components will meet 

the requirements of BC-TOP-5-A, Appendix C; however, the analyses must be performed, or at 

least confirmed to be conservative, on a plant-specific basis. The LRA also states that the 

specific analyses were performed for the main steam line penetrations and the feedwater 

penetrations at Callaway. The LRA further states that the analysis uses the simplified approach 

set in ASME Code Subparagraph NB-3228.3 of Section III, and it is only required if the 

penetration fails to meet the 3SM requirement of Subparagraph NB-3222.2. 
TIME-LIMITED AGING ANALYSES

4-100

BC-TOP-1 Loading Condition IV – Normal Plus Pipe Rupture – 10 Cycles. For “loading 

condition IV” (normal plus pipe rupture), the LRA states that a main steam line or feedwater 

rupture is only anticipated to occur once during the design lifetime. However, the original 

calculation used 10 occurrences; therefore, the one anticipated occurrence is bounded by the 

design calculation, and the evaluation remains valid for the period of extended operation. 

The applicant dispositioned the TLAA for loading condition IV of the main steam and feedwater 

lines, in accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of 

extended operation.

BC-TOP-1 Loading Condition V – Normal Penetration Thermal Gradient Plus Startup-Shutdown 

– 100 Cycles. For “loading condition V,” (normal thermal gradient plus operating cycle), the 

LRA states that stress intensity of the feedwater penetrations do not exceed the 3SM

requirement of NB-3222.2, therefore the cyclic loading aging effect does not need to be 

analyzed and the analysis is not a TLAA.

For “loading condition V,” the LRA states that the allowable stress is based on 100 

startup-shutdown cycles for an assumed plant design life of 40 years, however, a review of the 

ASME Code Section III Table I-9-1 shows that the allowable stress for 500 cycles envelopes the 

calculated stress. The LRA also states that 500 cycles exceeds the number of cycles projected 

for 60 years; therefore, the calculation has been projected through the period of extended 

operation. The applicant dispositioned the analysis for the main steam line penetrations, in 

accordance with 10 CFR 54.21(c)(1)(ii), that the analysis has been projected to the end of the 

period of extended operation.

4.6.1.2 Staff Evaluation

BC-TOP-1 Loading Condition IV – Normal Plus Pipe Rupture – 10 Cycles. The staff reviewed 

the applicant’s TLAA associated with “loading condition IV” for the main steam line and 

feedwater containment penetrations to verify, in accordance with 10 CFR 54.21(c)(1)(i), that the 

analysis remains valid for the period of extended operation. 

The staff reviewed the applicant’s TLAAs associated with “loading condition IV” for the main 

steam line and feedwater containment penetrations and the corresponding disposition 

consistent with the review procedures in SRP-LR Section 4.6.3.1.1.1. These procedures state 

that the reviewer should verify that the number of assumed transients used in the existing CUF 

calculations for the current operating term is compared to the extrapolation to 60 years of 

operation of the number of operating transients experienced to date and that the comparison 

confirms that the number of transients in the existing analyses will not be exceeded during the 

period of extended operation.

The staff reviewed BC-TOP-1 Section 5.3.4, “Loading Condition IV,” and noted that the original 

calculation assumed 10 cycles for this loading condition. The staff confirmed that LRA Table 

4.3-2, “Transient Accumulations and Projections,” replicates the information provided in 

FSAR-SP Table 3.9(N)-1, “Summary of Reactor Coolant System Analyzed Design Transients,” 

which states that the reactor trip from full power, with cooldown, with safety injection is expected 

to be, at most, a single event during the design plant lifetime. Therefore, the calculation based 

on 10 cycles remains valid for the period of extended operation. 

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analysis for “loading condition IV” for the main steam line and feedwater containment 

penetrations remains valid for the period of extended operation. Additionally, the analysis 
TIME-LIMITED AGING ANALYSES

4-101

meets the acceptance criteria in SRP-LR Section 4.6.2.1.1.1 because the number of assumed 

cyclic loads will not be exceeded during the period of extended operation.

BC-TOP-1 Loading Condition V – Normal Penetration Thermal Gradient Plus Startup-Shutdown 

– 100 Cycles. The staff reviewed the applicant’s TLAA associated with the analysis of “loading 

condition V” for the feedwater containment penetrations to verify that the analysis is not a TLAA. 

The staff audited the applicant’s TLAA basis document and noted that Callaway performed a 

plant-specific evaluation for the feedwater penetrations as an addendum to the BC-TOP-1 

calculations. According to the calculations referenced in the basis document, the stress for the 

feedwater penetrations does not exceed the allowable primary and secondary stress intensity 

3SM requirement of NB-3222.2 for “loading condition V.” The analyses in the CLB for “loading 

condition V,” for the feedwater containment penetrations does not include any cyclic loading 

aging effects. Therefore, the staff concludes that the calculation for feedwater penetrations 

does not meet the definition of a TLAA, in accordance with 10 CFR 54.3(a)(2).

The staff reviewed the applicant’s TLAA associated with the analysis of “loading condition V” for 

the main steam line containment penetration to verify, in accordance with 

10 CFR 54.21(c)(1)(ii), that the analysis has been projected to the end of the period of extended 

operation. 

The staff reviewed this TLAA consistent with the review procedures in SRP-LR 

Section 4.6.3.1.1.2, which state that the reviewer should review operating transient experience 

and a list of the increased number of assumed cyclic loads projected to the end of the period of 

extended operation to ensure that the cyclic load projection is adequate. 

The staff reviewed BC-TOP-1 and noted that loading condition V includes the normal thermal 

gradient plus an operating cycle, which is equivalent to a startup-shutdown cycle. The original 

allowable stress was based on 100 startup-shutdown cycles. The staff reviewed LRA Table 

4.3-2, “Transient Accumulations and Projections,” and noted that 65 startups and shutdowns are 

expected for 60 years. The projected value of 65 cycles is below the 100 cycles associated with 

an allowable stress greater than the actual calculated stress; therefore, the calculation has been 

projected to the end of the period of extended operation. 

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(ii), that 

the analysis for “loading condition V” for the main steam line containment penetration has been 

projected to the end of the period of extended operation. Additionally, the analysis meets the 

acceptance criteria in SRP-LR Section 4.6.2.1.1.2 because calculations were re-evaluated 

based on an increased number of assumed cyclic loads to cover the period of extended 

operation.

4.6.1.3 FSAR Supplement

LRA Section A3.5.1 provides the FSAR supplement summarizing the main steam line and 

feedwater penetrations TLAAs. The staff reviewed LRA Section A3.5.1 consistent with the 

review procedures in SRP-LR Section 4.6.3.2.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is, therefore, acceptable. Additionally, the staff determines that 

the applicant provided an adequate summary description of its actions to address main steam 

line and feedwater penetrations TLAAs, as required by 10 CFR 54.21(d).
TIME-LIMITED AGING ANALYSES

4-102

4.6.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the analysis for “loading condition 

IV” for the main steam line and the feedwater penetrations remains valid for the period of 

extended operation. The staff also concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(ii), that the analysis for “loading 

condition V” for the main steam line has been projected to the end of the period of extended 

operation. The staff also concludes that the FSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.6.2 Fatigue Waiver Evaluations for the Access Hatches and Leak Chase Channels

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6.2 describes the applicant’s TLAA for the fatigue waivers associated with the 

containment access hatches and the leak chase channels. 

Access Hatches. The LRA states that a fatigue waiver evaluation for the access hatches was 

completed in accordance with ASME Code Section III, Subsection NE-3222.4(d).

The LRA states that two of the six criteria in the access hatch evaluation include 

time-dependent assumptions, as follows:

• the evaluation assumes 1,920 pressure fluctuations from atmospheric to design 

pressure and back to atmospheric pressure during normal operation to satisfy fatigue 

waiver criterion 1

• the evaluation assumes 160 temperature fluctuations between 10 °C (50 °F) and 49 °C 

(120 °F) during startup and shutdown to satisfy fatigue waiver criterion 3

The LRA also states that containment pressure will only fluctuate between atmospheric and 

design pressure during integrated leak rate tests (ILRT) conducted every 10 years and will only 

experience the temperature fluctuations during startups and shutdowns. The LRA states that 

the number of cycles assumed will not be exceeded during the period of extended operation; 

therefore, the applicant dispositioned the TLAA for the access hatch, in accordance with 

10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of extended operation.

Leak Chase Channels. The LRA states that a fatigue waiver evaluation was completed in 

accordance with ASME Code Section III, Subsection NE-3222.4(d).

Two of the six criteria of the ASME Code Section III, Subsection NE-3222.4(d), in the leak 

chase evaluation include time-dependent assumptions, as follows:

• the evaluation assumes 40 Type A ILRT design pressure tests to satisfy fatigue waiver 

criteria 1 and 2

• the evaluation assumes 1,265 thermal transients, which considers all design basis 

transients over 40 years, as identified in FSAR-SP Table 3.9(N)-1A, to satisfy fatigue 

waiver criterion 3

The LRA further states that the Type A ILRT is only conducted every 10 years, and the only 

thermal transients that affect the containment components are heatup and cooldowns, which 
TIME-LIMITED AGING ANALYSES

4-103

have a design number of 200 cycles. The projected values will not exceed the assumed values 

during the period of extended operation; therefore, the applicant dispositioned the TLAA for the 

leak chases, in accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the 

period of extended operation.

4.6.2.2 Staff Evaluation

Access Hatches. The staff reviewed the applicant’s TLAA for the containment access hatch 

fatigue waiver and the corresponding disposition of 10 CFR 54.21(c)(1)(i) consistent with the 

review procedures in SRP-LR 4.6.3.1.1.1. These procedures state that the number of assumed 

transients used in the existing calculations for the current operating term and the extrapolation 

to 60 years of operation of the number of operating transients experienced to date are reviewed 

to confirm that the number of transients in the existing analyses will not be exceeded during the 

period of extended operation.

The staff noted that, for Criterion 1 of ASME Code Section III, Subsection NE-3222.4(d), the 

applicant’s evaluation assumes 1,920 pressure fluctuations from atmospheric to design 

pressure and back to atmospheric. This cycle would only occur during accident conditions or 

during ILRTs, which are conducted, on average, every 10 years. This results in much fewer 

cycles over 60 years than assumed in the original fatigue waiver calculation. The staff further 

noted that, to satisfy fatigue waiver criterion 3, the applicant’s evaluation assumes 160 

temperature fluctuations between 10 °C (50 ° F) and 49 °C (120 °F). There are several other 

transients that may lead to a significant temperature fluctuation in the containment (e.g., reactor 

trip, RCS depressurization, loss of power). As described in SER Section 4.3.1.2.2 on the 

applicant’s response to RAI 4.3-5 by letter dated October 11, 2012, the applicant explained that 

if any of these transients lead to a cooldown, the cooldown would be counted independently, as 

would the subsequent heatup. The staff found the applicant’s response acceptable and its 

evaluation of this concern associated with RAI 4.3-5 is provided in SER Section 4.3.1.2.2. 

Therefore, the cooldown-heatup transient is an acceptable measure of the temperature cycles in 

containment. The staff reviewed LRA Table 4.3-2, “Transient Accumulations and Projections,”

and noted that 65 startups (heatups) and shutdowns (cooldowns) are expected for 60 years. 

The projected value of 65 cycles is well below the 160 cycles assumed in the original 

calculation. Since the values assumed in the original fatigue waiver analysis bound the 

expected values for the period of extended operation, the analysis remains valid for the period 

of extended operation. 

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analysis for the containment access hatch fatigue waiver remains valid for the period of 

extended operation. Additionally, the analysis meets the acceptance criteria in SRP 4.6.2.1.1.1 

because the containment access hatch fatigue waiver number of assumed cyclic loads will not 

be exceeded during the period of extended operation.

Leak Chase Channels. The staff reviewed the applicant’s TLAA for the for the leak chase 

channel fatigue waiver and the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent 

with the review procedures in SRP-LR 4.6.3.1.1.1. These procedures state that the number of 

assumed transients used in the existing calculations for the current operating term and the 

extrapolation to 60 years of operation of the number of operating transients experienced to date 

are reviewed to confirm that the number of transients in the existing analyses will not be 

exceeded during the period of extended operation.

The staff noted that for fatigue waiver criteria 1 and 2, the applicant’s evaluation assumes 

40 pressure fluctuations associated with Type A ILRTs (i.e., pressure fluctuations from 
TIME-LIMITED AGING ANALYSES

4-104

atmospheric to design). As noted above, this testing only occurs, on average, every 10 years, 

which results in fewer cycles over 60 years than the 40 assumed in the original fatigue waiver 

calculation. The staff also noted that for fatigue waiver criterion 3, the applicant’s evaluation 

assumes 1,265 thermal transients. As stated above, the only transients that will cause a 

significant thermal transient on containment components are the heatups and cooldowns, 

which, as noted in LRA Table 4.3-2, are projected to be 65 occurrences over 60 years. Since 

the values assumed in the original fatigue waiver analysis bound the expected values for the 

period of extended operation, the analysis remains valid for the period of extended operation. 

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analysis for the leak chase channel fatigue waiver remains valid for the period of extended 

operation. Additionally, the analysis meets the acceptance criteria in SRP 4.6.2.1.1.1 because 

the leak chase channel fatigue waiver number of assumed cyclic loads will not be exceeded 

during the period of extended operation.

4.6.2.3 FSAR Supplement

LRA Section A3.5.2 provides the FSAR supplement summarizing the access hatches and leak 

chase channels fatigue waiver TLAAs. The staff reviewed LRA Section A3.5.2 consistent with 

the review procedures in SRP-LR Section 4.6.3.2, which states that the reviewer verifies that 

the applicant has provided information to be included in the FSAR supplement that includes a 

summary description of the evaluation of the penetrations fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2 and is, therefore, acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the access 

hatches and leak chase channels fatigue waiver TLAAs, as required by 10 CFR 54.21(d).

4.6.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the analyses for the containment 

access hatches and the containment leak chase channels fatigue waiver TLAAs remain valid for 

the period of extended operation. The staff also concludes that the FSAR supplement contains 

an appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7 Other Plant-Specific Time-Limited Aging Analyses

4.7.1 Containment Polar Crane, Fuel Building Cask Handling Crane, Spent Fuel Pool 

Bridge Crane, and Refueling Machine CMAA 70 Load Cycle Limits

4.7.1.1 Summary of Technical Information in the Application

LRA Section 4.7.1 describes the applicant’s TLAA for the containment polar crane, fuel building 

cask handling crane, spent fuel pool bridge crane, and refueling machine Crane Manufacturers 

Association of America (CMAA) 70 load cycle limits. The LRA states that the CMAA 70 crane 

service classification for each machine depends, in part, on the assumption that the number of 

stress cycles at or near the maximum allowable stress will not exceed the number assumed for 

that design class. The LRA further states that in operation, this means the number of lifts that 

approach or equal the design load (significant lifts) will not exceed the number of stress cycles 

assumed for that design class. Therefore, the applicant concluded that the design of cranes for 

these standard numbers of lifts for the plant lifetime is a TLAA.
TIME-LIMITED AGING ANALYSES

4-105

Design Lifts of Heavy-Lift Cranes. The LRA states that the cask handling crane is a CMAA 70, 

Class A crane designed for 100,000 full-capacity lifts in a design lifetime. The LRA also states 

that, to date, this crane has raised no significant number of heavy lifts, not yet shipped spent 

fuel, nor moved any spent fuel to onsite storage outside the spent fuel pool. The applicant 

assumed fuel used during the 80 postulated refueling operations is transferred to dry storage 

before the end of the period of extended operation, moving approximately 200 casks (80 

refuelings times 90 assemblies per refueling, plus 193 initial core load, divided by 37 assemblies 

per cask), resulting in about 400 lifts over its service life, which will not exceed the 100,000 

cycles specified for CMAA 70, Class A service.

The LRA states that the polar crane is a CMAA 70, Class C crane designed for 500,000 

full-capacity lifts in a design lifetime. The LRA states that the polar crane trolley is rated at 260 

tons; a second temporary trolley, rated at 220 tons, was installed to permit heavier lifts during 

construction; and the bridge is rated for 440 tons. The LRA states that the number of polar 

crane dual trolley capacity construction lifts is estimated to be 14, with about 70 additional lifts at 

the single trolley capacity, including replacement steam generator lifts. The LRA also states 

that the polar crane specification anticipated 16 rated lifts per year, which would be 960 rated 

lifts for a 60-year design life. The polar crane, however, is used only for removal and 

reinstallation of the vessel head, upper internals, and lower internals, which will result in 480 lifts 

over a 60-year life. The LRA further states that, even if the specified number is used, the polar 

crane will only experience 1,044 lifts over its service life (14 dual trolley construction lifts plus 70 

single trolley construction lifts plus 960 specified lifts) and, therefore, given the frequency of 

polar crane operation, it will not exceed the 500,000 cycles specified for CMAA 70, Class C 

Service.

Design Lifts of the Spent Fuel Pool Bridge and Refueling Machine. The LRA states that the 

spent fuel pool bridge crane is CMAA 70, Class B, and therefore, rated for up to 100,000 lifetime 

lifts. The LRA states that the spent fuel bridge crane is used to lift the fuel storage pool transfer 

gates to and from the storage racks and to move new and spent fuel assemblies. The LRA also 

states that the spent fuel pool bridge crane is conservatively expected to perform about 736 lifts 

per fuel cycle, consisting of:

• offload – 193 lifts per fuel cycle

• reload – 193 lifts per fuel cycle

• new fuel receipt – 90 lifts per fuel cycle

• cleaning – 100 lifts per fuel cycle

• fuel reshuffle – 160 lifts per fuel cycle

However, once Callaway commences dry cask storage, additional lifts will be necessary. The 

LRA states that the number of lifts is estimated to be the total number of new fuel assemblies 

received over 80 assumed refueling, plus 193 lifts for initial core loading. The LRA also states 

that moving the fuel storage gate adds about 160 lifetime lifts for the spent fuel bridge crane (2 

lifts per refueling). Therefore, the total expected lifetime lifts for the spent fuel pool bridge crane 

is (736 times 80 refuelings) plus (90 times 80 plus 193) plus 160, which equals 66,433 lifts.

The LRA states that the refueling machine, used to load, unload, and move fuel assemblies 

within the reactor core and to transfer fuel to and from the fuel transfer tube only requires about 

two refueling machine lifts per fuel assembly. There LRA states that there are 193 assemblies 

in a full core, or roughly 400 lifts for the refueling machine in a normal refueling outage and 

Callaway is designed for 80 refuels, for about 32,000 fuel handling lifts.
TIME-LIMITED AGING ANALYSES

4-106

The LRA also stated the spent fuel pool bridge and refueling machines will experience only a 

fraction of their rated lifetime number of lifts; therefore, the spent fuel bridge and refueling 

machines will not exceed the 100,000 cycles specified.

The applicant dispositioned the TLAAs for the containment polar crane, fuel building cask 

handling crane, spent fuel pool bridge crane, and refueling machine CMAA 70 load cycle limits, 

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 and the TLAAs for the containment polar crane, fuel 

building cask handling crane, spent fuel pool bridge crane, and refueling machine to verify, in 

accordance with 10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended 

operation. The staff reviewed these TLAAs consistent with the review procedures in SRP-LR 

Section 4.7.3.1.1, which state that the existing analyses should be shown to be bounding, even 

during the period of extended operation. 

The staff also reviewed the LRA referenced FSAR-SP Section 9.1.4, “Fuel Handling System,” 

and noted that it is composed of cranes, equipment, special fuel handling devices, and a fuel 

transfer system that are designed to meet the seismic and safety requirements of the plant. The 

staff noted that the section discusses the classification and function of (1) the cask handling 

crane (CMAA 70, Class A), (2) the spent fuel bridge crane (CMAA 70, Class B), (3) the 

containment building polar crane (CMAA 70, Class C), and (4) the refueling machine, which are 

further reviewed below.

Design Lifts of Heavy-Lift Cranes. The staff reviewed LRA Section 4.7.1 and Section 9.1.4, 

“Fuel Handling System,” of the Callaway FSAR-SP and confirmed that the fuel building cask 

handling crane is used to handle spent fuel shipping casks between trucks, the loading pool, 

and the washdown pit. LRA Table 4.7-1 shows that the estimated number of lifts for 60 years of 

operation will not exceed the maximum number of lifts for which the fuel building cask handling 

crane was designed. Considering the applicant’s assumption that all fuel used during the 

80 postulated refueling operation is transferred to dry storage before the end of the period of 

extended operation, the estimated maximum number of significant crane lifts for the fuel building 

cask handling crane is 400 lifts. The staff finds that this estimated number of lift cycles is 

significantly less than the 100,000 permissible cycles for a CMAA 70 Class A crane and, 

therefore, is acceptable.

The staff reviewed LRA Section 4.7.1 and FSAR-SP Section 9.1.4, “Fuel Handling System,” and 

confirmed that the containment building polar crane is used, in conjunction with various lifting 

rigs, to remove the reactor vessel head, the reactor vessel upper internals, and the lower 

internals, and for routine maintenance and inservice inspection. LRA Table 4.7-1 shows that 

the estimated number of lifts for 60 years of operation will not exceed the maximum number of 

lifts for which the polar crane was designed. The estimated number of dual trolley capacity 

construction lifts is estimated to be 14, with about 70 additional lifts at the single trolley capacity, 

for a total of 84 lifts. The crane specification anticipated 16 rated lifts per year, which for a 

60-year design life, would be 960 lifts. The estimated maximum number of significant crane lifts 

for the containment building polar crane is 1,044 lifts. The staff finds that this estimated number 

of lift cycles is significantly less than the 500,000 permissible cycles for a CMAA 70 Class C 

crane and, therefore, is acceptable.
TIME-LIMITED AGING ANALYSES

4-107

Design Lifts of the Spent Fuel Pool Bridge and Refueling Machine. The staff reviewed LRA 

Section 4.7.1 and FSAR-SP Section 9.1.4, “Fuel Handling System,” and confirmed that the 

spent fuel pool bridge crane is used to transport new and spent fuel to and from various 

locations inside the fuel building. LRA Table 4.7-1 shows that the estimated number of lifts for 

60 years of operation will not exceed the maximum number of lifts for which the spent fuel 

bridge crane was designed. Based on refueling operations, the spent fuel bridge crane is 

expected to perform about 736 lifts per fuel cycle, 90 lifts per fuel cycle once dry cask storage 

has commenced,193 initial core loading lifts, and 160 lifts moving the storage pool gate, for an 

estimated 66,433 significant crane lifts. The staff finds that this estimated number of lift cycles 

is less than the 100,000 permissible cycles for a CMAA 70 Class B crane and, therefore, is 

acceptable.

The staff reviewed LRA Section 4.7.1 and FSAR-SP Section 9.1.4, “Fuel Handling System,” and 

confirmed that the refueling machine is used to load, unload, and move fuel assemblies within 

the reactor core and to transfer fuel to and from the fuel transfer tube. LRA Table 4.7-1 shows 

that the estimated number of lifts for 60 years of operation will not exceed the maximum number 

of lifts for which the refueling machine was designed. Considering there are 193 assemblies in 

the core, roughly 400 lifts are estimated each refueling outage. Assuming 80 refuel cycles of 

the 60 years of operation, the estimated maximum significant crane lifts for the refueling 

machine is 32,000 lifts. The staff finds that this estimated number of lift cycles is less than the 

100,000 permissible cycles for CMAA 70 and, therefore, is acceptable.

The staff finds that the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), 

that the analyses for the containment polar crane, fuel building cask handling crane, spent fuel 

pool bridge crane, and refueling machine CMAA 70 load cycle limits remain valid for the period 

of extended operation. Additionally, the applicant meets the acceptance criteria in SRP-LR 

Section 4.7.2.1 because the applicant has demonstrated that the analyses for the containment 

polar crane, fuel building cask handling crane, spent fuel pool bridge crane, and refueling 

machine CMAA load cycle limits remain valid for the period of extended operation, in 

accordance with 10 CFR 54.21(c)(i).

4.7.1.3 FSAR Supplement

LRA Section A3.6.1 provides the FSAR supplement summarizing the containment polar crane, 

fuel building cask handling crane, spent fuel pool bridge crane, and refueling machine CMAA 70 

load cycle limits. The staff reviewed LRA Section A3.6.1 consistent with the review procedures 

in SRP-LR Section 4.7.3.2, which states that the applicant has provided information to be 

included in the FSAR supplement that includes a summary description of the evaluation of each 

TLAA. SRP-LR Section 4.7.3.2 also states that each summary description is reviewed to verify 

that it is appropriate, such that later changes can be controlled by 10 CFR 50.59, “Changes, 

Tests and Experiments,” and that the description should contain information that the TLAAs 

have been dispositioned for the period of extended operation.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2 and is, therefore, acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address CMAA 70 load 

cycle limits, as required by 10 CFR 54.21(d).

4.7.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the analyses for the containment 
TIME-LIMITED AGING ANALYSES

4-108

polar crane, fuel building cask handling crane, spent fuel pool bridge crane, and refueling 

machine CMAA 70 load cycle limits remain valid for the period of extended operation. The staff 

also concludes that the FSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.2 Inservice Flaw Analyses that Demonstrate Structural Integrity for 40 Years

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2 describes the TLAA for inservice flaw analyses. The LRA states that 

inservice flaw growth is identified in the SRP-LR as a potential TLAA and flaws of such size that 

they cannot be dispositioned through comparison with the ASME Code tables must be 

analyzed. The LRA states that these analyses depend on a specified number of operating 

events or years and, therefore, may be TLAAs. The applicant identified three flaw evaluations

as discussed here. 

Cold Leg Elbow-to-Safe End Weld Flaw Indications. The fatigue crack growth analysis for the 

cold leg elbow-to-safe end weld flaw indications assumes the design number of transients. The 

projected transient accumulations show that the numbers of transient cycles are expected to 

remain within the assumed numbers and, therefore, the analyses are valid through the period of 

extended operation. The TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(i). 

Canopy Seal Weld Overlay. The fracture mechanics crack growth analysis for the CRDM 

canopy seal weld overlay repairs indicates that the design is adequate for 57 years of operation. 

Since the repairs were performed in 1992, the repairs are valid through the period of extended 

operation, until 2049. The TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(i). 

Pressurizer SWOL Fatigue Crack Growth Analysis. The pressurizer nozzle structural weld 

overlays (SWOL), performed in 2007, depend on 40-year fatigue crack growth analyses, which 

will remain valid until 2047. The projected transient accumulations are expected to remain 

within the assumed numbers and, therefore, the analyses are valid through the period of 

extended operation. The TLAAs are dispositioned in accordance with 10 CFR 54.21(c)(1)(i). 

4.7.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAAs for inservice flaw growth analyses and the 

corresponding dispositions of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in 

SRP-LR Section 4.3.3.1.5.1. These procedures state that the operating cyclic experiences and 

a list of the assumed cycles used in the existing analysis are reviewed to ensure that the 

number of assumed cycles would not be exceeded during the period of extended operation.

Cold Leg Elbow-to-Safe End Weld Flaw Indications. LRA Section 4.7.2 states that for the cold 

leg elbow-to-safe end weld flaw indications, a fatigue crack growth analysis was performed. 

The LRA also states that the elbow is statically cast stainless steel (SA-351, CF8A) and the 

GTAWs are subject to thermal aging, but the effects are considered negligible. The applicant 

concluded that the fracture mechanics analysis did not consider aging effects and is not a 

TLAA, in accordance with 10 CFR 54.3(a), Criterion 2. The staff noted that the applicant did not 

justify why the GTAWs are not subject to thermal aging but the effect is considered negligible. 

The staff also noted that the applicant did not indicate whether the statically cast stainless steel 

elbow is susceptible to thermal aging and why such a fracture mechanics analysis of the elbow 

would not be a TLAA in accordance with 10 CFR 54.3.
TIME-LIMITED AGING ANALYSES

4-109

By letter dated August 6, 2012, the staff issued RAI 4.7.2-2 requesting that the applicant justify 

why the effect of thermal aging on the GTAWs is considered negligible and justify why the 

fracture mechanics analysis did not consider the elbow material, which may also be susceptible 

to thermal aging.

In its response to RAI 4.7.2-2 dated September 6, 2012, the applicant stated that because of the 

high fracture toughness properties for GTAWs and per ASME Code Section XI, Appendix C, 

Paragraph C-4210, GTAWs only need to consider the plastic collapse failure mode. The 

applicant also stated that plastic collapse is prevented by satisfying the IWB-3640 requirements 

that include a fatigue crack growth analysis. The RAI response also stated that the potential 

changes in the fracture toughness properties caused by thermal aging would not affect the 

result fatigue crack growth analysis. Therefore, the applicant concluded that thermal aging can 

be neglected for GTAWs because thermal aging will not affect the analysis results for the 

dominant failure mode. The staff noted that NUREG/CR-6428, “Effects of Thermal Aging on 

Fracture Toughness and Charpy-Impact Strength of Stainless Steel Pipe Welds,” May 1996, 

states that GTAWs exhibit higher fracture resistance than other types of welds. Therefore, the 

staff finds it reasonable that the effect of thermal aging on GTAWs is considered negligible.

The applicant also stated that the elbow is CASS but is not susceptible to thermal aging, as 

described in LRA Section 3.1.2.2.6.2, because the molybdenum (less than 0.5 percent) and 

ferrite (less than 20 percent) content of these fittings and piping pieces are below the industry 

accepted thermal aging significance threshold. The staff also noted that the staff’s 

recommendations for component susceptibility to thermal aging are provided in the GALL 

Report AMP XI.M12, which states that the susceptibility to thermal aging embrittlement of CASS 

materials is determined in terms of casting method, molybdenum content, and ferrite content. 

The staff noted that in its response to RAI 3.1.1.50-1, dated September 20, 2012, the applicant 

provided details justifying that its CASS components in the RCS are not susceptible to thermal 

aging embrittlement. The staff determined that the reactor coolant piping is not subjected to 

thermal aging. The staff’s review of the applicant’s response to RAI 3.1.1.50-1 is documented in 

SER Section 3.1.2.1.1.

The staff finds the applicant’s response to RAI 4.7.2-2 acceptable because the applicant 

provided sufficient justification, as described above, that the GTAW and the elbows of the cold 

leg elbow-to-safe end weld are not susceptible to thermal aging and, therefore, the fracture 

mechanic analyses are not TLAAs, in accordance with 10 CFR 54.3. The staff concern in RAI 

4.7.2-2 is resolved.

The LRA also indicates that the design numbers of transients assumed to occur over the plant 

life are consistent with those of FSAR Table 3.9(N)-1SP. However, LRA Section 4.7.2 did not 

specifically identify the transients that were used in the fatigue crack growth analysis and the 

staff cannot verify the adequacy of the disposition of the fatigue crack growth TLAA, in 

accordance with 10 CFR 54.21 (c)(1)(i). By letter dated August 6, 2012, the staff issued 

RAI 4.7.2-1 requesting the applicant identify all the transients and associated number of cycles 

that were used in the fatigue crack growth analysis of the cold leg elbow-to-safe end weld flaw 

indications.

In its response to RAI 4.7.2-1 dated September 6, 2012, the applicant provided a list of all the 

transients and associated number of cycles used in the fatigue crack growth analysis of the cold 

leg elbow-to-safe end weld flaw indications. The staff confirmed that those transients are 

included in LRA Table 4.3-2 and confirmed that the numbers of cycles analyzed in the fatigue 

crack growth analysis bound the number of cycles projected in LRA Table 4.3-2 for the 
TIME-LIMITED AGING ANALYSES

4-110

applicant’s plant through 60 years of operation. The staff’s evaluation of the applicant’s 

projection methodology for transient cycles is documented in SER Section 4.3.1.2. The staff 

noted that the 60-year projections listed in LRA Table 4.3-2 are less than the analyzed cycle 

limit with margin to account unanticipated occurrence of plant transients through the period of 

extended operation.

The staff finds the applicant’s response to RAI 4.7.2-1 acceptable because the applicant 

confirmed that the transients used as inputs to the fatigue crack growth analysis were listed in 

LRA 4.3-2, and the 60-year projected cycles in LRA Table 4.3-2 are bounded by the numbers of 

cycles analyzed in fatigue crack growth analysis. The staff’s concern described in RAI 4.7.2-1 is 

resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fatigue crack growth analysis for the cold leg elbow-to-safe end weld indications remains 

valid for the period of extended operation. Additionally, it meets the acceptance criteria in 

SRP-LR Section 4.3.2.1.5.1 because the cycle limits assumed in the fatigue crack growth 

analysis will not be exceeded during the period of extended operation based on the 60-year 

projected cycles and there is margin in the 40-year cycle limits to account for unanticipated 

occurrence of plant transients during the period of extended operation.

Canopy Seal Weld Overlay. For the canopy seal weld overlay, the applicant stated that the 

remaining life of the 1992 repair was determined with a fracture mechanics crack growth 

analysis that accounts for the stress corrosion cracking (SCC) resistance of the repair. The 

results of the SCC crack growth law are a function of time (e.g., years) and not based on 

monitored plant events (e.g., plant heatups). The staff noted that the fracture mechanics crack 

growth analysis for the canopy seal weld overlay repairs was assumed for 57 years of 

operation. In addition, since the repairs were performed in 1992, based on the analysis, the 

repairs are valid until 2049. The staff noted that the period of extended operation will be 

through October 2044 and the analysis remains valid during the period of extended operation.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fracture mechanics crack growth analysis for the canopy seal weld overlay remains valid for 

the period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.5.1 because the 57-year time limit established by the existing fracture 

mechanics crack growth analysis extends beyond the period of extended operation.

Pressurizer SWOL Fatigue Crack Growth Analysis. For the pressurizer SWOL, LRA 

Section 4.7.2 states that a fatigue crack growth evaluation was performed to support the relief 

request to perform preemptive SWOL on the pressurizer spray, relief, and safety nozzles.

The LRA states that the 40-year design numbers of transients were used in the fatigue crack 

growth analysis. However, LRA Section 4.7.2 did not specifically identify the transients that 

were used in this analysis and the staff cannot verify the adequacy of the disposition of the 

TLAA in accordance with 10 CFR 54.21 (c)(1)(i). By letter dated August 6, 2012, the staff 

issued RAI 4.7.2-3 requesting the applicant identify all the transients and associated number of 

cycles that were used in this fatigue crack growth analysis. The staff also requested the 

applicant to:

[i]dentify the baseline number of occurrences for each transient from 2007 to 

January 2011. In addition, provide and justify the projected occurrences for each 

transient from January 2011 to 2043 to support the TLAAs disposition, in 

accordance with 10 CFR 54.21 (c)(1 )(i). Alternatively, justify that the number of 
TIME-LIMITED AGING ANALYSES

4-111

occurrences between 1983 to January 2011 is a conservative representation of 

the number of occurrences between 2007 to January 2011.

In its response letter dated September 6, 2012, the applicant listed in Table 1, “Transients Used 

in the Fatigue Crack Growth Analyses,” of Enclosure 1, all transients and associated number of 

cycles used in the fatigue crack growth analysis of the pressurizer SWOL. The applicant also 

stated that all the transients in Table 1, Enclosure 1, are included in LRA Table 4.3-2. The 

applicant further stated that Table 1, Enclosure 1, “provides the baseline and projected numbers 

for all transients included in the fatigue crack growth analyses supporting the Callaway 

pressurizer (SWOL) repairs.” The applicant further stated that “the transients will not exceed 

the design numbers; therefore, the analyses will remain valid through the period of extended

operation and the TLAAs are dispositioned in accordance with 10 CFR 54.21(c)(1)(i).” The staff 

confirmed that those transients are included in LRA Table 4.3-2 and confirmed that the numbers 

of cycles analyzed in the analysis bound the number of cycles projected in LRA Table 4.3-2 for 

the applicant’s plant through 60 years of operation. The staff noted that the 60-year projections 

provided in LRA Table 4.3-2 are less than the analyzed cycle limit, with margin to account 

unanticipated occurrence of plant transients through the period of extended operation. The 

staff’s evaluation of the projection methodology is documented in SER Section 4.3.1.2.

The staff finds the applicant’s response to RAI 4.7.2-3 acceptable because the applicant 

confirmed that the transients used as inputs in the fatigue crack growth analyses were listed in 

LRA 4.3-2 and the 60-year projected cycles in LRA Table 4.3-2 are bounded by the numbers of 

cycles analyzed in fatigue crack growth analysis. The staff’s concern described in RAI 4.7.2-3 is 

resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fatigue crack growth analysis for the pressurizer SWOL remains valid for the period of

extended operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.5.1 

because the cycle limits assumed in the fatigue crack growth analysis will not be exceeded 

during the period of extended operation based on the 60-year projected cycles and there is 

margin in the 40-year cycle limits to account for unanticipated occurrence of plant transients 

during the period of extended operation.

4.7.2.3 FSAR Supplement

LRA Section A3.6.2 provides the FSAR supplement summary description of the applicant's 

TLAA evaluation of the fatigue crack growth analyses associated with the cold leg elbow-to-safe 

end weld flaw indications, canopy seal weld overlay, and pressurizer SWOL. The staff reviewed 

LRA Section A3.6.2 consistent with the review procedures in SRP-LR Section 4.3.3.2, which 

states that the information to be included in the FSAR supplement should include a summary 

description of the evaluation of the TLAAs and describes how the TLAAs have been 

dispositioned for the period of extended operation. 

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2. Additionally, the staff determines that the applicant provided an 

adequate summary description of its actions to address the fatigue crack analyses, as required 

by 10 CFR 54.21(d).

4.7.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that its fatigue crack analyses 
TIME-LIMITED AGING ANALYSES

4-112

associated with the cold leg elbow-to-safe end weld flaw indications, canopy seal weld overlay, 

and pressurizer SWOL remain valid for the period of extended operation. The staff also 

concludes that the FSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d).

4.7.3 Corrosion Analysis of the Reactor Vessel Cladding Indications

4.7.3.1 Summary of Technical Information in the Application

LRA Section 4.7.3 describes the applicant's assessment for corrosion analysis of the reactor 

vessel cladding indications. The LRA states that two areas were identified during RFO 13 

(spring 2004) and RFO 15 (spring 2007) where the RPV low-alloy steel has been left exposed to 

the reactor coolant. The evaluation of these indications considered a plant life of 40 years, 

which includes 20 years under the current license, plus 20 years for the period of extended 

operation. The LRA states that the vessel minimum wall thickness evaluation demonstrated 

that the wall thickness minus the maximum degraded area depth meets the criterion of ASME 

Code Section III, NB-3324.2. 

By letter dated May 6, 2014, as supplemented by a letter dated June 5, 2014, the applicant 

amended LRA Section 4.7.3 to provide an updated corrosion rate analysis for the two RPV 

cladding areas containing the corrosion-related indications. The applicant also stated that it was 

changing the basis for accepting the TLAA from 10 CFR 54.21(c)(1)(i) to 10 CFR 54.21(c)(1)(iii). 

The applicant stated that it will use the examinations of its ASME Section XI, Subsections IWB, 

IWC, and IWD Program to inspect and characterize the flaw indications during the period of 

extended operation and that the examinations of this AMP serve as an acceptable basis for 

accepting this TLAA in accordance with the requirement in 10 CFR 54.21(c)(1)(iii).

The applicant dispositioned the corrosion analysis of the reactor vessel cladding indications 

TLAA in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended 

function of the RPV will be adequately managed during the period of extended operation.

4.7.3.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the corrosion analysis of the reactor vessel cladding 

indications and the corresponding disposition, consistent with the review procedures in SRP-LR 

Section 4.7.3.1.1, which state that the existing analyses should be shown to be bounding during 

the period of extended operation. The SRP-LR also states that the applicant should show that 

conditions and assumptions used in the analysis already address the relevant aging effects for 

the period of extended operation, and acceptance criteria are maintained to provide reasonable 

assurance that the intended functions are maintained for renewal.

LRA Section 4.7.3 states that RPV low-alloy steel has been left exposed to the reactor coolant 

and that the vessel minimum wall thickness evaluation demonstrated that the wall thickness 

(5.38 in.) minus the maximum degraded area depth (0.28 in.) meets the criterion of NB-3324.2 

(4.33 in.). The amount of corrosion was calculated assuming a corrosion rate of 0.001 in/yr for 

normal operating condition, 0.015 in./yr for an outage, and 0.010 in./yr for a startup period after 

each outage. In addition, the LRA also indicates that assuming an outage corrosion rate for the 

entire 40-year period would yield 0.6 in. of corrosion. The staff noted that the corrosion 

analysis, which was performed in 2004 with an update in 2007, covered 40 additional years that 

coincides with the end of the period of extended operation.
TIME-LIMITED AGING ANALYSES

4-113

The staff noted that the applicant did not provide the thickness of the cladding and whether the 

wall thickness of 5.38 in. includes this cladding thickness; therefore, the staff was not able to 

determine if the criterion of NB-3324.2 was met. In addition, the staff noted that the applicant 

has not provided the technical bases regarding the use of the specified corrosion rates for its 

plant-specific conditions. Furthermore, only the maximum degraded area depth of 0.28 in. was 

discussed with respect to the minimum wall thickness criterion of NB-3324.2; the staff could not 

verify the adequacy of the disposition of the TLAA (at that time) in accordance with 

10 CFR 54.21(c)(1)(i).

By letter dated August 16, 2012, the staff issued RAI 4.7.3-1 requesting that the applicant justify 

that the corrosion rate of 0.015 in./yr is bounding for the conditions at the plant. The staff also 

requested the applicant to confirm that the maximum degraded area depth of 0.28 in. was a 

calculated or measured value at the time the cladding was discovered to be missing. The 

applicant was also requested to provide additional information from the calculation to support its 

conclusion that the wall thickness meets the criterion of NB-3324.2 and to revise the LRA as 

necessary.

In it response to RAI 4.7.3-1 dated September 20, 2012, the applicant stated that the calculation 

assumes corrosion rates for three plant conditions (normal operation, refueling, and startup) 

based on test data referenced in EPRI technical report, “Boric Acid Corrosion Guidebook,” 

Revision 1. The applicant stated that a corrosion rate of less than 0.001 in/yr was determined 

for carbon steel and low-alloy steel in the EPRI technical report based on test condition in 

deaerated water with 2,500 to 3,000 ppm boron at temperatures up to 590 °F. The applicant 

explained that its plant-specific normal operating conditions are consistent with historical 

maximum hot full power boric acid concentration of 1,400 ppm and the average RCS 

temperature is 585 °F. Thus, the staff found it reasonable that the applicant used 0.001 in/yr for 

its plant for normal operating conditions corrosion rate in this analysis because the applicant’s 

normal operating conditions are within the bounds of the test conditions.

The applicant explained that, for the plant startup corrosion rate, the test was conducted in the 

environment that was not deaerated, and no additional oxygen was added during the test. 

During the test, the specimens were held at 350 °F, and the results indicated slightly higher 

average corrosion rates than 0.010 in./yr. The applicant also explained that, since its plant is 

required to establish oxygen controls in the RCS before exceeding 250 °F, deaerated conditions 

will be established before exceeding the temperature range of the test data. The staff noted 

that, since the applicant’s start-up operation would maintain minimal oxygen content before 

250 °F, the actual plant condition during start-up is less severe than the test data conditions. 

Thus, it is reasonable for the applicant to use 0.010 in./yr for startup conditions corrosion rate in 

this analysis.

The applicant stated that the refueling corrosion rate of 0.015 in./yr was obtained based on a 

series of tests conducted for low alloy steel immersed in aerated water with 2,500 ppm boron at 

low temperatures, up to 140 °F. The applicant stated that its refueling conditions are consistent 

with these conditions with nominal refueling boric acid concentration and maximum refueling 

temperature at 2,500 ppm and 140 °F, respectively. The staff noted that since its actual plant 

condition during refueling is no more severe than the test data conditions, it is reasonable for 

the applicant to use 0.015 in./yr for refueling conditions corrosion rate in this analysis.

The applicant also stated that, even though its current operation schedules a refueling outage 

with an average duration of less than 8 weeks every 18 months, it used the outage corrosion 

rate of 0.015 in./yr for the entire 40-year period such that the resulting wall loss would be 0.6 in. 
TIME-LIMITED AGING ANALYSES

4-114

The staff finds the applicant use of outage corrosion rate for the entire evaluation period 

conservative because it assumed a higher corrosion rate than those for normal operation and 

startup periods.

The applicant also clarified that the minimum design wall thickness of the low-alloy steel reactor 

vessel bottom head is 5.38 in., which does not include the cladding. However, the applicant 

stated that in its assessment for corrosion of the reactor vessel cladding indications, it 

conservatively assumed that the nominal cladding thickness of 0.22 in. is included in the 

thickness of 5.38 in. The applicant explained that the depth for the defect is approximately 

0.14 in. based on its ultrasonic testing inspection report and the evaluation conservatively 

assumed the defect depth to be 0.28 in. The staff noted that the assumed depth of 0.28 in. is 

greater than the cladding thickness of 0.22 in., which supports the applicant’s statement that the 

low-alloy steel has been left exposed to reactor coolant. The staff finds the applicant’s

assumption on the damage depth of 0.28 in. reasonable because it doubled the approximated 

damage depth to allow additional margin in the evaluation.

The applicant further explained that adding the 0.6 in. wall loss due to corrosion to the assumed 

defect depth of 0.28 in. would still leave the reactor wall thickness at 4.5 in. (5.38 in. – 0.28 in. –

0.6 in. = 4.5 in.). The applicant concluded that the minimum wall thickness requirement based 

on the criterion of NB-3324.2 of 4.329 in. is satisfied.

The staff finds the applicant’s response to RAI 4.7.3-1 acceptable because the applicant 

(1) justified that corrosion rate assumed in the analysis is bounding for the conditions at the 

plant, (2) clarified the cladding thickness and whether the thickness of the vessel wall include 

the cladding, and (3) calculated and identified the remaining wall thickness at year 2044 (end of 

the period of extended operation) to support its TLAA disposition. The staff concerns described 

in RAI 4.7.3-1 are resolved.

As part of RAI B2.1.5-4b, dated January 30, 2013, the staff requested the applicant provide 

information regarding the aging management aspect of these reactor vessel cladding 

indications. Specifically, the applicant was requested to provide the inspection method to 

manage the degradation of the cladding and reactor vessel. In its response to RAI B2.1.5-4b, 

dated February 14, 2013, the applicant stated that during the upcoming refueling outage (RFO) 

(Spring 2013), an ultrasonic examination of each indication in the reactor vessel wall is planned 

and surface profile data will be collected in the area of the indication and the surrounding 

cladding. The applicant also stated that future thickness measurements of the reactor vessel 

wall indications will be performed as part of the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program. The staff’s review of the applicant’s response to 

RAI B2.1.5-4b is documented in SER Section 3.0.3.1.4.

The staff noted that, by letter dated May 6, 2014, as supplemented in the letter of June 5, 2014, 

the applicant amended LRA Section 4.7.3 to provide the following revised corrosion analysis for 

the RPV cladding indications:

The minimum required thickness of the reactor vessel, without cladding, in the area of 

the indications is 5.38 inches. The minimum measured thickness of the reactor vessel, 

including cladding, in the area of the cladding indications is 6.08 inches. The maximum 

average cladding thickness in the area of the cladding indications is 0.23 inches. The 

maximum depth of the cladding indications is 0.15 inches. The projected corrosion loss 

over 40 years is 0.119 inches. Subtracting from the minimum measured thickness of the 

reactor vessel wall the thickness of the cladding, the depth of the indication, and the 

projected corrosion loss over 40 years, leaves a wall thickness of 5.58 inches (6.08 
TIME-LIMITED AGING ANALYSES

4-115

inches – 0.23 inches – 0.15 inches – 0.119 inches = 5.58 inches) which is greater than 

the minimum required thickness of 5.38 inches.

The staff also noted that the applicant made the following changes to the basis for accepting 

this TLAA in accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii):

• The applicant indicated that LRA AMP B.2.1.1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWC Program,” will perform augmented depth 

measurements of the areas containing the flaws. 

• The applicant indicated that the previous inspection results will be compared to the 

results of the current examinations of the RPV to ensure that the bases of the analyses 

are maintained. 

• The applicant indicated that depth sizing measurements of the RPV areas containing the 

flaw indications will be performed concurrently with the visual examinations that are 

required to be performed on the interior RPV surfaces in accordance with the ASME 

Section XI Code.

• The applicant indicated that, instead of TLAA acceptance using the criterion in 

10 CFR 54.21(c)(1)(i), the TLAA is being accepted in accordance with the criterion in 

10 CFR 54.21(c)(1)(iii), and the applicant will use the augmented inspections of the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWC Program (LRA 

Section B.2.1.1) to ensure that the impacts of loss of material due to corrosion on the 

intended reactor coolant pressure boundary function of the RPV will be adequately 

maintained during the period of extended operation.

The staff evaluated the applicant’s revised corrosion analysis to determine whether the 

augmented wall thickness measurements would be capable of managing loss of material due to 

corrosion in the lower head on a 10-year ISI interval frequency. The staff noted that the 

applicant’s revised corrosion analysis analyzes corrosion through 40 years of operation. The 

staff noted, however, that even if the applicant’s projected corrosion analysis were projected 

through 60 years of operation (i.e., to 2064), the amount of corrosion projected would be 

approximately 0.18 inches of wall loss, rather than 0.119 inches of wall loss. Applying this 

assumption to the applicant’s calculation and assuming also that the 0.15 inches (“cladding 

indication depth”) represents loss of base metal, the staff noted that the remaining wall 

thickness in the limiting affected areas of the RPV bottom head would be at least 5.52 inches at 

the end of the period of extended operation (October 2044): 

6.08 inches – 0.23 inches – 0.15 inches – 0.18 inches = 5.52 inches

Based on this independent calculation, the staff determined that portions of the RPV lower head 

containing the limiting flaw indication would still have an acceptable margin against the 

minimum wall thickness of 5.38 inches for the RPV lower head even if the corrosion assessment 

were projected to the end of the period of extended operation. The staff also determined that 

the performance of the augmented wall thickness measurements on a 10-year ISI frequency will 

be sufficient to monitor and quantify any further wall loss of the RPV lower head indications prior 

to a loss of integrity of the RPV (i.e., prior to a loss of the reactor coolant pressure boundary 

function of the RPV). Therefore, based on this review, the staff concludes that the applicant has 

provided an acceptable basis for identifying the corrosion analysis is acceptable in accordance 

with 10 CFR 54.21(c)(1)(iii) because:
TIME-LIMITED AGING ANALYSES

4-116

(a) The applicant has demonstrated that the augmented wall thickness 

measurements of the impacted RPV areas, as performed in accordance 

with the ASME Section XI, Subsection IWB, IWC, and IWD Program on a 

10-year augmented inspection frequency, will be capable of monitoring 

for additional wall loss and taking appropriate corrective action prior to a 

loss of the reactor coolant pressure boundary function for the RPV.

(b) This demonstrates that implementation of the ASME Section XI, 

Subsections IWB, IWC, and IWD Program will be capable of managing 

loss of material due to corrosion in the RPV during the period of extended 

operation and that the TLAA is acceptable in accordance with the criterion 

in 10 CFR 54.21(c)(1)(iii).

Additionally, the applicant’s basis meets the acceptance criteria in SRP-LR Section 4.7.2.1 

because the applicant demonstrated that the effects of aging on the intended function(s) will be 

adequately managed for the period of extended operation. 

4.7.3.3 FSAR Supplement

LRA Section A3.6.3, as amended by letter dated September 20, 2012, provides the FSAR 

supplement summary description of the applicant's TLAA evaluation of the corrosion analysis of 

the RPV cladding indications. The staff reviewed LRA Section A3.6.3 consistent with the review 

procedures in SRP-LR Section 4.7.3.2, which states that the information to be included in the 

FSAR supplement should include a summary description of the evaluation of the TLAA and 

describes how the TLAA has been dispositioned for the period of extended operation. 

On May 6, 2014, the applicant amended this FSAR supplement summary description for the 

corrosion analysis of the RPV cladding indications. The applicant amended LRA Section A3.6.3 

to: (a) indicate that the periodic inspections of the RPV cladding indications and reconciliation of 

the inspection results with the applicant’s corrosion analysis basis will ensure the analytical 

basis is maintained; and (b) that the impact of loss of material due to corrosion on the RPV’s 

intended reactor coolant pressure boundary function will be adequately managed during the 

period of extended operation such that the TLAA may be accepted in accordance with 

10 CFR 54.21(c)(1)(iii).

The applicant also amended FSAR Supplement Table A4-1, “License Renewal Commitments,” 

to include Commitment No. 46, which states:

Enhance the ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD 

program to perform periodic inspection of the reactor vessel cladding indications 

identified in FSAR Section 5.2.3.2.2 SP and reconcile the inspection results with the 

corrosion analysis to ensure the analytical basis of the analysis are maintained.

The staff noted that Commitment No. 46 indicates that implementation will be no later than six 

months prior to the period of extended operation, and the inspections of the RPV cladding 

indications will be completed no later than six months prior to the period of extended operation 

or the end of the last refueling outage prior to the period of extended operation, whichever 

occurs later.

Consistent with the evaluation that has been given in SER Section 4.7.3.2 and the staff’s 

approval of the basis for accepting TLAA in accordance with 10 CFR 54.21(c)(1)(iii), the staff 

finds the change to LRA Section A3.6.3 acceptable because:
TIME-LIMITED AGING ANALYSES

4-117

(a) the amended version of the FSAR supplement provides an accurate 

summary description of TLAA on the corrosion analysis for the RPV 

cladding indications, as supplemented in the letter of May 6, 2014 

(b) the FSAR supplement summary description reflects that the TLAA is 

being accepted in accordance with 10 CFR 54.21(c)(1)(iii) and that 

periodic inspections of the cladding indications will be used to verify the 

acceptability of the corrosion analysis during the period of extended 

operation 

(c) implementation of the TLAA is reflected in Commitment No. 46 of FSAR 

Supplement Table A4-1, which indicates that augmented inspections of 

the RPV cladding indications will be performed in accordance with the 

applicant’s ASME Section XI, Subsections IWB, IWC, and IWD Program, 

and the results of the inspections will be reconciled against the bases 

used in the corrosion analysis, such that the TLAA remains acceptable in 

accordance with 10 CFR 54.21(c)(1)(iii)

Based on its review of the FSAR supplement, as amended by letter dated May 6, 2014, the staff 

finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2, and is therefore acceptable. 

Additionally, the staff determines that the applicant provided an adequate summary description 

of its actions to address the corrosion analysis of the reactor vessel cladding indications, 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 provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of corrosion of the 

reactor vessel cladding indications will be adequately managed for the period of extended 

operation. The staff also concludes that the FSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.4 Reactor Vessel Underclad Cracking Analyses

4.7.4.1 Summary of Technical Information in the Application

LRA Section 4.7.4 describes the applicant’s assessment of underclad cracking of the reactor 

vessel. The applicant stated that Westinghouse prepared a topical report on underclad cracking 

that included fatigue crack growth analyses and ASME Code Section XI allowable flaw size 

evaluations for typical Westinghouse vessels. The topical report concluded that the expected 

maximum flaw predicted by the crack growth analyses was less than the ASME Code 

Section XI allowable flaw size. The staff’s safety evaluation of the topical report determined that 

it may be incorporated by reference in an LRA, provided that the analysis is applicable to the 

applicant’s plant. However, the applicant stated that no underclad cracks have been discovered 

and this analysis is not invoked in its CLB, therefore it is not a TLAA by 10 CFR 54.3(a), 

Criterion 6.

4.7.4.2 Staff Evaluation

The staff reviewed LRA Section 4.7.4 and the assessment of underclad cracking of the reactor 

vessel components to verify the applicant’s basis for determining there are no applicable 

TLAAs. The staff reviewed the applicant’s evaluation and conclusion consistent with the review 
TIME-LIMITED AGING ANALYSES

4-118

procedures in SRP-LR Section 4.1.3, which state that the reviewer should verify that the 

selected analyses do not meet at least one of the criteria of a TLAA, as defined in 

10 CFR 54.3(a).

By letter dated May 3, 2012, the applicant amended LRA Section 4.7.4 to reference 

Westinghouse Report, WCAP-15338-A, as the basis for managing potential underclad cracking 

in the reactor vessel components that were made from SA-508, Class 2 alloy steel forging 

materials. The applicant also identified the fatigue crack growth analysis in WCAP-15338-A as 

a TLAA for the LRA. The applicant dispositioned this TLAA in accordance with 

10 CFR 54.21(c)(1)(i), that this fatigue crack growth analysis remains valid for the period of 

extended operation.

The staff reviewed the applicant’s amended TLAA for underclad cracking of reactor vessel 

components and the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the 

review procedures in SRP-LR Section 4.3.3.1.5.1. These procedures state that the operating 

cyclic experiences and a list of the assumed cycles used in the existing analysis are reviewed to 

ensure that the number of assumed cycles would not be exceeded during the period of 

extended operation.

The staff noted that the WCAP-15338-A provides a fatigue crack growth analysis for underclad 

cracks that are postulated in the internal cladding of SA-508, Class 2 alloy steel components in 

Westinghouse-designed RPVs. The staff noted that the fatigue crack growth analysis was 

based on ASME Code Section Xl, Appendix A, and evaluated potential RPV underclad flaws 

over the licensed operating period. The staff’s review of the fatigue crack growth analysis is 

documented in its Safety Evaluation of WCAP-15338, “A Review of Cracking Associated with 

Weld Deposited Cladding In Operating PWR Plants,” dated October 15, 2001 (ADAMS 

Accession No. ML012890230).

The staff’s SE indicated that a license renewal applicant must address two action items if 

WCAP-15338 is referenced for use in the LRA. The first action item states that the applicant 

should demonstrate that the design cycles assumed in WCAP-15338-A bound the number of 

cycles for 60 years of operation at the plant. The second action item states that the applicant 

should provide a summary description of the TLAA evaluation in the FSAR supplement.

The staff noted that Westinghouse considered the entire set of design basis transients to assess 

the impact on the postulated flaw sizes in the WCAP-15338 analysis. The staff further 

confirmed that those design basis transients considered in WCAP-15338 are included in LRA 

Table 4.3-2, the transients monitored by the applicant’s Fatigue Monitoring Program. The staff 

also confirmed that the number of cycles analyzed in WCAP-15338-A is bounding for the 

number of cycles projected for Callaway for 60 years of operation, as shown LRA Table 4.3-2. 

Thus, the applicant addressed the first action item and demonstrated that the WCAP-15338-A 

bound the number of cycles for 60 years of operation for its plant. The staff’s evaluation of the 

applicant’s projection methodology is documented in SER Section 4.3.1.2. The staff noted that 

the applicant, by letter dated May 3, 2012, revised its LRA to include LRA Section A3.6.4, which 

is the FSAR supplement for the TLAA related to underclad cracking of RPV components and 

WCAP-15338. Thus, the applicant addressed the second action item and provided a summary 

description of the TLAA evaluation in the FSAR supplement. The staff’s review of LRA 

Section A3.6.4 is documented in SER Section 4.7.4.3.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analysis for underclad cracking of the reactor vessel components remains valid for the 

period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 
TIME-LIMITED AGING ANALYSES

4-119

Section 4.3.2.1.5.1 because the fatigue crack growth analysis demonstrated that the full set of 

design transients were considered and the design cycle limits will not be exceeded during the 

period of extended operation.

4.7.4.3 FSAR Supplement

LRA Section A3.6.4, as amended by letter dated May 3, 2012, provides the FSAR supplement 

summarizing the TLAA for underclad cracking of the reactor vessel components. The staff 

reviewed LRA Section A3.6.4 consistent with the review procedures in SRP-LR Section 4.3.3.2, 

which states that the information to be included in the FSAR supplement should include a 

summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2. Additionally, the staff determines that the applicant provided an 

adequate summary description of its actions to address the TLAA for underclad cracking of the 

reactor vessel components, as required by 10 CFR 54.21(d).

4.7.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the analysis for underclad 

cracking of the reactor vessel components remains valid for the period of extended operation. 

The staff also concludes that the FSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.5 Reactor Coolant Pump Flywheel Fatigue Crack Growth Analysis

4.7.5.1 Summary of Technical Information in the Application

LRA Section 4.7.5 describes the applicant's TLAA for RCP flywheel fatigue crack growth 

analysis. The LRA states that a fatigue crack growth analysis demonstrates that 6,000 

start-stop cycles (over an assumed 60-year life) will produce an acceptable extension of the 

crack. The evaluation is based on the 60-year operating period. The LRA states that the 6,000 

events in Callaway’s fatigue flaw growth are based on the sum of the RCP start-stop cycles in 

FSAR Table 3.9(N)-1 SP, multiplied by 1.5, which is the general design number of events for the 

Nuclear Steam Supply System extrapolated to 60 years. The LRA states that only 220 RCP 

start-stop events are projected to occur in 60 years. Therefore, the applicant dispositioned the 

flywheel TLAA, in accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid during 

the period of extended operation.

4.7.5.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for RCP flywheel and the corresponding disposition of 

10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.7.3.1.1, 

which states that the existing analyses should be shown to be bounding during the period of 

extended operation. The SRP-LR also states that the applicant should show that conditions and 

assumptions used in the analysis already address the relevant aging effects for the period of 

extended operation, and acceptance criteria are maintained to provide reasonable assurance 

that the intended functions are maintained for renewal.

The staff noted that the applicant is relying on the flaw growth analysis referenced in

“Transmittal of WCAP-15666, ‘Extension of Reactor Coolant Pump Motor Flywheel 
TIME-LIMITED AGING ANALYSES

4-120

Examination,’ Non-Proprietary Class 3 (MUHP-3043),” dated August 24, 2001, (ADAMS 

Accession No. ML012420149) that assumed 6,000 start-stop cycles for the RCP for a 60-year 

operating period. The staff confirmed that the NRC endorsed the methodology and results in its 

“Safety Evaluation of Topical Report WCAP-15666, ‘Extension of Reactor Coolant Pump Motor 

Flywheel Examination,’” dated May 5, 2003 (ADAMS Accession No. ML031250595). LRA 

Table 4.3-2 shows the projected total number of RCP startups and shutdowns for the 60-year 

projection to be 220 for the most limiting RCP. The staff noted the expected cycles through the 

period of extended operation to be less than 5 percent of the design limit of 6,000 cycles, which 

leaves significant margin to account for unanticipated occurrences of the RCP operation.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fatigue flaw growth analysis for the RCP flywheel remains valid for the period of extended 

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the 

applicant’s 60-year projection for the RCP startups and shutdowns demonstrates that the 

existing analysis remains valid for the period of extended operation.

4.7.5.3 FSAR Supplement

LRA Section A3.6.5, as amended by letter dated May 3, 2012, provides the FSAR supplement 

summary description of the applicant's TLAA evaluation of the RCP flywheel fatigue crack 

growth analysis. The staff reviewed LRA Section A3.6.5 consistent with the review procedures 

in SRP-LR Section 4.7.3.2, which states that the information to be included in the FSAR 

supplement should include a summary description of the evaluation of the TLAA and describes 

how the TLAA has been dispositioned for the period of extended operation. The applicant 

revised the LRA section number from A3.6.4 to A3.6.5 by letter dated May 3, 2012. The staff 

reviewed the revisions and noted they were administrative and did not alter the technical 

content.

Based on its review of the FSAR supplement, as amended by letter dated May 3, 2012, the staff 

finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the RCP flywheel fatigue crack analysis, as required by 10 CFR 54.21(d).

4.7.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the RCP flywheel fatigue crack 

analysis remains valid for the period of extended operation. The staff also concludes that the 

FSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.7.6 High-Energy Line Break Postulation Based on Fatigue Cumulative Usage Factors

4.7.6.1 Summary of Technical Information in the Application

LRA Section 4.7.6 describes the applicant’s TLAA for HELB postulation based on fatigue CUF. 

The LRA states that the selection of ASME Code Section Ill, Class 1 piping HELB locations 

depends on CUFs, which will remain valid as long as the assumed numbers of cycles are not 

exceeded. Furthermore, it states that the Fatigue Monitoring Program ensures that the 

analytical bases of the HELB locations are maintained or that a HELB analysis for the new 

locations with a CUF greater than 0.1 is performed.
TIME-LIMITED AGING ANALYSES

4-121

The applicant dispositioned the TLAA, in accordance with 10 CFR 54.21(c)(1)(iii), that the 

effects of cracking postulated for HELB locations based on CUF will be adequately managed by

the Fatigue Monitoring Program for the period of extended operation.

4.7.6.2 Staff Evaluation

The staff reviewed LRA Section 4.7.6 and the TLAAs for HELB postulation based on fatigue 

CUF to verify, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging will be 

adequately managed during the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition consistent with the 

review procedures in SRP-LR Section 4.7.3.1.3, which states that the applicant is to identify the 

structures and components associated with the TLAA and to describe the TLAA with respect to 

the objectives of the analysis, conditions, assumptions used, acceptance criteria, relevant aging 

effects, and intended functions of the components or structures in the analysis. It further states 

that the reviewer is to assess the applicant’s AMP to verify that the effects of aging on the 

intended functions will be adequately managed consistent with the CLB for the period of 

extended operation.

FSAR Section 3.6.1.1.a SP defines high-energy piping as systems or portions of systems in 

which the maximum operating temperature exceeds 93 °C (200 °F) or the maximum operating 

pressure exceeds 275 psig during normal plant conditions. The staff noted that the pipe break 

identification basis in FSAR Section 3.6.2.1.1 SP is defined in a manner that conforms to the 

pipe break identification criteria in NRC Branch Technical Position MEB 3-1. The staff noted 

that a given location is identified as a line break location if it was a high-energy line location that 

satisfied the criteria in FSAR Section 3.6.1.1.a SP. One such criterion is that intermediate 

ASME Code Class 1 piping locations (i.e., locations between terminal ends) with design basis 

CUF values exceeding a value of 0.1 are identified as line break locations. The staff noted that 

the postulations of break locations based on CUFs are TLAAs because they are dependent on 

an assumed number of cycles expected for the design of the plant. FSAR Section 3.6.2.1.1.a

SP also indicated that breaks are eliminated from RCS primary loops, the accumulator and RHR 

lines because of the approved application of a LBB methodology. 

The applicant credits the Fatigue Monitoring Program to manage metal fatigue of these 

postulated HELB locations through the period of extended operation. The staff noted that as 

long as the number of transients that occur at the site remain bounded by the 40-year numbers 

of cycles assumed in these analyses, the HELB postulation evaluation remains valid. The staff 

also noted that the applicant enhanced the “corrective actions” program element in its Fatigue 

Monitoring Program to indicate that when a cycle counting action limit is reached, action will be 

taken to ensure the analytical bases of the HELB locations are maintained. The staff 

determined that the applicant’s AMP, when enhanced, ensures that the numbers of transients 

actually experienced during the period of extended operation remain below the assumed 

number or that corrective actions are taken. The staff’s evaluation of the Fatigue Monitoring 

Program and this enhancement is documented in SER Section 3.0.3.2.22.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of cracking postulated for HELB locations based on CUF will be adequately 

managed for the period of extended operation. Additionally, it meets the acceptance criteria in 

SRP-LR Section 4.7.2.1 because the applicant’s Fatigue Monitoring Program monitors and 

tracks the number design basis transients that will occur through the period of extended 

operation and includes action limits and corrective actions to ensure that the effects of metal 
TIME-LIMITED AGING ANALYSES

4-122

fatigue on the intended functions of these postulated HELB locations will be managed during the 

period of extended operation.

4.7.6.3 FSAR Supplement

LRA Section A3.6.6, as amended by letter dated May 3, 2012, provides the FSAR supplement 

summarizing the TLAA for HELB postulation based on CUF. The staff reviewed LRA 

Section A3.6.6, consistent with the review procedures in SRP-LR 4.7.3.2, which states that the 

information to be included in the FSAR supplement should include a summary description of the 

evaluation of the TLAA and describe how the TLAA has been dispositioned for the period of

extended operation. The applicant revised the LRA section number from A3.6.5 to A3.6.6 by 

letter dated May 3, 2012. The staff reviewed the revisions and noted that they were 

administrative and did not alter the technical content.

Based on its review of the FSAR supplement, as amended by letter dated May 3, 2012, the staff 

finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the TLAA for HELB postulation based on CUF as required by 10 CFR 54.21(d).

4.7.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of cracking postulated 

for HELB locations based on CUF will be adequately managed for the period of extended 

operation. The staff also concludes that the FSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.7 Fatigue Crack Growth Assessment in Support of a Fracture Mechanics Analysis for 

the Leak-Before-Break Elimination of Dynamic Effects of Piping Failures

4.7.7.1 Summary of Technical Information in the Application

LRA Section 4.7.7 describes the TLAAs for fatigue crack growth and fracture mechanics 

analyses performed to support LBB application. LBB analyses eliminated postulated breaks in 

the applicant’s reactor coolant loops (RCL), accumulator injection lines, and RHR hot leg 

suction lines. 

Reactor Coolant Loops. The LRA states that the fatigue crack growth analysis associated with 

the LBB analyses depend on design transient cycle assumptions and will remain valid as long 

as the assumed numbers of cycles are not exceeded. The LRA also states that the projected 

transient accumulations show that the numbers of transient cycles are expected to remain within 

the assumed numbers and therefore the analyses will remain valid for the period of extended 

operation. Therefore, the TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(i). 

Accumulator Injection and Residual Heat Removal Lines. The LRA states that the fatigue crack 

growth analyses are based on assumed 40-year design transients. The LRA also states that 

the projected transient accumulations are expected to remain within the assumed numbers and 

therefore the analyses will remain valid for the period of extended operation. The TLAA is 

dispositioned in accordance with 10 CFR 54.21(c)(1)(i).
TIME-LIMITED AGING ANALYSES

4-123

4.7.7.2 Staff Evaluation

The staff reviewed the applicant’s TLAAs for fatigue crack growth and fracture mechanics 

analyses performed to support LBB and the corresponding dispositions of 

10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.3.3.1.5.1. 

These procedures state that the operating cyclic experiences and a list of the assumed cycles 

used in the existing analysis are reviewed to ensure that the number of assumed cycles would 

not be exceeded during the period of extended operation.

LRA Section 4.7.7 states that the reactor coolant loops piping LBB analyses included a fracture 

mechanics analysis and a fatigue crack growth assessment. The staff noted that the fracture 

mechanics analysis accounts for reduction in fracture toughness of the CASS in the primary 

loops from thermal aging. The LRA indicates that the fracture mechanics analysis in support of 

the LBB submittal was performed for a reference material with fully-aged fracture toughness 

material properties. However, the applicant did not indicate whether the RCL piping is 

susceptible to thermal aging and did not justify why such a fracture mechanics analysis, 

performed for a reference material with fully-aged fracture toughness material properties, is not 

a TLAA as defined by 10 CFR 54.3.

By letter dated August 6, 2012, the staff issued RAI 4.7.7-2 requesting the applicant discuss 

whether the reactor coolant loops piping material is susceptible to thermal aging and justify why 

the fracture toughness material properties used in the LBB analysis are not time-dependent 

parameters. The applicant was also requested to justify that the thermal aging data used in the 

LBB analysis are up-to-date or conservative when compared to the most recent data for the 

state of the industry if the analysis involves assumption of referenced fracture toughness values.

In its response dated September 6, 2012, the applicant stated that the reactor coolant loops 

LBB fracture mechanics analysis was performed with the fracture toughness (J1C , Tmat and Jmax) 

from a reference material, which showed that the reference material values bound the fully aged 

fracture toughness properties of the RCPB cast stainless steel material. The applicant stated 

that it compared the GTAWs prepared with stainless steel filler material against the results of 

NUREG/CR-6428. In addition, the applicant performed a comparison of the SA-351 Grade 

CF8A base metal against the results of NUREG/CR-4513, Revision 1, “Estimation of Fracture 

Toughness of Cast Stainless Steels during Thermal Aging in LWR Systems,” dated May 1994. 

The applicant concluded that fracture toughness properties values were compared to the most 

recent data for the state of the industry and determined that the data used in the LBB analysis 

was conservative.

Thus, based on the comparison performed by the applicant, the staff finds that the applicant’s 

calculation remains valid when compared to the most recent available data in NUREG/CR-6428 

and NUREG/CR-4513. Furthermore, based on the results of this comparison, the staff finds 

that there is not a time-dependency for the lower bound fracture toughness value that was 

assumed for reactor coolant loop piping and fitting.

The applicant also stated that the reactor coolant loop piping material and elbow fittings are 

SA351 Grade CF8A cast stainless steel. Furthermore, the molybdenum (less than 0.5 percent) 

and ferrite (less than 20 percent) content of these fittings and piping pieces are below the 

thermal aging significance threshold. The applicant concluded that thermal aging of its CASS 

reactor coolant loop piping and fittings is not a concern, as described in LRA 

Section 3.1.2.2.6.2. The staff noted that GALL Report AMP XI.M12 indicates that, for steels 

with low molybdenum (less than 0.5 percent) content, only static-cast steels with more than 

20 percent ferrite are potentially susceptible to thermal aging embrittlement. The staff’s review 
TIME-LIMITED AGING ANALYSES

4-124

of the applicant’s CASS reactor coolant system piping and components exposed to reactor 

coolant is documented in SER Section 3.1.2.2.6.2, which determined that these components are 

not subject to thermal aging embrittlement. Therefore, since reactor coolant loop piping and 

fitting components are not susceptible to thermal aging embrittlement, the staff finds it 

reasonable that the applicant does not need to manage this aging effect for the period of 

extended operation.

In addition, the staff finds it acceptable that the fracture mechanics evaluation in the RCL LBB 

analysis is not a TLAA, in accordance with 10 CFR 54.3, because it does not involve 

time-limited assumptions defined by the current operating term.

The staff finds the applicant’s response to RAI 4.7.7-2 acceptable because the applicant 

provided sufficient justification, as described above, that the reactor coolant loops piping 

material is not susceptible to thermal aging embrittlement, and the analysis performed does not 

involve time-limited assumptions. The staff concern described in RAI 4.7.2-2 is resolved.

The LRA indicates that the 40-year design numbers of transients were used in the fatigue crack 

growth analysis for the reactor coolant loop piping. The staff also noted that the 60-year 

projections provided in LRA Table 4.3-2 are less than the design limit for each transient, with 

margin to account unanticipated occurrence of plant transients through the period of extended 

operation. The staff’s evaluation of the projection methodology is documented in SER 

Section 4.3.1.2.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fatigue crack growth analysis that supports the reactor coolant loop piping LBB analyses 

remain valid for the period of extended operation. Additionally, it meets the acceptance criteria 

in SRP-LR Section 4.3.2.1.5.1 because the 40-year cycle limits assumed in these fatigue crack 

growth evaluations will not be exceeded during the period of extended operation based on the 

60-year projected cycles and because there is margin in the 40-year cycle limits to account for 

unanticipated occurrence of plant transients during the period of extended operation.

LRA Section 4.7.7 states that the LBB analysis for the accumulator injection and RHR lines 

included a fracture mechanics and a fatigue crack growth analysis. The applicant stated these 

lines and associated fittings are forged and are not subject to thermal aging. Therefore, the 

fracture mechanics analyses are not TLAAs by 10 CFR 54.3(a), Criterion 2. The staff noted 

that, as described in the GALL Report, CASS may exhibit significant embrittlement (reduction in 

fracture toughness) because of thermal aging. The staff noted that, since the accumulator 

injection and RHR lines included associated fittings that are forged, thermal aging embrittlement 

is not a concern. The staff evaluation of the applicant’s absence of TLAA for these fracture 

mechanics analyses is documented in SER Section 4.1.2.1.2.

The LRA states that normal operating and upset thermal transients were selected as input to the 

fatigue crack growth evaluation of the LBB analyses. However, LRA Section 4.7.7 did not 

specifically identify the transients that were used in the analysis, and the staff cannot verify the 

adequacy of the disposition of the TLAA in accordance with 10 CFR 54.21(c)(1)(i). By letter 

dated August 6, 2012, the staff issued RAI 4.7.7-1 requesting the applicant identify all the 

transients and associated number of cycles that were used in the fatigue crack growth analysis 

for the accumulator injection and RHR lines.

In its response to 4.7.7-1 dated September 6, 2012, the applicant provided a list of the 

transients and associated number of cycles used in the LBB fatigue crack growth analyses for 

the accumulator injection and RHR lines. The staff confirmed that those transients are included 
TIME-LIMITED AGING ANALYSES

4-125

in LRA Table 4.3-2 and confirmed that the numbers of cycles analyzed in the fatigue crack 

growth analysis bound the number of cycles projected in LRA Table 4.3-2 for the applicant’s 

plant through 60 years of operation. The staff noted that the 60-year projections provided in 

LRA Table 4.3-2 are less than the analyzed cycle limit, with margin to account for unanticipated 

occurrences of plant transients through the period of extended operation. The staff’s evaluation 

of the projection methodology is documented in SER Section 4.3.1.2.

The staff finds the applicant’s response to RAI 4.7.7-1 acceptable because the applicant 

confirmed that the transients used as inputs in the fatigue crack growth analyses were listed in 

LRA Table 4.3-2, and the 60-year projected cycles in LRA Table 4.3-2 are bounded by the 

numbers of cycles analyzed in these fatigue crack growth analysis. The staff concern described 

in RAI 4.7.7-1 is resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the fatigue crack growth analysis for the accumulator injection and RHR lines remains valid for 

the period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.5.1 because the cycle limits established in the fatigue crack growth evaluation 

will not be exceeded during the period of extended operation based on the 60-year projected 

cycles. The staff also finds there is margin in the 40-year cycle limits to account for 

unanticipated occurrence of plant transients during the period of extended operation.

4.7.7.3 FSAR Supplement

LRA Section A3.6.7, as amended by letter dated May 3, 2012, provides the FSAR supplement 

summary description of the applicant's TLAAs evaluation of the fatigue crack growth analyses 

and fracture mechanics analyses associated with the LBB. The staff reviewed LRA 

Section A3.6.7, consistent with the review procedures in SRP-LR Section 4.3.3.2, which states 

that the information to be included in the FSAR supplement should include a summary 

description of the evaluation of the TLAAs and describe how the TLAAs have been 

dispositioned for the period of extended operation. The applicant revised the LRA section 

number from A3.6.6 to A3.6.7 by letter dated May 3, 2012. The staff reviewed the revisions and 

noted that they were administrative and did not alter the technical content.

Based on its review of the FSAR supplement, as amended by letter dated May 3, 2012, the staff 

finds it meets the acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the fatigue crack analyses, as required by 10 CFR 54.21(d).

4.7.7.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the fatigue crack growth analyses 

and fracture mechanics analyses associated with LBB remain valid for the period of extended 

operation. The staff also concludes that the FSAR supplement contains an appropriate 

summary description of the TLAAs evaluation, as required by 10 CFR 54.21(d).

4.7.8 Replacement Class 3 Buried Piping

4.7.8.1 Summary of Technical Information in the Application

LRA Section 4.7.8 describes the applicant’s TLAA for its replacement essential service water 

(ESW) piping from the pump house to the control building and from the control building to the 
TIME-LIMITED AGING ANALYSES

4-126

ultimate heat sink (UHS) cooling tower with high-density polyethylene (HDPE) piping. The 

applicant submitted a relief request as an alternative to ASME Code Section XI to allow 

installation of HDPE piping in lieu of metallic piping. The LRA states that the acceptance criteria 

in the analysis of the design pressure, longitudinal stress, and thermal loads; as well as the 

modulus of elasticity used as input to the analysis of the soil and surcharge loads and thermal 

loads were all based on a 40-year life. The LRA also states that the replacement of the buried 

piping began in 2008 and, therefore, a 40-year life exceeds the end of the period of extended 

operation, October 2044.

The applicant dispositioned the TLAA for the replacement ESW piping, in accordance with 

10 CFR 54.21(c)(1)(i), that the analyses remain valid for the period of extended operation.

4.7.8.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the replacement ESW piping and the corresponding 

disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR 

Section 4.7.3.1.1. The procedures state that the applicant should show that the conditions and 

assumptions used in the analysis already address the relevant aging effects for the period of 

extended operation and that acceptance criteria are maintained to provide reasonable 

assurance that the intended function(s) is maintained for renewal.

The staff noted that calculations 2007-13241, Revision 1, “Minimum Wall Thickness for ESW 

Buried HDPE Piping,” dated September 3, 2008, (ADAMS Accession No. ML082630799) and 

2007-1670, “Analysis of Buried HDPE Piping,” dated December 21, 2007, (ADAMS Accession 

No. ML081220483), use a 40-year normal service life and include a 30-day duration of peak 

post-accident conditions. The staff also noted that LRA Section 4.7.8 states that the 

replacement of the buried ESW piping with HDPE material began in 2008. The staff further 

noted that the design analysis for 40 years surpasses the end of the period of extended 

operation for the applicant’s site, October 2044; however, based on a review of the FSAR, the 

staff noted that other transient scenarios less severe than the postulated 30-day transient (e.g., 

inadvertent opening of a pressurizer safety or relief valve, minor steam system piping failure) 

could result in operating parameters that are higher than those for the 40-year life parameters 

and for which multiple frequencies could occur in the plant’s expected life (i.e., 60 years). 

These potential other transients are not reflected in the calculations. By letter dated 

July 5, 2012, the staff issued RAI 4.7.8-1 requesting the applicant to state whether other 

transients should have been included in the HDPE analyses and, if so, state the basis for why 

these additional transients do not impact the 40-year life of the piping.

In its response to RAI 4.7.8-1 dated August 6, 2012, the applicant stated that only the following 

transients result in a release of energy to the containment environment:

• inadvertent opening of a steam generator relief or safety valve (Condition II, FSAR 

Chapter 15.1.4)

• inadvertent opening of a pressurizer safety or relief valve (Condition II, FSAR 

Chapter 15.6.1)

• break in instrument line or other lines from RCPB that penetrate containment 

(Condition II, FSAR Chapter 15.6.2)
TIME-LIMITED AGING ANALYSES

4-127

• loss-of-coolant accidents resulting from a spectrum of postulated piping breaks within 

the RCPB (small break) (Condition III, FSAR 15.6.5)

• steam system piping failure (Condition III, FSAR 15.1.5)

In its response the applicant also stated that:

The Condition II transients will not result in the ESW return piping exceeding its 

normal design temperature of [41 °C] (105 °F). The vent paths for the 

Condition II transients do not discharge to the containment atmosphere and 

would not increase the containment temperature. Therefore, an increase to the 

ESW return piping temperature would not be expected. Even if conditions 

resulted in a release to the containment atmosphere (e.g. blown pressurizer relief 

tank rupture disk), the accident requires that the [RCS] be at normal operating 

pressure (NOP). With the RCS at NOP, the RHR system would not be aligned to 

the RCS. Since the RHR system accounts for most of the heat load on the ESW 

system; there would be sufficient heat removal capacity to prevent the ESW 

return piping from exceeding its normal design temperature of [41 °C] (105° F).

Condition III transients occur very infrequently during the life of the plant but may 

result in the ESW water increasing to greater than the normal design temperature 

of [41 °C] (105° F). The design basis assumes five small LOCA events and five 

small steam line break events. The ESW return piping temperature during these 

Condition III transients would be much closer to the normal design temperature 

versus the post-accident design temperature of [79 °C] (175 °F). The large break 

LOCA event itself only results in an ESW temperature of [60 °C] (140 °F), and 

the mass and energy released during a small break event is a fraction of the 

release during a design basis event. The peak post-LOCA ESW temperature will 

only be short-lived, and the long-term post-LOCA discharge temperature will be 

significantly lower. Given that the maximum ESW temperature and the duration 

at the maximum temperature were analyzed at a much greater value than those 

actually expected; the current analysis is sufficient to account for the Condition III 

transients.

The staff finds the applicant’s response acceptable because, based on a review of all operating 

transients in FSAR Section 15, none exceed the design limits in the calculations for minimum 

wall thickness and the stress analyses for the HDPE piping. The staff’s concern described in 

RAI 4.7.8-1 is resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(i), that 

the analyses for the replacement ESW piping remain valid for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because, as 

documented in the above referenced calculations and response to RAI 4.7.8-1, the stress 

evaluations are acceptable for 40 years, which, in the case of the applicant’s site, will surpass 

the period of extended operation. The staff noted that the applicant will be required to submit 

subsequent relief requests in accordance with 10 CFR 50.55a at the start of each subsequent 

inservice inspection interval in order to continue to allow use of the HDPE piping in lieu of 

metallic piping.
TIME-LIMITED AGING ANALYSES

4-128

4.7.8.3 FSAR Supplement

LRA Section A3.6.8, as amended by letter dated May 3, 2012, provides the FSAR supplement 

summarizing the replacement Class 3 buried piping. The staff reviewed LRA Section A3.6.8, 

consistent with the review procedures in SRP-LR Section 4.7.3.2, which states that each such 

summary description should contain information that the TLAAs have been dispositioned for the 

period of extended operation and should have sufficient detail to ensure that later changes can 

be controlled by 10 CFR 50.59. The applicant revised the LRA section number from A3.6.7 to 

A3.6.8 by letter dated May 3, 2012. The staff reviewed the revisions and noted that they were 

administrative and did not alter the technical content.

Based on its review of the FSAR supplement, as amended by letter dated May 3, 2012, the staff 

finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2, and is therefore acceptable. 

Additionally, the staff determines that the applicant provided an adequate summary description 

of its actions to address the replacement Class 3 buried piping, as required by 10 CFR 54.21(d).

4.7.8.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(i), that the analyses for the replacement 

Class 3 buried piping remain valid for the period of extended operation. The staff also 

concludes that the FSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d).

4.7.9 Replacement Steam Generator Tube Wear

4.7.9.1 Summary of Technical Information in the Application

LRA Section 4.7.9 describes the applicant’s TLAA for replacement steam generator tube wear. 

The applicant stated that for the replacement steam generators, the time-averaged wear rates 

at the tube support locations were analyzed due to the impact or sliding motion of the tubes 

against their supports. The LRA also states that this analysis assumed a cumulative operating 

service life of 45 years and compared the calculated maximum wear (0.010 in.) to the maximum 

allowable wear of 40 percent of the tube wall thickness (0.0156 in.). In addition, the LRA states 

that since the 45-year design life of the RSG tubes extends beyond the period of extended 

operation, the design of the replacement steam generator tubes is valid through the period of 

extended operation. The applicant dispositioned the TLAA for the steam generator tube wear in 

accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the period of 

extended operation.

4.7.9.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the steam generator tube wear and the 

corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in 

SRP-LR Section 4.7.3, which state that for certain applicants, plant-specific analyses may meet 

the definition of a TLAA as given in 10 CFR 54.3. SRP-LR Section 4.7.3 also states that the 

review of these TLAAs provides the assurance that the aging effect is properly addressed 

through the period of extended operation.

LRA Section B2.1.9, “Steam Generators,” indicates that the previous steam generators were 

replaced in Fall 2005 (RFO 14). LRA Section 4.7.9 states that the TLAA analysis assumed a 

cumulative operating service of 45 years. LRA Section 4.7.9 also compared the calculated 
TIME-LIMITED AGING ANALYSES

4-129

maximum wear of 0.010 in. to the maximum allowable wear of 40 percent of the tube wall 

thickness, 0.0156 in.

The staff noted that by letter dated May 17, 2012, the applicant submitted to the NRC the 

“Callaway Energy Center Steam Generator Tube Inspection Report.” Section 4.0 of the 

inspection report addresses the results of the applicant’s in-service inspection of the steam 

generators, which was conducted during RFO 18 (corresponding to 6 years of operation of the 

steam generators). The following summarizes the inspection results and related information for 

the tube wear observed in the four replacement steam generators as addressed in Table 2 of 

the steam generator inspection report:

• Callaway’s plugging limit for the steam generator tubes was set at 28 percent 

through-wall, conservatively, for the next three cycles (Cycles 19, 20, and 21).

• A total of 258 steam generator tubes indicated wear. A total of 232 tubes indicated 

anti-vibration bar (AVB) wear, and 28 tubes indicated tube support plate (TSP) wear.

• Based on the inspection results, a total of 29 tubes were plugged due to AVB wear 

In its review, the staff noted that some of the actual measured tube wear indications exceeded 

the calculated maximum wear (0.010 in.). Therefore, the staff needed additional information to 

justify the validity of the applicant’s TLAA and its disposition. By letter dated August 16, 2012, 

the staff issued RAI 4.7.9-2 requesting that the applicant justify why the applicant’s TLAA is 

valid even though some of the steam generator tubes indicated wear greater than the calculated 

maximum wear for 45 years (0.010 in. for 45 years). The staff also requested that if necessary, 

the applicant identify any impact of actual measured wear on its analysis, and revise the TLAA 

accordingly.

In its response dated September 20, 2012, the applicant stated that the AVB wear is the most 

active wear mechanism in its steam generators, as observed by the steam generator tube 

inspections, but only one percent (232 out of 23,488) of the steam generator tubes show 

indications of AVB wear.

In addition, the applicant stated that all wear indications are justified for continued operation until 

the next scheduled inspection, typically 3 cycles, by establishing a wear rate based on 

measured data. The applicant stated that 30 tubes out of a total 23,488 tubes were plugged for 

aging management, including one tube that was plugged pre-service. The applicant further 

stated that since the wear analysis describes the wear experienced by the typical steam 

generator tube, and since all tubes with excessive wear are removed from service, the TLAA will 

remain valid for the period of extended operation. The applicant stated that excessive wear is 

defined as tube wear exceeding the TS 5.5.9.c tube plugging criterion of 40 percent 

through-wall thickness, as incorporated in the Steam Generators Program.

In addition to its response above, the applicant also changed the disposition of this TLAA to 

10 CFR 54.21(c)(1)(iii), and stated that the effects of aging on the intended function(s) will be 

adequately managed for the period of extended operation using the Steam Generators 

Program. The applicant also revised LRA Sections 4.7.9 and A3.6.9 to reflect the revised TLAA 

disposition, consistent with 10 CFR 54.21(c)(1)(iii). The staff’s evaluation of the Steam 

Generators Program is discussed in SER Section 3.0.3.1.7.

The applicant stated that the Steam Generators Program detects flaws in tubing, plugs, and 

tube supports needed to maintain tube integrity. The applicant also stated that assessment of 

tube integrity is performed in accordance with plant TS and the program implementing 
TIME-LIMITED AGING ANALYSES

4-130

procedures. In addition, the applicant stated that plugs and tube supports with aging indications 

are evaluated for corrective actions, in accordance with the applicant’s Corrective Action 

Program and the Steam Generators Program. The applicant further stated that, therefore, the 

steam generator tube wear associated with this TLAA will be adequately managed for the period 

of extended operation.

In its review, the staff noted the applicant’s explanation regarding AVB wear and that the TLAA’s 

disposition was changed to 10 CFR 54.21(c)(1)(iii), indicating excessive tube wear will be 

managed by the Steam Generators Program.

However, the staff also noted that the total number of the steam generator tubes (i.e., 23,488), 

described in the applicant’s response is not consistent with the total number of the tubes 

(22,144) in Table 1 of the applicant’s inspection report, dated May 17, 2012. In addition, the 

applicant’s response does not clearly address the number of the steam generator tubes that 

show wear indications due to TSP wear. Therefore, the staff needed confirmation on the actual 

total number of steam generator tubes. 

By letter dated November 21, 2012, the staff issued RAI 4.7.9-2a requesting that the applicant 

clarify the total number of steam generator tubes. The staff also requested that the applicant 

confirm if a total of 258 steam generator tubes have wear indications because of AVB wear and 

TSP wear, as described in the applicant’s inspection report dated May 17, 2012.

In its response dated December 13, 2012, the applicant stated that there are 5,872 tubes in 

each steam generator, for a total of 23,488 tubes. The applicant also clarified that the number 

provided in the inspection report dated May 17, 2012 is a summary of the number of tubes 

(22,143) that were eddy current tested during RFO 18. The applicant also stated that Table 2 of 

the inspection report dated May 17, 2012, correctly presents the number of tube support plate 

indications and there are a total of 258 steam generator tubes that show wear indications 

because of AVB wear or TSP wear. The staff finds the applicant’s response acceptable 

because the applicant clarified that the total number of the steam generator tubes are 23,488 

and a total of 258 steam generator tubes show wear indications because of AVB wear or TSP 

wear. The staff’s concerns described in RAIs 4.7.9-2 and 4.7.9-2a are resolved.

LRA Section 4.7.9 indicates that the applicant’s TLAA analyzes steam generator tube wear 

caused by the impact or sliding motion of the tubes against their supports. In comparison, the 

recent industry operating experience indicates that steam generator tubes may be subject to 

tube-to-tube wear, as well as tube wear against their support structures. However, LRA 

Section 4.7.9 did not indicate that the applicant’s TLAA considered tube-to-tube wear as one of 

the mechanisms that could cause steam generator tube wear. By letter dated August 16, 2012, 

the staff issued RAI 4.7.9-3 requesting that the applicant provide its technical basis for why the 

TLAA did not consider tube-to-tube wear as one of the wear mechanisms.

In its response dated September 20, 2012, the applicant stated that the steam generators, 

which have experienced tube-to-tube wear in the industry, are from a different manufacturer 

than the manufacturer of Callaway’s steam generators. The applicant further stated that 

Callaway has a different nuclear steam supply system design (AREVA-manufactured 

Westinghouse 4-loop design) from the Combustion Engineering 2-loop design that experienced 

steam generator tube-to-tube wear. The applicant also stated that a review of its steam 

generator inspections confirmed that Callaway steam generator tubes are not exhibiting signs of 

tube-to-tube proximity or contact. The staff finds the applicant’s response acceptable because 

the applicant clarified that the manufacturer of its steam generators is different from the 

manufacturer of the steam generators that showed tube-to-tube wear and the applicant’s 
TIME-LIMITED AGING ANALYSES

4-131

inspection results confirm that tube-to-tube wear has not occurred in the steam generators at 

Callaway. In addition, the staff finds that the applicant’s Steam Generators Program adequately 

manages steam generator wear by performing periodic inspections of the tubes; assessment of 

the inspection results; and plugging and repair activities as necessary. Therefore, the staff’s 

concern described in RAI 4.7.9-3 is resolved.

In its review, the staff also noted that industry operating experience indicates that clogging of 

TSP holes may increase steam generator tube wear. In comparison, LRA Section 4.7.9 does 

not clearly indicate if the applicant considered the potential adverse effect of clogging of TSP 

holes in its tube wear calculations. By letter dated August 16, 2012, the staff issued RAI 4.7.9-4 

requesting that the applicant clarify if its TLAA considers the potential adverse effect of clogging 

of TSP holes on steam generator tube wear.

In its response dated September 20, 2012, the applicant stated that the clogging of the holes at 

the TSP is taken into consideration in the tube wear analysis. The applicant also stated that a 

clogged hole results in a reduced damping ratio for the vibratory system, which is a penalizing 

effect in the wear analysis, and the phenomenon is considered even though it is rather unlikely 

to occur. The staff finds the applicant’s response acceptable because the applicant clarified that 

its TLAA considers potential adverse effect of clogging of the TSP holes. The staff’s concern 

described in RAI 4.7.9-4 is resolved.

During the audit, the staff noted that Callaway Action Request (CAR) 200500411 describes the 

failure of a flow meter component due to flow-accelerated corrosion (FAC) as addressed in 

RAI B2.1.7-6, dated July 18, 2012. The staff review of the applicant’s response to RAI B2.1.7-6 

is discussed in SER Section 3.0.3.1.6. The staff also noted that the flow tube, which was 

separated from its venturi throat, migrated down the pipe and blocked the minimum recirculation 

flow line. The failed flow meter addressed in the applicant’s CAR is not a feedwater flow meter. 

However, the staff noted that the applicant’s feedwater venturi flow meter may be subject to 

similar aging degradation (e.g., FAC or corrosion product deposits). Degradation of feedwater 

flow meters may cause flow rate calculation errors or flow correction factor errors, which can 

lead to reactor overpower conditions because of underestimations of feedwater flow rates. In 

turn, reactor overpower conditions can increase steam generator tube wear.

Therefore, the staff needed to clarify if the applicant considered the potential analysis input 

errors associated with flow rate calculations or flow correction factors, which might affect the 

TLAA results. By letter dated August 16, 2012, the staff issued RAI 4.7.9-5 requesting that the 

applicant provide additional information to clarify if its TLAA considers feedwater flow rate 

calculation errors or flow correction factor errors as part of the analysis.

In its response dated September 20, 2012, the applicant stated that its analysis includes a 

2 percent measurement uncertainty. In its review of the applicant’s response, the staff noted 

that the applicant did not clearly address if the 2 percent measurement uncertainty is specifically 

associated with the feedwater flow rate or reactor thermal power. By letter dated 

November 21, 2012, the staff issued RAI 4.7.9-5a requesting the applicant to provide additional 

clarification regarding the 2 percent measurement uncertainty. 

In its response dated December 13, 2012, the applicant stated that each feedwater flow venturi 

is visually inspected and cleaned as necessary at least once per 18 months in accordance with 

FSAR 16.4.9.1.1. The applicant also stated that these inspections have ensured that the 

feedwater flow meters adequately maintain the accuracy of the flow coefficient so that Callaway 

is within the 2 percent measurement uncertainty on the reactor thermal power analysis.
TIME-LIMITED AGING ANALYSES

4-132

The staff finds the applicant’s response acceptable because the applicant clarified that it 

performs periodic visual inspections of the feedwater flow meters to ensure that the plant is 

within the 2 percent measurement uncertainty on the reactor thermal power analysis. The 

staff’s concerns described in RAIs 4.7.9-5 and 4.7.9-5a are resolved.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of loss of material caused by wear on the intended functions of the steam generator 

tubes will be adequately managed by the Steam Generators Program for the period of extended 

operation. As documented in SER Section 3.0.3.1.7, the staff finds that the Steam Generators 

Program is adequate to manage steam generator tube wear because it includes periodic 

inspections of the tubes; assessment of the inspection results; and plugging and repair 

activities. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the 

applicant demonstrated that effects of aging on the intended function(s) of the steam generators 

tube wear will be adequately managed for the period of extended operation.

4.7.9.3 FSAR Supplement

LRA Section A3.6.9 provides the FSAR supplement summarizing the applicant’s TLAA for 

steam generator tube wear. As amended on September 20, 2012, the applicant amended LRA 

Section A3.6.9 to reflect TLAA disposition in accordance with 10 CFR 54.21(c)(1)(iii), using the 

Steam Generators Program for aging management. The applicant also amended the FSAR 

supplement to clarify that the allowable limit for tube wear is 40 percent through-wall thickness. 

The staff reviewed amended LRA Section A3.6.9, consistent with the review procedure in 

SRP-LR Section 4.7.3.2, which states the FSAR summary description is reviewed to verify that 

it is appropriate, such that later changes can be controlled by 10 CFR 50.59. The SRP-LR also 

states that the description should contain information that the TLAAs have been dispositioned 

for the period of extended operation.

Based on its review of the FSAR supplement, as amended by letter dated September 20, 2012, 

the staff finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2 and is, therefore, 

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address steam generator tube wear, as required by 

10 CFR 54.21(d).

4.7.9.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of loss of material 

caused by wear on the intended functions of the steam generator tube will be adequately 

managed by the Steam Generators Program for the period of extended operation. The staff 

also concludes that the FSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.10 Mechanical Environmental Qualification

4.7.10.1 Summary of Technical Information in the Application

LRA Section 4.7.10 was added to the LRA by LRA Amendment 10, submitted by letter dated 

September 20, 2012. The section describes the applicant’s TLAA for the evaluation of EQ of 

mechanical components for the period of extended operation. The LRA states that the 

Mechanical EQ Program establishes qualified lives for safety-related mechanical components 
TIME-LIMITED AGING ANALYSES

4-133

located in harsh environments, in accordance with the requirements of 10 CFR Part 50, 

Appendix A, Criterion 4. The LRA states that as part of the qualification, replacement intervals 

were identified as required either on the basis of component aging under an IEEE 323-1974 

qualification program or based on published material aging data. The LRA also states that the 

EQ of Electrical Components Program manages applicable component thermal, radiation, and 

cyclic aging effects for mechanical EQ components for the current operating license using 

methods for qualification for aging and accident conditions established by 10 CFR 50.49(f). The 

applicant took an exception to the LRA Appendix B, Section B3.2, “Environmental Qualification 

(EQ) of Electric Components” Program that expands the “scope of program” to include 

mechanical EQ components. The LRA further states that this ensures the effects of aging on 

the intended function(s) of equipment included under mechanical EQ will be adequately 

addressed for the period of extended operation. The applicant finally stated that mechanical 

components with qualification extending beyond 40 years are TLAAs and are dispositioned in 

accordance with 10 CFR 54.21(c)(1)(iii). 

LRA Section 4.4 states that re-analysis of an aging evaluation to extend the qualification of 

components (qualified life) is performed on a routine basis as part of the EQ of Electric 

Components Program. The applicant included under this program the important attributes of 

reanalysis including analytical methods, data collection and reduction methods, underlying 

assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met).

The applicant dispositioned the TLAA for mechanical components, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of thermal, radiation, and cyclical aging on the intended 

functions will be adequately managed by the EQ of Electric Components Program for the period 

of extended operation.

4.7.10.2 Staff Evaluation

By letter dated September 20, 2012, as part of its response to RAI 4.4-1, the applicant amended 

its LRA to add LRA Section 4.7.10, “Mechanical Environmental Qualification.” The staff’s 

evaluation of the applicant’s response to RAI 4.4-1 is documented in SER Section 4.4.2. The 

staff reviewed the applicant’s TLAA for the EQ of mechanical components and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in 

SRP-LR Sections 4.4.3.1.3 and 4.7.3.1.3, which state that an applicant must demonstrate the 

effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. The applicant is using its EQ of Electric Components Program to manage 

the effects of aging for mechanical EQ components.

The staff reviewed LRA Sections 4.7.10 and B3.2, plant basis documents, and interviewed plant 

personnel to verify whether the applicant provided adequate information to meet the 

requirement of 10 CFR 54.21(c)(1). For mechanical EQ components, the applicant dispositions 

its TLAA evaluation in accordance with 10 CFR 54.21(c)(1)(iii), that the aging effects of 

mechanical EQ components will be adequately managed by its EQ of Electric Components 

Program during the period of extended operation based on both electrical and mechanical 

components having the same materials, environments, and aging effects. Per the GALL 

Report, a plant EQ of Electric Equipment Program that implements the requirements of 

10 CFR 50.49 is considered an acceptable AMP under license renewal 10 CFR 54.21(c)(1)(iii),

with GALL Report AMP X.E1, “Environmental Qualification (EQ) of Electric Components,” 

providing a means to meet the requirements of 10 CFR 54.21(c)(1)(iii). The staff reviewed the 

applicant’s EQ of Electric Components Program to determine whether it will ensure that the 

mechanical components covered under this program will continue to perform their intended 
TIME-LIMITED AGING ANALYSES

4-134

functions, consistent with the CLB, for the period of extended operation. LRA Section 4.7.10 for 

mechanical EQ is also consistent with the guidance provided in SRP-LR Section 4.4.1, which 

states that a TLAA for mechanical components should be performed under the provision of 

SRP-LR Section 4.7, “Other Plant-Specific Time-Limited Aging Analysis.” 

The staff’s evaluation of the components qualification focused on how the EQ of Electric 

Equipment Program manages the aging effects to meet the requirements, in accordance with 

10 CFR 50.49 and 10 CFR Part 50, Appendix A, Criterion 4, for mechanical EQ components. 

The applicant stated that as part of qualification, replacement intervals were identified for 

mechanical equipment. The applicant also stated that the qualifications of some mechanical 

equipment extends beyond 40 years and are considered TLAAs. Therefore, mechanical 

components qualified for 40 years need to be evaluated to determine the qualified life for the 

period of extended operation. The applicant also stated that design basis conditions will remain 

the same as the current license period and the design basis parameters for temperature, 

radiation and humidity do not require further evaluation for license renewal.

The EQ of Electric Components Program includes an exception to expand the scope to include 

aging management of mechanical EQ components. The staff conducted an audit of the 

information provided in LRA Sections 4.4 and B3.2 and the program basis documents. LRA 

Section B3.2 discusses the component reanalysis attributes, including analytical models, data 

collection and reduction methods, underlying assumptions, acceptance criteria, and corrective 

actions for the program. As described in SER Section 3.0.3.1.19, the staff found that the EQ of 

Electric Equipment Program with the expanded scope for mechanical EQ components 

exception, which the applicant claimed to be consistent with GALL Report AMP X.E1, is 

consistent with the GALL Report. 

The applicant’s mechanical EQ TLAA is implemented per the requirements of 

10 CFR 54.21(c)(1)(iii) and therefore is consistent with SRP-LR Sections 4.7.3.1.3 and 4.4.3.1.3 

and with the applicant’s TLAA for EQ of Electric Components Program. The staff finds that the 

applicant’s mechanical EQ TLAA, in conjunction with the applicant’s EQ of Electric Components 

Program, will adequately manage the aging effects for mechanical EQ components for the 

period of extended operation. The staff’s review of the EQ of Electric Components Program is 

documented in SER Section 3.0.3.1.19.

The staff finds the applicant has demonstrated, in accordance with 10 CFR 54.21(c)(1)(iii), that 

the effects of thermal, radiation, and cyclical aging on the intended functions of mechanical 

EQ components will be adequately managed for the period of extended operation. Additionally, 

the applicant’s mechanical EQ TLAA meets the acceptance criteria in SRP-LR Section 4.7.2.1 

because the applicant’s EQ of Electric Equipment Program is capable of programmatically 

managing the qualified life of mechanical EQ components within the scope of the program for 

license renewal. The continued implementation of the EQ of Electric Equipment Program 

provides assurance that the aging effects will be managed and that components within the 

scope of the EQ of Electric Equipment Program, including mechanical EQ components, will 

continue to perform their intended functions for the period of extended operation.

4.7.10.3 FSAR Supplement

LRA Section A3.6.10, as incorporated by LRA Amendment 10, dated September 20, 2012,

provides the FSAR supplement summarizing the mechanical EQ TLAA. The staff reviewed LRA 

Section A3.6.10, consistent with the review procedures in SRP-LR Section 4.7.3.2, which state 

that the FSAR supplement is reviewed to verify that the applicant has provided information to be 
TIME-LIMITED AGING ANALYSES

4-135

included in the FSAR supplement that includes a summary description of the evaluation of each 

TLAA.

Based on its review of the FSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2 and is, therefore, acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the mechanical 

EQ TLAA for the period of extended operation, as required by 10 CFR 54.21(d).

4.7.10.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of thermal, radiation, 

and cyclical aging on the intended functions of the mechanical components will be adequately 

managed by the mechanical EQ TLAA for the period of extended operation. The staff also 

concludes that the FSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d).

4.8 Conclusion

The staff reviewed the information in LRA Section 4, “Time-Limited Aging Analyses.” On the 

basis of its review, the staff concludes that the applicant provided a sufficient list of TLAAs, as 

defined in 10 CFR 54.3, and that the applicant has demonstrated the following: 

• The TLAAs will remain valid for the period of extended operation, as required by 

10 CFR 54.21(c)(1)(i).

• The TLAAs have been projected to the end of the period of extended operation, as 

required by 10 CFR 54.21(c)(1)(ii).

• 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 FSAR 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. Additionally, any changes made to the CLB to comply with 10 CFR 54.29(a) are in 

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

5-1

SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

The U.S. Nuclear Regulatory Commission (NRC or the staff) issued its safety evaluation report 

(SER) with open items related to the renewal of the operating license for Callaway Plant, Unit 1, 

on April 23, 2013. On May 22, 2014, the applicant presented its license renewal application 

(LRA), and the staff presented its review findings to the Advisory Committee on Reactor 

Safeguards (ACRS) Plant License Renewal Subcommittee. The staff reviewed the applicant’s 

comments on the SER and completed its review of the LRA. The staff’s evaluation is 

documented in an SER that was issued by letter dated August 21, 2014. 

During the 618th meeting of the ACRS held October 2–4, 2014, the ACRS completed its review 

of the Callaway Plant, Unit 1, LRA and the staff’s SER. The ACRS documented its findings in a 

letter to the Commission dated October 14, 2014. 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

October 14, 2014

The Honorable Allison M. Macfarlane

Chairman

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL 

APPLICATION OF THE CALLAWAY PLANT, UNIT 1

Dear Chairman Macfarlane:

During the 618th meeting of the Advisory Committee on Reactor Safeguards (ACRS), October 

2-4, 2014, we completed our review of the license renewal application for Callaway Plant, Unit 1 

(Callaway) and the Final Safety Evaluation Report (SER) prepared by the NRC staff. Our 

subcommittee on Plant License Renewal reviewed this matter during a meeting on May 22, 

2014. During these reviews, we had the benefit of discussions with representatives of the NRC 

staff and Ameren Missouri (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 Ameren Missouri to manage age-related 

degradation provide reasonable assurance that Callaway can be operated in accordance 

with its current licensing basis for the period of extended operation without undue risk to 

the health and safety of the public.

2. The Ameren Missouri application for renewal of the operating license for Callaway 

should be approved.

BACKGROUND

The nuclear steam supply system for Callaway is a pressurized water reactor that was designed 

and supplied by the Westinghouse Electric Corporation. The reactor core is designed for an 

output of 3,565 MWt and the electrical rating is 1,284 MWe. The containment is a carbon steellined, concrete structure. The walls and dome are post-tensioned, prestressed concrete, and 

the base slab is reinforced concrete.
5-3

-2-

Callaway is located 10 miles southeast of the city of Fulton in Callaway County, Missouri, and is 

located 80 miles west of the St. Louis metropolitan area. The nearest population center is 

Jefferson City, Missouri, located 25 miles west-southwest of the site. Callaway is situated on a 

7,354 acre site with the power plant site occupying approximately 2,765 acres. The plant is 

located on a high plateau approximately 300 feet above the Missouri River, and the river is 

located about five miles to the south of the plant. 

The NRC issued Callaway’s construction permit on April 16, 1976, and operating license on 

October 18, 1984. In this application, Ameren Missouri requested renewal of the Callaway 

Operating License No. NPF-30, for a period of 20 years beyond the expiration of the current 

license, which occurs on October 18, 2024.

DISCUSSION 

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 an inspection at the 

plant site. The staff reviewed the completeness of the identification of structures, systems, and 

components (SSCs) that are within the scope of license renewal; the integrated plant 

assessment process; the identification of plausible aging mechanisms associated with passive, 

long-lived components; adequacy of the Aging Management Programs (AMPs); and 

identification and assessment of Time-Limited Aging Analyses (TLAAs) requiring review.

In the Callaway license renewal application, Ameren Missouri identified the SSCs that fall within 

the scope of license renewal. Based on this review, the applicant will implement 42 AMPs for 

license renewal, comprised of 32 existing programs and 10 new programs. Nineteen AMPs are 

consistent with the Generic Aging Lessons Learned (GALL) Report (NUREG-1801, Revision 2), 

without enhancements or exceptions. Twenty three AMPS are consistent with enhancements or 

exceptions. There are no plant-specific AMPs. 

The application either demonstrates consistency with the GALL Report or documents and 

justifies deviations to the specified approaches in that report. The license renewal application 

includes six exceptions to the GALL Report. We reviewed these exceptions (selective leaching, 

inspection of internal surfaces of miscellaneous piping and ducting, buried underground tanks, 

protective coating monitoring and maintenance program, fire water system, and above-ground 

metallic tanks). The applicant subsequently resolved the last of these exceptions. We agree 

with the staff’s conclusions that the remaining five exceptions are acceptable. 

The staff conducted license renewal audits and performed a license renewal inspection at 

Callaway. The audits verified the appropriateness of the scoping and screening methodology 

for AMPs, the aging management review, and the TLAAs. The inspection verified that the 

license renewal requirements are appropriately implemented. Both the inspection and the 

report of that inspection are very thorough. Based on the audits, inspection, and staff reviews 

related to this license renewal application, the staff concluded in the final SER that the proposed 

activities will manage the effects of aging of SSCs identified in the application and that the 

intended functions of these SSCs will be maintained during the period of extended operation. 

We agree with this conclusion.
5-4

-3-

The following open items were resolved prior to our final review on October 2, 2014:

Scoping of Fire Protection SSCs and NFPA 805 Transition

The staff raised questions regarding fire protection SSCs in Callaway’s auxiliary boiler 

room and in various locations in the turbine building. The staff’s concern was that if 

these water systems and components were excluded from the scope of license renewal 

they would not be subject to an aging management review. The staff requested that the 

applicant provide justification for these exclusions. The applicant subsequently 

reexamined these components. That reexamination resulted in either addition of the 

turbine building SSCs to the scope of the aging management review or removal of SSCs 

from the scope, as appropriate.

Ameren Missouri submitted a license amendment request to transition Callaway’s 

existing Fire Protection Program to a risk-informed, performance-based program based 

on National Fire Protection Association Standard NFPA 805. Subsequently, Ameren 

Missouri submitted the license renewal application for renewal of their Operating License 

NPF-30 for Callaway. Ameren Missouri performed a gap analysis that described the 

changes to the license renewal application based on components that were added to or 

removed from the Fire Protection Program as the result of the transition to NFPA 805, 

and updated the license renewal scope to be consistent with NFPA 805.

Reactor Vessel Head Closure Studs

During their review of the license renewal application, the staff determined that on 

multiple occasions several of Callaway’s reactor vessel head closure studs had become 

stuck during either stud insertion or stud removal. The applicant has committed to 

remove the one remaining stuck Stud No. 18 and inspect its stud hole in the lower 

reactor vessel head flange prior to entering the period of extended operation. Stud No. 

18 will be replaced. Threads in six stud holes are damaged. Threads in four other stud 

holes have been repaired. The applicant has committed to inspect the six stud holes 

with thread damage and to inspect the four other stud holes with thread repair prior to 

entering the period of extended operation. 

Materials Reliability Program Issues

Ameren Missouri’s PWR Vessel Internals Program implements the guidance of Materials 

Reliability Program (MRP)-227-A, “PWR Reactor Internals Inspection and Evaluation 

Guideline,” dated January 9, 2012, which includes their plant-specific responses to 

action items, conditions, and limitations identified in the NRC Safety Evaluation for
5-5

-4-

MRP-227, “Materials Reliability Program: Pressurized Water Reactor Internals 

Inspection and Evaluation Guideline (MRP-227, Revision 0).” During the review of 

Callaway’s program and their responses to action items for MRP-227-A, the staff 

identified several issues requiring additional information. The issues were resolved by 

the applicant including an AMP for vessel internals that is consistent with MRP-227-A; 

justifying replacement of a hold down spring with martensitic stainless steel material; and 

providing flaw tolerance analyses, functionality analyses or susceptibility analyses for 

cast austenitic stainless steel used in the reactor vessel internals.

ASME Code Class 1 Small-Bore Socket Weld Population

The staff communicated that the accounting for Callaway’s population of small-bore 

socket welds in ASME Code Class 1 piping less than 4 inches and greater than or equal 

to 1 inch nominal pipe size was initially inaccurate. Subsequent actions and reviews of 

the as-built drawings resulted in an acceptable accounting for all of these small-bore 

socket weld locations.

Effects of the Reactor Coolant System Environment on Fatigue Life of Piping and 

Components

Ameren Missouri performed a systematic review of all wetted reactor coolant pressure 

boundary components with a Class 1 fatigue analysis to either show that the 

NUREG/CR-6260 locations are bounding or to incorporate environmentally assisted 

fatigue into the licensing basis for more limiting components. The staff had concerns 

about the approach taken by the applicant to address the effects of the reactor coolant 

system environment on fatigue life of piping and components. 

The applicant performed a systematic review to determine the “sentinel” locations to be 

monitored by the Fatigue Monitoring Program. This systematic review involved ranking 

and comparisons of environmental fatigue usage. However, in justifying its systematic 

review, the applicant did not initially demonstrate that the values for environmental 

fatigue usage were based on a normalized scale. Thus, the staff's concern was that 

Callaway’s original ranking and comparisons may not have appropriately determined the 

“sentinel” locations. The applicant subsequently provided justification for the screening 

methods used to identify the “sentinel” locations. 

Ameren Missouri identified the systems and components requiring TLAAs and 

reevaluated them for the period of extended operation. The staff concluded that Ameren 

Missouri has provided an adequate list of TLAAs. Further, the staff concluded that the 

applicant has met the requirements of the License Renewal Rule by demonstrating that 

the TLAAs will remain valid for the period of extended operation, or that the TLAAs have 

been projected to the end of the period of extended operation, or that the aging effects 

will be adequately managed for the period of extended operation. The staff has 

concluded that the applicant has demonstrated that the effects of aging at Callaway will 

be adequately managed so that the intended function(s) will be maintained consistent 

with the current licensing basis for the period of extended operation, as required by 10 

CFR 54.21(a)(3). 
5-6

-5-

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 Callaway. None of the 

items described in this letter report precludes approval of this license renewal application. The 

programs established and committed to by Ameren Missouri provide reasonable assurance that 

Callaway can be operated in accordance with its current licensing basis for the period of 

extended operation without undue risk to the health and safety of the public. The Ameren 

Missouri application for renewal of the operating license for Callaway should be approved.

Dr. Peter Riccardella did not participate in the Committee’s deliberations regarding this matter.

Sincerely,

/RA/

John W. Stetkar

Chairman

REFERENCES

1. Safety Evaluation Report Related to the License Renewal of Callaway Plant, Unit 1, 

dated August 2014 (ML14232A380).

2. NRR Memorandum from John Lubinski to Edwin Hackett, dated May 12, 2014, Subject: 

Review of the Callaway Nuclear Plant License Renewal Application - Safety Evaluation 

Report (ML14121A106).

3. Safety Evaluation Report With Open Items Related to the License Renewal of Callaway 

Plant, Unit 1, dated April 2013 (ML13086A224).

4. Letter from McLachlan, M., Ameren Missouri: Enclosure 2 - Amendment 26, LRA

Changes, dated August 29, 2013 (ML13242A291).

5. Callaway Plant Unit 1, License Renewal Application 2012 Annual Update, Amendment 

18, dated December 19, 2012 (ML123560157).

6. NRC Inspection Report 05000483/2012009, dated November 20, 2012 (ML12328A053).

7. NRC Aging Management Programs Audit Report, dated August 9, 2012 

(ML12180A023).

8. NRC Scoping and Screening Audit Report, dated August 6, 2012 (ML12178A475).

9. PWR Reactor Internals Inspection and Evaluation Guidelines, dated January 9, 2012 

(ML12017A193).

10. Letter from Ameren Missouri to NRC, Submitting Callaway Plant Unit 1, License

Renewal Application, dated December 15, 2011 (ML113530367).
5-7

-6-

11. Callaway Plant, Unit 1, License Renewal Application, dated December 15, 2011 

(ML113530372).

12. NRC NUREG-1800, Revision 2, “Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants” (SRP-LR), dated December 2010 

(ML103409036).

13. NRC NUREG 1801, Revision 2, “Generic Aging Lessons Learned (GALL) Report,” dated 

December 2010 (ML103409041).

14. NRC Regulatory Guide 1.188, Revision 1, “Standard Format and Content for 

Applications to Renew Nuclear Power Plant Operating Licenses,” dated September 2005 

(ML082950585).

15. National Fire Protection Association Standard (NFPA) 805, “Performance-Based 

Standard for Fire Protection for Light Water Reactor Electric Generating Plants,” 2001 

Edition.

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

Nuclear Power Plant Components,” dated February 28, 1995 (ML031480219).

6-1

SECTION 6

CONCLUSION

The staff of the United States (U.S.) Nuclear Regulatory Commission (NRC) (the staff) reviewed 

the license renewal application (LRA) for Callaway Plant, Unit 1, in accordance with NRC 

regulations and NUREG-1800, Revision 2, “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants,” dated December 2010. Title 10 of the Code of 

Federal Regulations (10 CFR) 54.29, “Standards for Issuance of a Renewed License,” sets the 

standards used for issuing a renewed license.

On the basis of its review of the LRA, the staff determines that the requirements of 

10 CFR 54.29(a) have been met.

The staff noted that any issues pertaining to 10 CFR Part 51, “Environmental Protection 

Regulations for Domestic Licensing and Related Regulatory Functions," Subpart A, “National 

Environmental Policy Act—Regulations Implementing Section 102(2),” will be documented in 

NUREG-1437, plant-specific supplement 51, “Generic Environmental Impact Statement for 

License Renewal of Nuclear Plants, Supplement 51, Regarding Callaway Plant, Unit 1.”

A-1

APPENDIX A

CALLAWAY PLANT UNIT 1 LICENSE RENEWAL COMMITMENTS

During the review of the Callaway Plant Unit 1 (Callaway) license renewal application (LRA) by 

the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff), Union Electric 

Company, doing business as Ameren Missouri (the applicant), made commitments related to 

aging management programs (AMPs) to manage aging effects of structures and components. 

LRA Section A0, “Appendix A Introduction,” states that Appendix A “[as revised by supplements 

and RAI responses] provides the information to be submitted in a Supplement to the Final 

Safety Analysis Report (FSAR) Update as required by 10 CFR 54.21(d) for the Callaway Plant 

License Renewal Application.” It also states “...Section A4 contains summary descriptions of 

license renewal commitments. These summary descriptions [...] and license renewal 

commitments will be incorporated in the Callaway Plant FSAR Update following issuance of the 

renewed operating license in accordance with 10 CFR 50.71(e).” The following table lists these 

commitments, as well as the implementation schedules and the sources for each commitment.
APPENDIX A

A-2

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

1 Procedures will be enhanced to apply the 

elements of corrective actions, confirmation 

process, and administrative controls of the 

Callaway Plant Quality Assurance Program to 

those nonsafety-related structures, systems, 

and components (SSCs) requiring aging 

management. 

(Completed LRA Amendment 23 dated 

April 26, 2013)

B1.3 Completed Letter 

ULNRC-05963 

dated 

February 28, 

2013

Letter

ULNRC-05979 

dated April 26, 

2013

2 Enhance the station operating experience 

review process and Corrective Action Program 

(CAP) to perform reviews of plant-specific and 

industry operating experience to confirm the 

effectiveness of the license renewal aging 

management programs (AMPs), to determine 

the need for AMPs to be enhanced, or indicate 

the need to develop a new AMP.

In order to provide additional assurance that 

internal and external operating experience 

related to aging management continues to be 

used effectively in the AMPs, Callaway will 

enhance its operating experience program to:

• Explicitly require the review of operating 

experience for age-related degradation. 

(Completed LRA Amendment 18 dated 

December 19, 2012)

• Establish criteria to define age-related 

degradation. In general, the criteria will be 

used to identify aging that is considered 

excessive relative to design, previous 

inspection experience, and inspection 

intervals. (Completed LRA Amendment 18 

dated December 19, 2012)

• Establish coding for use in identification, 

trending and communications of age-related 

degradation. This coding will assist plant 

personnel in ensuring that, in addition to 

addressing the specific issue, the adequacy 

of existing aging management programs is 

assessed. This could lead to AMP revisions 

or the establishment of new AMPs, as 

appropriate. (Completed LRA Amendment 

18 dated December 19, 2012)

• Require communication of significant 

internal age-related degradation, associated 

with SSCs in the scope of license renewal, 

to the industry. Criteria will be established 

for determining when aging-related 

degradation is significant. (Completed LRA 

Amendment 18 dated December 19, 2012)

B1.4 Completed Letter 

ULNRC-05939 

dated 

December 19, 

2012

Letter 

ULNRC-05957 

dated 

February 14, 

2013

Letter

ULNRC-05979 

dated April 26, 

2013
APPENDIX A

A-3

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

• Require review of external operating 

experience for information related to aging 

management, and evaluation of such 

information for potential improvements to 

Callaway aging management activities. 

License Renewal Interim Staff Guidance 

(LR-ISG) documents will be reviewed as 

part of this external operating experience 

information as they are issued on an 

ongoing basis, capturing new insights or 

addressing issues that emerge from license 

renewal reviews. (Completed LRA 

Amendment 21 dated February 14, 2013)

• Provide training to those responsible for 

screening, evaluating and communicating 

operating experience items related to 

aging-related degradation. This training will 

be commensurate with their role in the 

process. (Completed LRA Amendment 23 

dated April 26, 2013)

• Explicitly require AMP activities, criteria, and 

evaluations integral to the elements of the 

AMPs be included in the operating 

experience evaluation. (Completed LRA 

Amendment 21 dated February 14, 2013)

3 Enhance the Boric Acid Corrosion Program 

procedures to: include steel, copper alloy 

greater than 15% zinc, and aluminum as 

materials that are susceptible to boric acid 

corrosion. (Completed LRA Amendment 13 

dated October 24, 2012)

• Ensure that system engineers will observe 

for signs of boric acid residue when 

performing system walkdowns. (Completed 

LRA Amendment 13 dated 

October 24, 2012)

• Specify that the corrective actions taken by 

the program will include a consideration to 

modify the present design or operating 

procedures to mitigate or prevent recurrence 

of aging effects caused by borated water 

leakage. Consideration will be given to 

modifications that (a) reduce the probability 

of primary coolant leaks at locations where 

they may cause corrosion damage and (b) 

entail the use of suitable corrosion resistant 

materials or the application of protective 

coatings or claddings. (Completed LRA 

Amendment 13 dated October 24, 2012)

B2.1.4 Completed Letter 

ULNRC-05920 

dated 

October 24, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-4

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

4 Implement the PWR Vessel Internals Program 

as described in LRA Section B2.1.6. As part of 

the implementation activities address the 

following Applicant/Licensee Action Items 

(A/LAI) of NRC MRP-227-A Safety Evaluation 

dated December 16, 2011. (Completed LRA 

Amendment 28 dated December 20, 2013)

Applicant/Licensee Action Item (A/LAI) #1

Each applicant or licensee is responsible for 

assessing its plant’s design and operating 

history and demonstrating that the approved 

version of Materials Reliability Program 

(MRP)-227 is applicable to the facility. Each 

applicant or licensee shall refer, in particular, 

to the assumptions regarding plant design 

and operating history made in the failure 

modes, effects, and criticality analysis and 

functionality analyses for reactors of their 

design (i.e., Westinghouse, Combustion 

Engineering, or Babcock and Wilcox) which 

support MRP-227 and describe the process 

used for determining plant-specific 

differences in the design of their reactor 

vessel internals (RVI) components or plant 

operating conditions, which result in different 

component inspection categories. The 

applicant or licensee shall submit this 

evaluation for NRC review and approval as 

part of its application to implement the 

approved version of MRP-227. (Completed 

LRA Amendment 28 dated 

December 20, 2013)

B2.1.6 Completed LRA

Letter 

ULNRC-05950 

dated 

January 24, 2013

Letter

ULNRC-06050 

dated 

October 17, 2013

Letter

ULNRC-06057 

dated 

December 20, 

2013

Letter 

ULNRC-06080 

dated February 

14, 2014

Letter 

ULNRC-06106

dated 

March 28, 2014
APPENDIX A

A-5

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

5 Enhance the Bolting Integrity Program 

procedures to:

• Reference NUREG-1339, “Resolution of 

Generic Safety Issue 29: Bolting 

Degradation of Failure in Nuclear Power 

Plants,” and Electric Power Research 

Institute (EPRI) NP-5769 to meet the GALL 

Report recommendations. (Completed LRA 

Amendment 1 dated April 25, 2012)

• Include bolting in the list of items to be 

inspected during walkdowns. 

(Completed LRA Amendment 15 dated 

November 8, 2012)

• Include a visual inspection of a sample of 

submerged bolting heads in raw water and 

waste water environments every four 

refueling outages (6 years) when the pumps 

are dewatered. In addition, when 

submerged raw water and waste water 

pump casings are disassembled during 

maintenance activities, the bolting threads 

will be opportunistically inspected. A 

sample of submerged bolting on the fuel oil 

storage tank transfer pumps will be visually 

inspected every 10 years when the pumps 

are disassembled during maintenance 

activities. The sample for submerged 

bolting will be 20% of the population with a 

maximum of 25 for each environment. The 

inspection of submerged bolting will focus 

on the bounding or lead components most 

susceptible to aging due to time in service 

and severity of operating conditions.

B2.1.8 Portions completed 

are as shown. 

Remaining portions 

to be implemented 

as follows:

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections and 

testing to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later. 

Letter 

ULNRC-05856 

dated 

April 25, 2012 

Letter 

ULNRC-05928 

dated 

November 8, 

2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013

Letter

ULNRC-06121 

dated 

June 5, 2014 

6 Enhance the Open-Cycle Cooling Water System 

Program procedures to:

• Include polymeric material inspection 

requirements, parameters monitored, and 

acceptance criteria. Examination of 

polymeric materials by the Open-Cycle 

Cooling Water System Program will be 

consistent with examinations described in 

the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting 

Components Program.

• Include inspection and cleaning, if 

necessary, of the air-side of safety-related 

air-to-water heat exchangers cooled by the 

essential service water (ESW) system.

• Prior to the period of extended operation, an 

inspection technique will be selected from 

available technologies to identify internal 

pipe wall degradation due to MIC for 

performance of a one-time inspection of a 

B2.1.10 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections and 

testing to be 

completed no later 

than 6 months prior 

to the period of 

extended operation

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05892 

dated 

August 21, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013

Letter 

ULNRC-06057

dated 

December 20, 

2013

Letter 

ULNRC-06117

dated April 23, 

2014
APPENDIX A

A-6

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

buried carbon steel piping segment that is 

representative of other accessible carbon 

steel ESW piping segments.

• Procedures will be enhanced to perform 

periodic visual inspections on all accessible 

internal surface coatings of the component 

cooling water heat exchangers, Class IE 

electrical equipment air conditioners, control 

room air conditioners, and essential service 

water self-cleaning strainers. Baseline 

inspections will be conducted in the 10-year 

period prior to the period of extended 

operation on the accessible internal 

surfaces coatings of the in-scope 

components. Coatings are inspected every 

6 years on an alternating train basis based 

on no observed degradation or cracking and 

flaking that has been evaluated as 

acceptable; and the component is not 

subject to turbulent flow. Baseline 

inspections may be used to demonstrate 

that long-term coatings are or are not 

subject to turbulent flow conditions that 

could result in mechanical damage to the 

coating. Coatings with blisters, peeling, 

delaminations, or rusting that has been 

determined not to require remediation are 

inspected on a 4-year frequency. For 

peeling, delaminations, and blisters 

determined to not meet the acceptance 

criteria and that will not be repaired or 

replaced, physical testing is performed 

where physically possible (i.e., sufficient 

room to conduct testing). Testing consists 

of destructive or nondestructive adhesion 

testing using ASTM International Standards 

endorsed in RG 1.54, “Service Level I, II, 

and III Protective Coatings Applied to 

Nuclear Plants.” Monitoring and trending of 

coatings is based on a review of the 

previous two inspections’ results (including 

repairs) with the current inspection results. 

The training and qualification of individuals 

involved in coating inspections are 

conducted in accordance with ASTM 

International Standards endorsed in RG 

1.54 including guidance from the staff 

associated with a particular standard.

Coating acceptance criteria are as follows:

• Indications of peeling and 

delamination are not acceptable and 

the coatings are repaired or replaced. 

Letter 

ULNRC-06121

dated June 5, 

2014
APPENDIX A

A-7

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

Blisters are evaluated by a coatings specialist 

qualified in accordance with an ASTM 

International standard endorsed in RG 1.54 

including staff guidance associated with use of 

a particular standard.

• Indications such as cracking, flaking, 

and rusting are to be evaluated by a 

coatings specialist qualified in 

accordance with an ASTM 

International standard endorsed in 

RG 1.54 including staff guidance 

associated with use of a particular 

standard.

• Adhesion testing results meet or 

exceed the degree of adhesion 

recommended in engineering 

documents specific to the coating and 

substrate.

Inspection results not meeting the acceptance 

criteria will be evaluated by a qualified 

coatings evaluator. Corrective actions will be 

determined using the Corrective Action 

Program.

7 Enhance the Closed Treated Water Systems 

Program procedures to:

• Include visual inspections of the surfaces of 

components with a closed treated water 

systems water environment. 

Representative samples of each 

combination of material and water treatment 

program will be visually inspected at least 

every 10 years or opportunistically when 

consistent with sample requirements. 

Sample locations will be selected based on 

the likelihood of corrosion and cracking. 

Inspections will be conducted and evaluated 

consistent with ASME Code inspections, 

industry standards, or a plant-specific 

inspection procedure by personnel qualified 

to detect aging. If adverse conditions are 

found, additional examinations will be 

performed. This periodic inspection will 

determine the extent of cracking, loss of 

material and fouling, and serves as a 

leading indicator of the condition of the 

interior of piping components otherwise 

inaccessible for visual inspection.

B2.1.11 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05886 

dated 

August 6, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-8

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

8 Enhance the Inspection of Overhead Heavy 

Load and Light Load (Related to Refueling) 

Handling Systems Program procedures to:

• Inspect crane structural members for loss of 

material due to corrosion and rail wear, and 

loss of preload due to loose or missing bolts 

and nuts.

• Include performance of periodic inspections 

as defined in the appropriate ASME B30 

series standard for all cranes, hoists, and 

equipment handling systems within the 

scope of license renewal. For handling 

systems that are infrequently in service, 

such as those only used during refueling 

outages, periodic inspections may be 

deferred until just prior to use.

• Require evaluation of loss of material due to 

wear or corrosion and loss of bolting 

preload per the appropriate ASME B30 

series standard.

• Require repairs to cranes, hoists, and 

equipment handling systems per the 

appropriate ASME B30 series standard.

B2.1.12 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

9 Enhance the Fire Protection Program 

procedures to:

• Include visual inspections of the external 

surfaces of halon fire suppression system 

components for excessive loss of material 

due to corrosion. (Completed LRA 

Amendment 28 dated December 20, 2013)

• Include trending of the performance of the 

halon system during testing. (Completed 

LRA Amendment 1 dated April 25, 2012)

B2.1.13 Completed Letter 

ULNRC-05856 

dated 

April 25, 2012

Letter 

ULNRC-06057 

dated 

December 20, 

2013

10 Recoat the internal surface of fire water storage 

tanks.

Enhance the Fire Water System Program 

procedures to:

• Perform internal inspections on accessible 

exposed portions of fire water piping during 

plant maintenance activities. When visual 

inspections are used to detect loss of 

material, the inspection technique is 

capable of detecting surface irregularities 

that could indicate wall loss to below 

nominal pipe wall thickness due to corrosion 

and corrosion product deposition. Where 

such irregularities are detected, followup 

volumetric wall thickness examinations are 

performed.

• Replace sprinkler heads prior to 50 years in 

service, or have a recognized testing 

B2.1.14 Implementation is 

started 5 years 

before the period of 

extended operation. 

Recoat the internal 

surface of the fire 

water storage tanks 

and inspections of 

wetted segments 

that cannot be 

drained or that allow 

water to collect to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

Letter 

ULNRC-05923 

dated 

October 31,2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013

Letter 

ULNRC-06057 

dated 

December 20, 

2013
APPENDIX A

A-9

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

laboratory field-service test a representative 

sample in accordance with National Fire 

Protection Association (NFPA) 25 and test 

additional samples every 10 years 

thereafter to ensure signs of aging are 

detected in a timely manner.

• Review and evaluate trends in flow 

parameters recorded during the NFPA 25 

fire water flow tests.

• Perform annual hydrant flow testing in 

accordance with NFPA 25.

• Perform annual hydrostatic testing of fire 

brigade hose.

• Enhance the Fire Water System 

program to include nonintrusive pipe 

wall thickness examinations. Wall 

thickness measurements will be 

performed on fire water piping every 

3 years. Each 3-year sample will 

include at least three locations for a total 

of 100 feet of aboveground fire water 

piping and will be selected based on 

system susceptibility to corrosion or 

fouling and evidence of performance 

degradation during system flow testing 

or periodic flushes. Pipe wall thickness 

examinations and internal inspections 

will be performed commencing after 

2014 and throughout the period of 

extended operation.

• Perform augmented tests and 

inspections of water-based fire 

protection system components that have 

been wetted but are normally dry. The 

augmented tests and inspections are 

conducted as follows on piping 

segments that cannot be drained or that 

allow water to collect:

• In each 5-year interval, 

beginning 5 years prior to the 

period of extended operation, 

either conduct a flow test or 

flush sufficient to detect 

potential flow blockage, or 

conduct a visual inspection of 

100% of the internal surface 

of piping segments that 

cannot be drained or allow 

water to collect. 

• A 100% baseline inspection 

will be performed prior to the 

period of extended operation. 

In each 5-year interval of the 

period of extended operation, 

20% of the length of piping 

whichever occurs 

later.

The program’s 

remaining 

inspections begin 

during the period of 

extended operation.

Letter 

ULNRC-05897 

dated August 16, 

2012

Letter 

ULNRC-06117 

dated April 23, 

2014

Letter 

ULNRC-06118 

dated May 6, 

2014

Letter 

ULNRC-06129 

dated July 31, 

2014
APPENDIX A

A-10

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

segments that cannot be 

drained or that allow water to 

collect is subject to volumetric 

wall thickness inspections. 

Measurement points will be 

obtained to the extent that 

each potential degraded 

condition can be identified 

(e.g., general corrosion, MIC). 

The 20% of piping that is 

inspected in each 5-year 

interval will be in different 

locations than previously 

inspected piping.

If the results of a 100% internal visual 

inspection are acceptable, and the 

segment is not subsequently wetted, no 

further augmented tests or inspections 

will be performed.

• Require the inspection of the interior of 

the fire water storage tanks to include 

checking for evidence of voids beneath 

the floor. (Completed LRA 

Amendment 38, July 31, 2014)

• Change the frequency of trip testing 

each deluge valve from every 3 years to 

every refueling outage.

• Change the frequency of tests of 

spray/sprinkler nozzle discharge 

patterns from every 3 years to every 

refueling outage.

• Perform the following additional 

inspections if pitting, corrosion, or 

coating failure is found during the 

inspection of the fire water storage 

tanks: (1) tank coatings are evaluated 

using an adhesion test consistent with 

ASTM D 3359, Standard Test Methods 

for Measuring Adhesion by Tape Test; 

(2) dry film thickness measurements are 

taken at random locations to determine 

the overall coating thickness; 

(3) nondestructive ultrasonic readings 

are taken to evaluate the wall thickness 

where there is evidence of pitting or 

corrosion; (4) interior surfaces are spot 

wet-sponge tested to detect pinholes, 

cracks, or other compromises in the 

coating; (5) tank bottoms are tested for 

metal loss on the underside by use of 

ultrasonic testing where there is 

evidence of pitting or corrosion; (6) 

bottom seams are vacuum-box tested in 

accordance with NFPA 22, Standard for 

Water Tanks for Private Fire Protection.

• Require the removal of foreign material 
APPENDIX A

A-11

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

if its presence is found during pipe 

inspections to obstruct pipe or 

sprinklers. In addition, the source of the 

material is determined and corrected.

• Perform main drain tests consistent with 

NFPA 25, Section 13.2.5, of a 

representative sample of 20% of the 

main drains within the scope of license 

renewal annually in order to check for 

potential flow blockage in system risers. 

During annual testing, one of the tests is 

performed in a radiologically controlled 

area. 

• Inspect wet pipe suppression systems 

every 5 years consistent with NFPA 25, 

Section 14.2. For buildings containing 

multiple systems, half are inspected in 

the first 5-year interval and the 

remaining half inspected in the next 

5-year interval. If sufficient foreign 

material is found in any system in a 

building, then all systems in the building 

will be inspected. The NFPA 25, 

Section 14.2, inspection of dry pipe 

preaction systems will be performed 

following actuation, prior to return to 

service. If sufficient foreign material is 

found to obstruct pipe or sprinklers, then 

an obstruction investigation is 

conducted per NFPA 25 Annex D. If the 

visual inspection detects surface 

irregularities that could indicate wall loss 

below nominal pipe wall thickness, then 

followup volumetric examinations will be 

performed.

• Revise the implementation procedure 

and calculation for changing test and 

inspection frequencies associated with 

the NFPA 805 license amendment 

(Amendment 206) to note the following 

restrictions when changing license 

renewal Fire Water System program 

and Fire Protection program test and 

inspection frequencies.

• EPRI Report 1006756, Fire 

Protection Equipment 

Surveillance Optimization and 

Maintenance Guide will be 

used to adjust test and 

inspection frequencies.

• Data to be used in analyzing 

the potential for modifying test 

and inspection frequencies 

would not be obtained any 

earlier than 5 years prior to 

the period of extended 

operation.
APPENDIX A

A-12

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

• A minimum sample size 

consistent with EPRI Report 

1006756 Section 11.2 will be 

used to modify test and 

inspection frequencies.

• EPRI Report 1006756 would not be used to 

modify fire water storage tank 

inspections/tests, underground flow tests, 

and inspections of normally dry but 

periodically wetted piping that will not drain 

due to its configuration.

11 Implement the Aboveground Metallic Tanks 

Program as described in LRA Section B2.1.15.

B2.1.15 Implementation 

started within the 

5-year period prior to 

the period of 

extended operation. 

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05923 

dated 

October 31, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013

12 Remove the blisters in the coating, inspect the 

base metal for aging, and repair the coating in 

the train A emergency diesel generator fuel oil 

storage tank.

Enhance the Fuel Oil Chemistry Program 

procedures to:

• Include periodic draining of the water from 

the bottom of the emergency fuel oil system 

day tanks, diesel fire pump fuel oil day 

tanks, and security diesel generator fuel oil 

day tank.

• Include the addition of biocide to the diesel 

fire pump fuel oil day tank and security 

diesel generator fuel oil day tank if periodic 

testing indicates biological activity or 

evidence of corrosion.

• Include draining, cleaning, and inspection of 

the emergency fuel oil system day tanks 

within the 10-year period prior to the period 

of extended operation and at least once 

every 10 years after entering the period of 

extended operation.

B2.1.16 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections and 

referenced coating 

repairs to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05923 

dated 

October 31, 2012

Letter 

ULNRC-05950 

dated 

January 24, 2013

Letter 

ULNRC-05963 

dated 

February 28, 

2013

Letter 

ULNRC-06117 

dated April 23, 

2014
APPENDIX A

A-13

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

• Include a determination of water and 

sediment in the periodic sampling of the 

emergency fuel oil system day tanks and 

security diesel generator fuel oil day tank.

• Include a determination of particulate 

concentrations in the periodic sampling of 

the emergency fuel oil system day tanks, 

diesel fire pump fuel oil day tanks, and 

security diesel generator fuel oil day tank.

• Include a determination of microbial activity 

concentrations in the periodic sampling of 

the emergency fuel oil system storage 

tanks, emergency fuel oil system day tanks, 

diesel fire pump fuel oil day tanks, and 

security diesel generator fuel oil day tank.

• Include new fuel oil receipt sampling for 

water and sediment prior to introduction into 

the security diesel generator fuel oil day 

tank and diesel fire pump fuel oil day tank.

• Perform a volumetric examination of the 

emergency fuel oil system storage tanks 

and day tanks after evidence of tank 

degradation is observed during the visual 

inspection within the 10-year period prior to 

the period of extended operation and at 

least once every 10 years after entering the 

period of extended operation.

• Perform a volumetric examination on the 

external surface of the diesel fire pump fuel 

oil day tanks and security diesel generator 

fuel oil day tank within the 10-year period 

prior to the period of extended operation 

and at least once every 10 years after 

entering the period of extended operation.

• Include at least quarterly trending for water, 

biological activity, and particulate 

concentrations on the emergency fuel oil 

system day tanks, diesel fire pump fuel oil 

day tanks, and security diesel generator fuel 

oil day tank.

• Include immediate removal of accumulated 

water when discovered in the emergency 

fuel oil system day tank, diesel fire pump 

fuel oil day tank, and security diesel 

generator fuel oil day tank.

• Perform periodic visual inspections on all 

accessible internal surface coatings of the 

emergency fuel oil storage tanks and day 

tanks. Baseline inspections will be 

conducted in the 10-year period prior to the 

period of extended operation on the 
APPENDIX A

A-14

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

accessible internal surfaces coatings of the 

in-scope components. Coatings are 

inspected every 6 years on an alternating 

train basis based on no observed 

degradation or cracking and flaking that has 

been evaluated as acceptable. Coatings 

with blisters, peeling, delaminations, or 

rusting that has been determined not to 

require remediation are inspected on a 

4-year frequency. For peeling, 

delaminations and blisters determined to not 

meet the acceptance criteria and that will 

not be repaired or replaced, physical testing 

is performed where physically possible (i.e., 

sufficient room to conduct testing). Testing 

consists of destructive or nondestructive 

adhesion testing using ASTM International 

Standards endorsed in RG 1.54, “Service 

Level I, II, and III Protective Coatings 

Applied to Nuclear Plants.” Monitoring and 

trending of coatings is based on a review of 

the previous two inspections’ results 

(including repairs) with the current 

inspection results. The training and 

qualification of individuals involved in 

coating inspections are conducted in 

accordance with ASTM International 

Standards endorsed in RG 1.54 including 

guidance from the staff associated with a 

particular standard.

Coating acceptance criteria are as follows:

• Indications of peeling and 

delamination are not acceptable and 

the coatings are repaired or replaced. 

• Blisters are evaluated by a coatings 

specialist qualified in accordance with 

an ASTM International standard 

endorsed in RG 1.54 including staff 

guidance associated with use of a 

particular standard. 

• Indications such as cracking, flaking, 

and rusting are to be evaluated by a 

coatings specialist qualified in 

accordance with an ASTM 

International standard endorsed in RG 

1.54 including staff guidance 

associated with use of a particular 

standard. 

• Adhesion testing results meet or 

exceed the degree of adhesion 

recommended in engineering 

documents specific to the coating and 

substrate. 
APPENDIX A

A-15

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

Inspection results not meeting the acceptance 

criteria will be evaluated by a qualified 

coatings evaluator. Corrective actions will be 

determined using the Corrective Action 

Program.

13 Enhance the Reactor Vessel Surveillance 

Program to:

• Determine the vessel fluence by ex-vessel 

dosimetry, following withdrawal of the final 

capsule. (Completed LRA Amendment 28 

dated December 20, 2013) 

• Require that pulled and tested surveillance 

capsules are placed in storage for future 

reconstitution or reinsertion unless given 

NRC approval to discard. (Completed LRA 

Amendment 28 dated December 20, 2013) 

• Specifically require the design change 

process to evaluate the impact of plant 

operation changes on reactor vessel 

embrittlement. (Completed LRA 

Amendment 14 dated October 31, 2012)

B2.1.17

4.2

Completed Letter 

ULNRC-05923 

dated 

October 31, 2012

Letter 

ULNRC-06057 

dated 

December 20, 

2013

14 Implement the One-Time Inspection Program as 

described in LRA Section B2.1.18.

B2.1.18 Implementation 

started within the 

10-year period prior 

to the period of 

extended operation. 

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-16

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

15 Implement the Selective Leaching Program as 

described in LRA Section B2.1.19.

B2.1.19 Implementation 

started within the 

5-year period prior to 

the period of 

extended operation. 

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

16 Implement the One-Time Inspection of ASME 

Code Class 1 Small-Bore Piping Program as 

described in LRA Section B2.1.20.

B2.1.20 Implementation 

started within the 

6-year period prior to 

the period of 

extended operation. 

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

17 Implement the External Surfaces Monitoring of 

Mechanical Components Program as described 

in LRA Section B2.1.21.

B2.1.21 Implemented no 

later than 6 months 

prior to the period of 

extended operation 

and inspections to 

begin during the 

period of extended 

operation.

Letter 

ULNRC-06057 

dated 

December 20, 

2013
APPENDIX A

A-17

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

18 Implement the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components 

Program as described in LRA Section B2.1.23.

B2.1.23 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

19 Enhance the Lubricating Oil Program 

procedures to:

• Indicate that lubricating oil contaminants are 

maintained within acceptable limits, thereby 

preserving an environment that is not 

conducive to loss of material or reduction of 

heat transfer. (Completed LRA 

Amendment 34 dated April 23, 2014)

• State the testing standards for water content 

and particle count. (Completed LRA 

Amendment 34 dated April 23, 2014)

• State that phase separated water in any 

amount is not acceptable. (Completed LRA 

Amendment 34 dated April 23, 2014)

B2.1.24 Completed Letter 

ULNRC-06117 

dated 

April 23, 2014

20 Implement the Buried and Underground Piping 

and Tanks Program as described in LRA 

Section B2.1.25.

B2.1.25 Implementation to be 

started within the 

10-year period prior 

to the period of 

extended operation. 

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-18

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

21 Enhance the ASME Section XI, Subsection IWE 

Program to:

• Specify that whenever replacement of 

bolting is required, bolting material, 

installation torque or tension, and use of 

lubricants and sealants are in accordance 

with the guidelines of EPRI NP 5769, 

EPRI TR 104213, and the additional 

recommendations of NUREG-1339.

• Perform additional surface examinations of 

stainless steel penetration sleeves, 

dissimilar metal welds, bellows, and steel 

components that are subject to cyclic 

loading for cracking, unless Appendix J 

testing is adequate to identify cracking.

B2.1.26 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections and 

testing to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

22 Enhance the ASME Section XI, Subsection IWF 

Program procedures to:

• Specify that whenever replacement of 

bolting is required, bolting material, 

installation torque or tension, and use of 

lubricants and sealants are in accordance 

with the applicable EPRI guidelines, ASTM 

standards, American Institute of Steel 

Construction specifications, and NUREG 

recommendations to prevent or mitigate 

degradation and failure of safety-related 

bolting due to stress corrosion cracking 

(SCC). Specifically, if ASTM A325, 

ASTM F1852, and/or ASTM A490 bolts are 

used, the preventive actions as discussed in 

Section 2 of the Research Council for 

Structural Connections, Specification for 

Structural Joints Using ASTM A325 or A490 

Bolts, will be followed.

B2.1.28 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Letter 

ULNRC-05891 

dated 

August 9, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013

23 Enhance the Structures Monitoring Program 

procedures to:

• Include the main access facility, the nitrogen 

storage tank foundation and pipe trench, 

and the reinforced concrete structures 

under the turbine building and in the yard 

that provide a return flowpath for the 

circulating water system in the scope of the 

Structures Monitoring Program.

• Specify that whenever replacement of 

bolting is required, bolting material, 

installation torque or tension, and use of 

lubricants and sealants are in accordance

with the guidelines of EPRI NP-5769,

EPRI NP-5067, EPRI TR-104213, and the 

additional recommendations of 

NUREG-1339.

• Specify the preventive actions for storage, 

lubricants, and SCC potential discussed in 

B2.1.31 Completed no later 

than 6 months prior 

to the period of 

extended operation 

with the exception of 

item indicated by *, 

which will be 

completed by 

December 31, 2017, 

and item indicated 

by #, for which initial 

inspections were 

completed by 

December 31, 2012, 

and any corrective 

actions resulting 

from initial 

inspections will be 

completed no later 

than 

December 31, 2017. 

Letter 

ULNRC-05891 

dated 

August 9, 2012

Letter 

ULNRC-05915 

dated 

October 11, 2012

Letter 

ULNRC-05950 

dated 

January 24, 2013

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-19

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

Section 2 of the Research Council for 

Structural Connections publication, 

Specification for Structural Joints Using 

ASTM A325 or A490 Bolts, for ASTM A325, 

ASTM F1852, and/or ASTM A490 structural 

bolts.

• Specify inspections of penetrations, 

transmission towers, electrical conduits, 

raceways, cable trays, electrical cabinets or 

enclosures, and associated anchorages, 

and complete a baseline inspection of these 

components.*

• Specify that groundwater is monitored for 

pH, chlorides, and sulfates, and every 

5 years at least two samples are tested and 

the results are evaluated by engineering to 

assess the impact, if any, on below grade 

structures.

• Specify inspector qualifications in 

accordance with American Concrete 

Institute (ACI) 349.3R-96. 

• Quantify acceptance criteria and critical 

parameters for monitoring degradation, and 

to provide guidance for identifying 

unacceptable conditions requiring further 

technical evaluation or corrective action in 

accordance with the three-tier quantitative 

evaluation criteria recommended in 

ACI 349.3R.

• Incorporate applicable industry codes, 

standards and guidelines for acceptance 

criteria.

• Specify that degradation associated with 

seismic isolation gaps, obstructions of these 

gaps, or questionable material in these 

gaps, will be evaluated by an engineer 

familiar with the seismic design of the plant, 

and the evaluation will consider the seismic 

isolation function in determining what 

corrective actions may be required.#

Inspections and 

testing to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-06118 

dated 

May 6, 2014
APPENDIX A

A-20

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

24 Enhance the Protective Coating Monitoring and 

Maintenance Program procedures to:

• Specify parameters monitored or inspected 

to include any visible defects, such as 

blistering, cracking, flaking, peeling, rusting, 

and physical damage.

• Specify inspection frequencies, personnel 

qualifications, inspection plans, inspection 

methods, and inspection equipment that 

meet the requirements of ASTM D 5163-08.

• Specify a pre-inspection review of the 

previous two monitoring reports and, based 

on inspection report results, prioritize repair 

areas as either needing repair during the 

same outage or as postponed to future 

outages, but under surveillance in the 

interim period.

• Specify characterization, documentation, 

and testing consistent with 

ASTM D 5163-08 Sections 10.2–10.4 and to 

specify an evaluation of the inspection 

reports by the responsible coating 

evaluation specialist who prepares a 

summary of findings and recommendations 

for future surveillance or repair.

• Specify that the inspection reports prioritize 

repair areas as either needing repair during 

the same outage or as postponed to future 

outages, but under surveillance in the 

interim period.

B2.1.33 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

25 Enhance the Insulation Material for Electrical 

Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification 

Requirements Program procedures to:

• Include all accessible in-scope cable in an 

adverse localized environment.

• Ensure there are no unacceptable visual 

indications of surface anomalies. All 

unacceptable visual indications of cable 

jacket and connection insulation surface 

anomalies will be subject to an engineering

evaluation.

B2.1.34 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-21

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

26 Enhance the Insulation Material for Electrical 

Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits 

Program procedures to:

• Identify the scope of cables requiring aging 

management.

• Require engineering review of surveillance 

results every 10 years.

• Initiate corrective actions when surveillance 

results do not meet acceptance criteria, and 

to require an engineering evaluation be 

performed. When an unacceptable 

condition or situation is identified, a 

determination is also made as to whether 

the review of surveillance results or the 

cable testing frequency needs to be 

increased.

B2.1.35 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections and 

testing to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05856 

dated 

April 25, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-22

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

27 Enhance the Inaccessible Power Cables Not 

Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program procedures 

to:

• Identify the power cables (greater than or 

equal to 400 volts), manholes, pits, and duct 

banks that are within the scope of the 

Inaccessible Power Cables Not Subject to 

10 CFR 50.49 Environmental Qualification 

Requirements Program. 

• Include periodic inspection of manholes, 

pits, and duct banks, to confirm cables are 

not submerged or immersed in water, 

cables/splices and cable support structures 

are intact, and dewatering/drainage systems 

(i.e., sump pumps) and associated alarms 

operate properly. 

• Identify that inspections will be performed at 

least annually based on water accumulation 

over time and after event-driven 

occurrences (e.g., heavy rain or flooding). 

In addition, operation of dewatering devices 

will be inspected and operation verified prior 

to any known or predicted heavy rain or 

flooding events.

• Ensure in-scope power cables are tested at 

least once every 6 years and adjusted 

based on test results and operating 

experience. 

• Compare test results to previous test results 

to evaluate for additional information on the 

rate of cable degradation.

• Confirm cables are not submerged or 

immersed in water, cables, splices, and 

cable support structures are intact, and 

dewatering/drainage systems (i.e., sump 

pumps) and associated alarms operate 

properly. Acceptance criteria for cable 

testing will be defined prior to each test.

• Require an engineering evaluation when the 

test or inspection acceptance criteria are not 

met.

B2.1.36 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections and 

testing to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05856 

dated 

April 25, 2012

Letter 

ULNRC-05891 

dated 

August 9, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-23

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

28 Implement the Electrical Cable Connections Not 

Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program as 

described in LRA Section B2.1.37.

B2.1.37 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

29 Implement the Monitoring of Neutron-Absorbing 

Materials Other than Boraflex Program as 

described in LRA Section B2.1.38.

B2.1.38 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

30 Implement the Metal Enclosed Bus Program as 

described in LRA Section B2.1.39.

(Program implemented, LRA Amendment 38

dated July 31, 2014)

B2.1.39 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

Letter 

ULNRC-06129

dated 

July 31, 2014

31 Enhance the Fatigue Monitoring Program 

procedures to:

• Include fatigue usage calculations that 

consider the effects of the reactor water 

environment for a set of sample reactor 

coolant pressure boundary locations and 

reactor vessel internals locations with 

fatigue usage calculations. The reactor 

coolant pressure boundary set includes the 

NUREG/CR-6260 sample locations for a 

newer-vintage Westinghouse Plant and 

4.3.2.1

4.3.2.2

4.3.4

B3.1

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Letter 

ULNRC-05874 

dated 

June 5, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013
APPENDIX A

A-24

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

plant-specific bounding environmentally 

assisted fatigue (EAF) locations. 

• Ensure the scope includes the fatigue crack 

growth analyses, which support the 

leak-before-break analyses, ASME Code 

Section XI evaluations, and the high-energy 

line break (HELB) selection criterion remain 

valid by counting the transients used in the 

analyses. 

• Require the review of the temperature and 

pressure transient data from the operator 

logs and plant instrumentation to ensure 

actual transient severity is bounded by the 

design and to include environmental effects 

where applicable. If a transient occurs 

which exceeds the design transient 

definition the event is documented in the 

CAP and corrective actions are taken. 

• Include additional transients that contribute 

significantly to fatigue usage. These 

additional transients were identified by 

evaluation of ASME Code Section III fatigue 

and fatigue crack growth analyses. 

• Include additional locations which receive 

more detailed monitoring. These locations 

were identified by evaluation of ASME 

Section III fatigue analyses and the 

locations evaluated for effects of the reactor 

coolant environment. In addition, reactor 

vessel internals locations with fatigue usage 

calculations will be evaluated for the effects 

of the reactor water environment. The 

monitoring methods will be benchmarked 

consistent with the NRC Regulatory Issue 

Summary (RIS) 2008-30. 

• Project the transient count and fatigue 

accumulation of monitored components into 

the future. 

• Include additional cycle count and fatigue 

usage action limits, which permit completion 

of corrective actions if the design limits are 

expected to be exceeded within the next 

three fuel cycles. The fatigue results 

associated with the NUREG/CR-6260 

sample locations for a newer-vintage 

Westinghouse plant and plant-specific 

bounding EAF locations will account for 

environmental effects on fatigue. The cycle 

count action limits for the hot leg surge 

nozzle will incorporate the 60-year cycle 

projections used in the hot leg surge nozzle 

EAF analysis.

Letter

ULNRC-06050 

dated 

October 17, 2013

Letter 

ULNRC-05979 

dated April 26, 

2013

Letter 

ULNRC-05860 

dated May 3, 

2012
APPENDIX A

A-25

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

• Include appropriate corrective actions to 

be invoked if a component approaches a 

cycle count or CUF action limit or if an 

experienced transient exceeds the design 

transient definition. If an action limit is 

reached, corrective actions include 

fatigue reanalysis, repair, or replacement. 

When a cycle counting action limit is 

reached, action will be taken to ensure 

that the analytical bases of the HELB 

locations are maintained. Reanalysis of a 

fatigue crack growth analysis must be 

consistent with or reconciled to the 

originally submitted analysis and receive 

the same level of regulatory review as the 

original analysis.

• Limit the number of the most severe RCP 

component cooling water transient, 

elevated CCW inlet temperature 

transients, to 75% of its design value 

(i.e., limited to 150) in order to 

accommodate the seasonal temperature 

change transient in the RCP thermal 

barrier flange fatigue analysis. (Moved 

here from Commitment No. 38 by LRA 

Amendment 23)

• Include non-NUREG/CR-6260 locations 

with a Uen greater than 1.0 for further 

evaluation using the same methods as 

those used for NUREG/CR-6260 

locations to remove conservatisms from 

the preliminary Uen. The results of these 

final analyses will be incorporated into the 

Fatigue Monitoring Program by either 

counting the transients assumed or 

incorporate the stress intensities into a 

CBF ability of the program. As an 

alternative, the Fatigue Monitoring 

Program will implement SBFs of certain 

locations in order to ensure the 

component does not exceed a Uen of 1.0. 

Any use of SBF will be implemented 

consistent with RIS 2008-30.

• The sentinel location analysis, when refined, 

will be revisited to confirm bounding Reactor 

Coolant Pressure Boundary 

Environmentally Assisted Fatigue 

susceptible sentinel locations are updated 

appropriately and remain bounded 

consistent with the refined analysis.
APPENDIX A

A-26

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

32 Enhance the Concrete Containment Tendon 

Prestress Program specification to:

• Include random samples for the 40-, 45-, 

50-, and 55-year surveillances.

• Extend the predicted lower limit (PLL) lines 

for the vertical and hoop tendon groups to 

60 years.

• Specifically require the final report for each 

surveillance interval to plot the measured 

results against time and to include the PLL, 

Minimum Required Value, and trend lines.

• Require a regression analysis consistent 

with the requirements of NRC Information 

Notice 99-10 Revision 1, Attachment 3.

B3.3

4.5

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Letter 

ULNRC-05963 

dated 

February 28, 

2013

33 As additional industry and plant-specific 

applicable operating experience becomes 

available, it will be evaluated and incorporated 

into each new program.

B2.1.15

B2.1.18

B2.1.19

B2.1.20

B2.1.21

B2.1.23

B2.1.25

B2.1.37

B2.1.38

B2.1.39

Completed 

consistent with 

implementation 

schedule noted with 

each referenced 

AMP.

Letter 

ULNRC-05963 

dated 

February 28, 

2013

Letter 

ULNRC-06057 

dated 

December 20, 

2013

Letter 

ULNRC-06129

dated 

July 31, 2014
APPENDIX A

A-27

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

34 Ameren Missouri replacement steam generator 

divider plate assemblies are fabricated of 

Alloy 690. The divider plate to primary head 

and tubesheet junctions are welded with 

Alloy 152 weld materials. The tubesheet 

cladding is Alloy 182 and the primary head 

cladding is stainless steel. There is a concern 

regarding potential failure at the divider plate 

welds to primary head and tubesheet cladding 

and Ameren Missouri commits to perform one of 

the following three resolution options: 

Option 1: Inspection

Perform a one-time inspection of each steam 

generator to assess the condition of the divider 

plate welds. The examination technique(s) will 

be capable of detecting primary water 

stress-corrosion cracking (PWSCC) in the 

divider plate assemblies and the associated 

welds. 

OR

Option 2: Analysis

Perform an analytical evaluation of the steam 

generator divider plate welds in order to 

establish a technical basis which concludes that 

the steam generator RCS pressure boundary is 

adequately maintained with the presence of 

steam generator divider plate weld cracking. 

The analytical evaluation will be submitted to 

the NRC for review and approval.

OR

Option 3: Industry/NRC Studies

If results of industry and NRC studies and 

operating experience document that potential 

failure of the steam generator RCS pressure 

boundary due to PWSCC cracking of steam 

generator divider plate welds is not a credible 

concern, this commitment will be revised to 

reflect that conclusion.

Section 

3.1.2.2.11.1

Table 3.1.2-4

Option 1 completed 

between fall 2025 

and fall 2029 when 

the replacement 

steam generators 

are in service for 

more than 20 years. 

Option 2 or Option 3 

available for NRC 

review in the fall 

2023. 

Letter 

ULNRC-05920 

dated 

October 24, 2012

Letter 

ULNRC-06057 

dated 

December 20, 

2013

Letter 

ULNRC-06080 

dated 

February 14, 

2014
APPENDIX A

A-28

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

35 The material of steam generator tubesheet 

cladding is Alloy 182. The tubes are made of 

Alloy 690 and are secured to the tubesheet by 

means of tube-to-tubesheet leaktight weld and 

tube expansion. There is a concern regarding 

potential failure of primary-to-secondary 

pressure boundary due to PWSCC cracking of 

tube-to-tubesheet welds. Ameren Missouri

commits to perform one of the following two 

resolution options: 

Option 1: Inspection

Perform a one-time inspection of a 

representative number of tube-to-tubesheet 

welds in each steam generator to determine if 

PWSCC cracking is present. The examination 

technique(s) will be capable of detecting 

PWSCC in the tube-to-tubesheet welds. If weld 

cracking is identified, the condition will be 

resolved through repair or engineering 

evaluation to justify continued service, as 

appropriate, and a periodic monitoring program 

will be established to perform routine 

tube-to-tubesheet weld inspections for the 

remaining life of the steam generators.

OR

Option 2: Analysis

Perform an analytical evaluation of the steam 

generator tube-to-tubesheet welds either 

determining that the welds are not susceptible 

to PWSCC or redefining the reactor coolant 

pressure boundary of the tubes, where the 

steam generator tube-to-tubesheet welds are 

not required to perform a reactor coolant 

pressure boundary function. The redefinition of 

the reactor coolant pressure boundary will be 

submitted as part of a license amendment 

request requiring approval from the NRC. The 

evaluation for determination that the welds are 

not susceptible to PWSCC and do not require 

inspection will be submitted to the NRC for 

review.

Section 

3.1.2.2.11.2

Table 3.1.2-4

Option 1 completed 

between fall 2025 

and fall 2029 when 

the replacement 

steam generators 

are in service for 

more than 20 years. 

Option 2 available 

for NRC review in 

the fall 2023. 

Letter 

ULNRC-05920 

dated 

October 24, 2012

Letter 

ULNRC-06057 

dated 

December 20, 

2013

Letter 

ULNRC-06080 

dated 

February 14, 

2014
APPENDIX A

A-29

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

36 Implement stress-based fatigue (SBF) or 

cycle-based fatigue (CBF) consistent with 

RIS 2008-30 to monitor the CUF of the limiting 

location out of the pressurizer lower head, surge 

nozzle, and heater penetrations to 

accommodate the insurge-outsurge transient. 

(Closed. LRA Amendment 11, dated 

October 11, 2012. The re-evaluation of 

insurge-outsurge analysis demonstrated that 

this type of detailed monitoring was not 

necessary.)

4.3.1

4.3.2.2

B3.1

Closed Letter 

ULNRC-05915 

dated 

October 11, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013

37 Complete an evaluation to determine if there are 

any additional plant-specific bounding EAF 

locations. The supporting environmental 

factors, F(en), calculations will be performed 

with NUREG/CR-6909 or NUREG/CR-6583 for 

carbon and low-alloy steels, NUREG/CR-6909 

or NUREG/CR-5704 for austenitic stainless 

steels, and NUREG/CR-6909 for nickel alloys. 

(Completed Amendment 2 dated May 3, 2012)

In order to determine if the pressurizer contains 

a limiting EAF location, the fatigue analyses will 

be revised to incorporate the effect of 

insurge-outsurge transients on the pressurizer 

lower head, surge nozzle, and heater well 

nozzles at plant-specific conditions. (Completed 

Amendment 2 dated May 3, 2012)

The pressurizer contains a limiting EAF location. 

The fatigue analyses will be revised to 

incorporate the effect of insurge-outsurge 

transients in the pressurizer lower head. 

(Completed LRA Amendment 11 dated 

October 11, 2012)

4.3.2.2

4.3.4

Completed Letter 

ULNRC-05860 

dated 

May 3, 2012

Letter 

ULNRC-05915 

dated 

October 11, 2012

Letter

ULNRC-05979 

dated 

April 26, 2013

38 The number of the most severe RCP 

component cooling water (CCW) transient, 

elevated CCW inlet temperature transients, will 

be limited to 75% of its design value (i.e., limited 

to 150) to accommodate the seasonal 

temperature change transient in the RCP 

thermal barrier flange fatigue analysis. (Moved 

to Item #31 to be managed by the Fatigue 

Monitoring program – LRA Amendment 23 

dated April 26, 2013)

See 

Commitment 

No. 31

Implemented as part 

of Commitment No. 

31:

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Letter 

ULNRC-05979 

dated 

April 26, 2013
APPENDIX A

A-30

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

39 NFPA 805 and LRA gap analysis: 

A gap analysis of LRA Tables 2.3.3-20 and 

3.3.2-20 will be provided to identify 

differences between the existing and 

NFPA 805 post-transition changes. The 

results and the impacts of these gaps on the 

fire protection program described in LRA 

Tables 2.3.3-20 and 3.3.2-20 will be

summarized, as the basis for transitioning to 

the NFPA 805 nuclear safety capabilities. 

The summary will also list the fire protection 

systems and components including 

structural fire barriers (e.g., fire walls and 

slabs, fire doors, fire barrier penetration 

seals, fire dampers, fire barrier coatings and 

wraps, equipment and personnel hatchways 

and plugs, metal siding) that will be added or 

removed based on the NFPA 805 transition 

in the scope of license renewal in 

accordance with 10 CFR 54.4(a) and 

whether they are subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). 

(Completed Amendment 31 dated 

February 14, 2014)

B2.1.13

B2.1.14

Completed Letter 

ULNRC-05877 

dated 

July 2, 2012

Letter 

ULNRC-05946 

dated 

January 10, 2013

Letter 

ULNRC-05971 

dated 

March 20, 2013

Letter 

ULNRC-06080 

dated 

February 14, 

2014

Letter 

ULNRC-06114 

dated April 15, 

2014

40 Enhance the ASME Section XI, Subsection IWL 

Program to specify that acceptability of concrete 

surfaces is based on the evaluation criteria 

provided in ACI-349.3R.

B2.1.27 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to the period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later.

Letter 

ULNRC-05891 

dated 

August 9, 2012

Letter 

ULNRC-05963 

dated 

February 28, 

2013

41 To allow for monitoring of the condition of the 

threads on the RPV stud and flange hole 

threads, Ameren Missouri commits to remove 

RPV stud #18 through nondestructive or 

destructive means. If RPV stud hole repair is 

required following removal of RPV stud #18, the 

repair plan will include inspecting the RPV stud 

hole prior to the repair to assess the as-found 

condition and an inspection after the repair is 

complete to assess the results of the repair.

B2.1.3 Implemented as part 

of proposed License 

Condition No. 3:

Completed no later 

than 6 months prior 

to the period of 

extended operation

or the refueling 

outage prior to the 

period of extended 

operation, whichever 

occurs later. 

Letter 

ULNRC-06032 

dated 

August 29, 2013

Letter

ULNRC-06057 

dated 

December 20, 

2013
APPENDIX A

A-31

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

42 It is noted that Ameren Missouri experienced 

problems with the reactor vessel head closure 

studs and stud holes early in plant life 

(1986-1992) and that multiple RPV stud holes 

required ASME Section XI repairs to remove 

damaged threads. To supplement the 

monitoring that is accomplished through regular 

volumetric inspections and to confirm that 

additional thread degradation is not occurring in 

the RPV stud holes, Ameren Missouri commits 

to perform a one-time inspection of select RPV 

stud holes using a method consistent with the 

Babcock and Wilcox laser inspection that was 

applied following stud hole repair in 1989 and 

1992. RPV stud hole locations 2, 4, 5, 7, 9, and 

53 have had more than one thread removed 

and will be inspected. If inspection of these 

RPV stud holes confirms that there was minimal 

or no additional degradation since the prior 

video inspection, then it is a reasonable 

conclusion that there will be minimal additional 

degradation in the period of extended operation. 

If additional degradation is observed in any of 

the repaired stud holes where more than one 

thread has been removed, the condition will be 

entered in the Corrective Action Program for 

evaluation and corrective action, and the 

remaining repaired RPV stud hole locations 13, 

25, 39, and 54 will be inspected. The inspection 

is expected to confirm that further degradation is 

not occurring in the repaired stud holes and will 

provide a basis for the conclusion that 

acceptance criteria for thread engagement will 

continue to be met through the period of 

extended operation.

B2.1.3 Implemented as part 

of proposed License 

Condition No. 3: 

Completed no later 

than 6 months prior 

to the period of 

extended operation

or the refueling 

outage prior to the 

period of extended 

operation, whichever 

occurs later.

Letter 

ULNRC-06032 

dated 

August 29, 2013

Letter

ULNRC-06057 

dated 

December 20, 

2013

43 The core design procedure will be modified to 

include a review for the following core design 

parameters to ensure that these limits are met 

in future core designs:

• Active fuel – upper core plate distance 

>12.2 inches

• Average core power density 

<124 watts/cm3

• Heat generation figure of merit, F 

≤68 watts/cm3

(Completed Amendment 31 dated 

February 14, 2014)

B2.1.6 Completed Letter 

ULNRC-06072 

dated 

January 16, 2014

Letter 

ULNRC-06080 

dated 

February 14, 

2014

Letter 

ULNRC-06090

dated 

March 13, 2014
APPENDIX A

A-32

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

44 For all MRP-191 Table 4-4 components, as 

applicable to Callaway, Ameren Missouri 

commits to perform one or more of the following 

resolution options for the non-CASS RVI 

components:

Option 1: Replacement

RVI components determined to be subject to 

20% or greater cold work and 30 ksi operating 

stress will be replaced.

Option 2: Inspection

For RVI components determined to be subject 

to 20% or greater cold work and 30 ksi 

operating stress, an augmented inspection 

program capable of detecting cracking will be 

developed. Minimum examination coverage 

criteria consistent with MRP-227-A Primary 

Inspection Category Components will apply. 

The augmented inspection program will be 

submitted to the NRC prior to performance of 

the inspection(s).

Option 3: Impact Evaluation

For RVI components determined to be subject 

to 20% or greater cold work and 30 ksi 

operating stress, an impact evaluation will be 

prepared to establish that the effects of aging 

are minimal and will not have an adverse impact 

on future plant operability or component 

intended function. The impact evaluation(s) will 

be submitted to the NRC.

Option 4: Mitigation

RVI components determined to be subject to 

20% or greater cold work and 30 ksi operating 

stress will be mitigated of stress corrosion 

cracking (SCC) susceptibility. 

Note: Indeterminate components will be 

conservatively assumed to be subject to 20% or 

greater cold work and subject to 30 ksi 

operating stress.

(Closed, evaluation (ULNRC-06106, March 28, 

2014) concluded that the plant-specific material 

fabrication and design are consistent with the 

MRP-191 basis and the MRP-227-A aging 

management requirements as related to cold 

work are directly applicable to Callaway Unit 1. 

Therefore, Options 1 – 4 are not necessary.

B2.1.6 Closed Letter 

ULNRC-06079 

dated 

February 5, 2014

Letter 

ULNRC-06106 

dated 

March 28, 2014

Letter 

ULNRC-06117 

dated 

April 23, 2014
APPENDIX A

A-33

Item 

Number

Commitment FSAR 

Supplement

Section/ LRA 

Section

Implementation 

Schedule

Source

45 Enhance the RG 1.127, Inspection of 

Water-Control Structures Associated with 

Nuclear Power Plants program procedures to 

include the concrete structures in the turbine 

building that provide a flowpath for the 

circulating water system in the scope of the 

program.

(Moved to Item 23 to be managed by the 

Structures Monitoring program – LRA 

Amendment 35 dated May 6, 2014)

See 

Commitment 

No. 23

Implemented as part 

of Commitment No. 

23:

Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Letter 

ULNRC-06080 

dated 

February 14, 

2014

Letter 

ULNRC-06118 

dated 

May 6, 2014

46 Enhance the ASME Section XI Inservice 

Inspection, Subsection IWB, IWC, and IWD 

Program to perform periodic inspection of the 

reactor vessel cladding indications identified in 

FSAR Section 5.2.3.2.2 SP and reconcile the 

inspection results with the corrosion analysis to 

ensure the analytical basis of the analysis is

maintained. 

4.7.3 Completed no later 

than 6 months prior 

to the period of 

extended operation. 

Inspections to be 

completed no later 

than 6 months prior 

to period of 

extended operation 

or the end of the last 

refueling outage 

prior to the period of 

extended operation, 

whichever occurs 

later. 

Letter 

ULNRC-06118 

dated 

May 6, 2014

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 (the staff) and Union Electric Company, doing 

business as Ameren Missouri (the applicant) and other correspondence regarding the staff’s 

reviews of the Callaway Plant Unit 1 (Callaway), Docket Number 50-483, license renewal 

application (LRA).

Date Subject

December 15, 2011 Callaway Plant Unit 1—Letter from Reasoner III C.O., Ameren Missouri: Callaway, 

Unit 1, Application for Renewed Operating License (LDCN 11-0022). (Agencywide 

Documents Access and Management System (ADAMS) Accession 

No. ML113530367)

December 15, 2011 Callaway Plant Unit 1, License Renewal Application. (ADAMS Accession 

No. ML113530372)

December 15, 2011 Callaway Plant Unit 1, Applicant’s Environmental Report; Operating License Renewal 

Stage Final, Cover through Chapter 2. (ADAMS Accession No. ML113540349)

December 15, 2011 Callaway Plant Unit 1, Applicant’s Environmental Report; Operating License Renewal 

Stage Final, Chapter 3 through Attachment D. (ADAMS Accession 

No. ML113540352)

December 15, 2011 Callaway Plant Unit 1, Applicant’s Environmental Report; Operating License Renewal 

Stage Final, Attachment E through End. (ADAMS Accession No. ML113540354)

December 23, 2011 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Receipt and 

Availability of the License Renewal Application for the Callaway Plant, Unit 1. 

(ADAMS Accession No. ML11343A060)

December 23, 2011 Federal Register Notice: Notice of Receipt and Availability of Application for Renewal 

of Callaway Plant, Unit 1. (ADAMS Accession No. ML11343A087)

December 29, 2011 Press Release-11-229: NRC Announces Availability of License Renewal Application 

for Callaway Nuclear Power Plant. (ADAMS Accession No. ML113630433)

February 14, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Determination of 

Acceptability and Sufficiency for Docketing, Proposed Review Schedule, and 

Opportunity for a Hearing Regarding the Application from Union Electric Company, for 

Renewal of the Operating License for Callaway Plant, Unit 1. (ADAMS Accession 

No. ML12024A262)

February 14, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Notice of Intent to 

Prepare an Environmental Impact Statement and Conduct Scoping Process for 

License Renewal for Callaway Plant, Unit 1. (ADAMS Accession No. ML12040A215)

February 14, 2012 Federal Register Notice: NRC Union Electric Company Notice of Intent to Prepare an 

Environmental Impact Statement and Conduct the Scoping Process for Callaway 

Plant, Unit 1. (ADAMS Accession No. ML12040A225)

February 16, 2012 Federal Register Notice: Notice of Opportunity for Hearing, Regarding Renewal of 

Facility Operating License No. NPF-30 for an Additional 20-Year Period, Federal 

Register Notice. (ADAMS Accession No. ML12024A254)

February 24, 2012 Meeting Notice: Forthcoming Meeting to Discuss the License Renewal Process and 

Environmental Scoping for Callaway Plant, Unit 1. (ADAMS Accession 

No. ML12041A479)

March 28, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Callaway 

Plant Unit 1 Union Electric Co. Facility Operating License NPF-30 License Renewal 

Application Online LR Library. (ADAMS Accession No. ML12088A351)

April 17, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Callaway Plant, 

Unit 1, License Renewal Application Online Reference Portal (TAC No. ME7708). 

(ADAMS Accession No. ML12104A191)
APPENDIX B

B-2

Date Subject

April 23, 2012 Letter to Salveter A., U.S. Fish and Wild Service: Callaway Plant, Unit 1, License 

Renewal Application Environmental Review. (ADAMS Accession No. ML12103A209)

April 25, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Callaway 

Plant Unit 1 Union Electric Co. Facility Operating License NPF-30 Amendment 1 to 

Application for Renewed Operating License. (ADAMS Accession No. ML121170324)

May 3, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Callaway 

Plant Unit 1 Union Electric Co. Facility Operating License NPF-30 Amendment 2 to 

Application for Renewed Operating License. (ADAMS Accession No. ML12128A150)

May 31, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Project Manager 

Change for the License Renewal Project (Safety) for Callaway Plant, Unit 1 (TAC 

No. ME7708). (ADAMS Accession No. ML12139A058) 

June 5, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Callaway 

Plant Unit 1 Union Electric Co. Facility Operating License NPF-30 Amendment 3 to 

Application for Renewed Operating License. (ADAMS Accession No. ML121580340)

June 11, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application (TAC No. ME7708). (ADAMS Accession No. ML12144A035)

June 22, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application (TAC No. ME7708). (ADAMS Accession No. ML12157A058)

June 22, 2012 Summary of Site Audit Related to the Review of the License Renewal Application for 

Callaway Plant, Unit 1 (TAC Nos. ME7715 and ME7716. (ADAMS Accession 

No. ML12159A154)

July 2, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 1 and Amendment 4 to the Callaway LRA. (ADAMS Accession 

No. ML121850174)

July 5, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application (TAC No. ME7708). (ADAMS Accession No. ML12164A905)

July 9, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 4 (TAC No. ME7708). (ADAMS Accession No. ML12172A111)

July 18, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 5 (TAC No. ME7708). (ADAMS Accession No. ML12179A400)

July 20, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 2 to the Callaway LRA. (ADAMS Accession No. ML122021159)

August 6, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Scoping and 

Screening Methodology Audit Report Regarding the Callaway Plant, Unit 1, License 

Renewal Application (TAC No. ME7708). (ADAMS Accession No. ML12178A475)

August 6, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 6 (TAC No. ME7708). (ADAMS Accession No. ML12206A264)

August 6, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 3 and Amendment 5 to the Callaway LRA. (ADAMS Accession 

No. ML122200189)

August 9, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 4 and Amendment 6 to the Callaway LRA. (ADAMS Accession 

No. ML122230044)

August 9, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Aging Management 

Programs Audit Report Regarding the Callaway Plant Unit 1 License Renewal 

Application (TAC No. ME7708). (ADAMS Accession No. ML12180A023)
APPENDIX B

B-3

Date Subject

August 16, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 7 (TAC No. ME7708). (ADAMS Accession No. ML12216A338)

August 21, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 5 and Amendment 7 to the Callaway LRA. (ADAMS Accession 

No. ML122350582)

August 23, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 8 (TAC No. ME7708). (ADAMS Accession No. ML12233A613)

September 6, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 6 and Amendment 8 to the Callaway LRA. (ADAMS Accession 

No. ML122510211)

September 6, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 9 (TAC No. ME7708). (ADAMS Accession No. ML12233A570)

September 12, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 10, Public Version (TAC No. ME7708). (ADAMS Accession 

No. ML12284A454)

September 18, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Supplemental 

Responses to RAI Set 3 to the Callaway LRA. (ADAMS Accession 

No. ML122630080)

September 20, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 7 and Amendment 9 to the Callaway LRA. (ADAMS Accession 

No. ML122690080)

September 20, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 8 and Amendment 10 to the Callaway LRA. (ADAMS Accession 

No. ML122650037)

September 20, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set #11 (TAC No. ME7708). (ADAMS Accession No. ML12250A770)

September 25, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set #12 (TAC No. ME7708). (ADAMS Accession No. ML12256A895)

October 1, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 13 (TAC No. ME7708). (ADAMS Accession No. ML12255A287)

October 3, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 14 (TAC No. ME7708). (ADAMS Accession No. ML12270A147)

October 11, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 9, Amendment 11, and Supplemental Responses to the Callaway LRA. 

(ADAMS Accession No. ML122860144)

October 12, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 15 (TAC No. ME7708). (ADAMS Accession No. ML12276A373)

October 15, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 10 and Amendment 12 to the Callaway LRA. (ADAMS Accession 

No. ML122900161)

October 24, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 16 (TAC No. ME7708). (ADAMS Accession No. ML12286A235)

October 24, 2012 Letter from Kremer G. S., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 11 and 12 and Amendment 13 to the Callaway LRA. (ADAMS Accession 

No. ML122990295)
APPENDIX B

B-4

Date Subject

October 31, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Sets 13 and 14 and Amendment 14 to the Callaway LRA. (ADAMS Accession 

No. ML123060389)

November 8, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 15 and Amendment 15 to the Callaway LRA. (ADAMS Accession 

No. ML123140212)

November 20, 2012 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Callaway Plant –

NRC License Renewal Inspection Report 05000483/2012009. (ADAMS Accession 

No. ML12328A053)

November 20, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 16 and Amendment 16 to the Callaway LRA. (ADAMS Accession 

No. ML12328A088)

November 24, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 17 (TAC No. ME7708). (ADAMS Accession No. ML12320A517)

November 29, 2012 Summary of Telephone Conference Call Held on September 27, 2012, Between the 

U.S. Nuclear Regulatory Commission and Union Electric Company (Ameren Missouri), 

Concerning Requests for Additional Information Pertaining to the Callaway Plant,

Unit 1, License Renewal Application (TAC No. ME7708). (ADAMS Accession 

No. ML12321A199)

December 7, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 18 (TAC No. ME7708). (ADAMS Accession No. ML12326A915)

December 13, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 17 and Amendment 17 to the Callaway LRA. (ADAMS Accession 

No. ML123490272)

December 19, 2012 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Annual 

Update to the Callaway License Renewal Application Response to RAI Set #18. 

(ADAMS Accession No. ML123560157)

December 27, 2012 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set #19 (TAC No. ME7708). (ADAMS Accession No. ML12342A172)

January 10, 2013 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Response to 

RAI 2.3.4.2-1a and Amendment 19 to the Callaway LRA. (ADAMS Accession 

No. ML130110026)

January 14, 2013 Letter to Heflin A. C., Union Electric Company(Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 20 (TAC No. ME7708). (ADAMS Accession No. ML13009A211)

January 24, 2013 Letter from Kremer G. S., Union Electric Company (Ameren Missouri): Responses to 

RAI Sets 19 and 20 and Amendment 20 to the Callaway LRA. (ADAMS Accession 

No. ML130290353)

January 25, 2013 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Summary of the 

Public Meeting to Discuss the Results of the Callaway Nuclear Plant License Renewal 

Inspection. (ADAMS Accession No. ML13025A134)

January 30, 2013 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 21 (TAC No. ME7708). (ADAMS Accession No. ML13025A031)

February 12, 2013 Summary of Telephone Conference Call Held on December 6, 2012, Between the 

U.S. Nuclear Regulatory Commission and Union Electric Company (Ameren Missouri), 

Concerning Requests for Additional Information Pertaining to the Callaway Plant, 

Unit 1, License Renewal Application (TAC No. ME7708). (ADAMS Accession 

No. ML13029A659)
APPENDIX B

B-5

Date Subject

February 12, 2013 Summary of Telephone Conference Call Held on January 22, 2013, Between the 

U.S. Nuclear Regulatory Commission and Union Electric Company (Ameren Missouri), 

Concerning Requests for Additional Information Pertaining to the Callaway Plant, 

Unit 1, License Renewal Application (TAC No. ME7708). (ADAMS Accession 

No. ML13029A016)

February 14, 2013 Letter from McLachlan M., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 21 and Amendment 21 to the Callaway LRA. (ADAMS Accession 

No. ML130460490)

February 21, 2013 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 22 (TAC No. ME7708). (ADAMS Accession No. ML13038A308)

February 28, 2013 Letter from Kremer G. S., Union Electric Company (Ameren Missouri): Responses to 

RAI Set 22 and Amendment 22 to the Callaway LRA. (ADAMS Accession 

No. ML130630622)

March 20, 2013 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Commitment 

Regarding NFPA 805 Gap Analysis for the Callaway LRA. (ADAMS Accession 

No. ML13080A348)

March 26, 2013 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 23 (TAC No. ME7708). (ADAMS Accession No. ML13042A042)

March 26, 2013 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Date 

Correction to RAI Set #22, Enclosure 1 Related to the Callaway LRA. (ADAMS 

Accession No. ML130860643)

March 29, 2013 Letter to Heflin A. C., Union Electric Company (Ameren Missouri): Request for 

Additional Information for the Review of the Callaway Plant, Unit 1 License Renewal 

Application, Set 24 (TAC No. ME7708). (ADAMS Accession No. ML13058A124)

April 1, 2013 Summary of Telephone Conference Call Held on August 23, 2012, Between the 

U.S. Nuclear Regulatory Commission and Union Electric Company (Ameren Missouri), 

Concerning Requests for Additional Information Pertaining to the Callaway Plant, 

Unit 1, License Renewal Application (TAC No. ME7708). (ADAMS Accession 

No. ML13067A316)

April 16, 2013 Summary of Telephone Conference Call Held on April 11, 2013, Between the 

U.S. Nuclear Regulatory Commission and Union Electric Company (Ameren Missouri), 

Concerning Requests for Additional Information Pertaining to the Callaway Plant, 

Unit 1, License Renewal Application (TAC No. ME7708). (ADAMS Accession 

No. ML13102A131)

April 23, 2013 Letter to Heflin A. C., Ameren Missouri: Safety Evaluation Report with Open Items 

Related to the License Renewal of Callaway Plant Unit 1 (TAC No. ME7708). 

(ADAMS Accession No. ML13086A224)

April 23, 2013 Memorandum to E. M. Hackett, Advisory Committee on Reactor Safeguards: ACRS 

Review of the Callaway Plant, Unit 1, LRA- SER With Open Items. (ADAMS 

Accession No. ML13098A149)

April 26, 2013 Letter from Kanuckel L. H., Union Electric Company (Ameren Missouri): Callaway, 

Unit 1, Responses to RAI Set #23 and Amendment 23 to the Callaway LRA. (ADAMS 

Accession No. ML13119A133)

April 26, 2013 Letter from Kanuckel L. H., Ameren Missouri: Callaway, Unit 1, Enclosure 1 to 

ULNRC-05979, License Renewal Application, Request for Additional Information(RAI) 

Set #23 Responses. (ADAMS Accession No. ML13119A136)

April 26, 2013 Letter from Kanuckel L. H., Ameren Missouri: Callaway, Unit 1, Enclosure 2 to 

ULNRC-05979, Amendment 23, LRA Changes from RAI Responses and Commitment 

Updates Enclosure 2 Summary Table. (ADAMS Accession No. ML13119A137)

April 29, 2013 Letter fromKanuckel L. H., Ameren Missouri: Callaway, Unit 1, Responses to RAI 

Set #24 and Amendment 24 to LRA. (ADAMS Accession No. ML13121A249)
APPENDIX B

B-6

Date Subject

April 29, 2013 Letter from Kanuckel L. H., Ameren Missouri: Callaway, Unit 1, Enclosure 1 to 

ULNRC-05990, Responses to RAI Set # 24 and Amendment 24 to LRA and 

Enclosure 2, Amendment 24, LRA Changes from RAI Responses. (ADAMS 

Accession No. ML13121A250)

May 10, 2013 Letter from Reasoner, C. O., Ameren Missouri: Callaway, Unit 1 - Request to Delay 

Scheduled ACRS Subcommittee Meeting Date. (ADAMS Accession No. 

ML13134A304)

May 30, 2013 Letter to Heflin A. C., Ameren Missouri: Schedule Revision for the Safety Review of 

the Callaway Plant, Unit 1, LRA (TAC No. ME7708). (ADAMS Accession 

No. ML13141A748)

June 5, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Review of Safety 

Evaluation with Open Items. (ADAMS Accession No. ML13156A351)

June 5, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant, Unit 1 - Enclosure 1 to 

ULNRC-05994 - Technical Comments Regarding the Safety Evaluation Report (SER) 

with Open Items Related to the License Renewal . (ADAMS Accession 

No. ML13156A352)

June 5, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Editorial Comments 

Regarding the Safety Evaluation Report (SER) with Open Items Related to the License 

Renewal. (ADAMS Accession No. ML13156A353)

July 12, 2013 Letter to Heflin A. C., Ameren Missouri: Request for Additional Information for the 

Review of the Callaway Plant, Unit 1, License Renewal Application, Set 25 (TAC 

No. ME7708). (ADAMS Accession No. ML13143A344)

August 2, 2013 Letter to Heflin A. C., Ameren Missouri: RAI Set 26. (ADAMS Accession 

No. ML13192A025)

August 2, 2013 Letter from McLachlan, M., Ameren Missouri: Callaway, Unit 1, Response to RAI 

Set #25 Amendment 25 to LRA. (ADAMS Accession No. ML13217A073)

August 2, 2013 Letter from McLachlan, M., Ameren Missouri: Callaway, Unit 1, Response to Request 

for Additional Information Set #25 on License Renewal Application. (ADAMS 

Accession No. ML13217A074)

August 29, 2013 Letter from McLachlan, M., Ameren Missouri: Callaway Plant Unit 1 - Response to 

RAI Set #26 and Amendment 26 to the Callaway LRA. (ADAMS Accession 

No. ML13242A290)

August 29, 2013 Letter from McLachlan, M., Ameren Missouri: Enclosure 1: Request for Additional 

Information (RAI) Set #26 Responses on License Renewal Application. (ADAMS 

Accession No. ML13242A291)

August 29, 2013 Letter from McLachlan, M., Ameren Missouri: Enclosure 2 - Amendment 26, LRA 

Changes. (ADAMS Accession No. ML13242A292)

September 20, 2013 Letter to Heflin A. C., Ameren Missouri: Callaway Plant, Unit 1, RAI Set 27 Rev 2. 

(ADAMS Accession No. ML13253A210)

October 17, 2013 Letter from Kremer, G. S., Ameren Missouri: Callaway, Unit 1, Response to RAI 

Set #27 (RAI B2.1.6-4c) and Amendment 27 to the Callaway LRA. (ADAMS 

Accession No. ML13295A108)

November 4, 2013 Letter to Heflin A. C., Ameren Missouri: Schedule Revision for the Safety Review of 

the Callaway Plant, Unit 1, License Renewal Application (TAC Nos. ME7708 and 

ME7716). (ADAMS Accession No. ML13281A781)

December 2, 2013 Letter to Heflin A. C., Ameren Missouri: Request for Additional Information for the 

Review of the Callaway Plant, Unit 1, License Renewal Application, Set 29 (TAC 

No. ME7708). (ADAMS Accession No. ML13330A689)

December 20, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Annual Update to the 

Callaway License Renewal Application and Response to RAI Set #28. (ADAMS 

Accession No. ML13360A272)

December 20, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1, Enclosure 1 to 

ULNRC-06057, License Renewal Application - Request for Additional Information 

(RAI) Set #28 Responses. (ADAMS Accession No. ML13360A273)
APPENDIX B

B-7

Date Subject

December 20, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1, Enclosure 2 to 

ULNRC-06057 - Amendment 28 LRA Change for LRA Annual Update and RAI Set 28. 

(ADAMS Accession No. ML13360A274)

December 20, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1, Enclosure 3 to 

ULNRC-06057, License Renewal Application - Summary of LRA Correspondence. 

(ADAMS Accession No. ML13360A275)

December 20, 2013 Letter fromKovaleski, S., Ameren Missouri: Callaway Plant, Unit 1, Enclosure 1 to 

ULNRC-06066, License Renewal Application, Request for Additional Information (RAI) 

Set #15 Responses Supplement to RAI B2.1.7-5A. (ADAMS Accession 

No. ML13360A302)

December 20, 2013 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant, Unit 1, Supplement to 

RAI B2.1-7-5a. (ADAMS Accession No. ML13360A303)

January 16, 2014 Letter from Kovaleski, S., Ameren Missouri: Enclosure 1 to ULNRC-06072, Callaway 

Plant, Unit 1, Responses to Request for Additional Information (RAI) Sets #29 and #27 

(RAI B2.1.6-4b). (ADAMS Accession No. ML14017A007)

January 16, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant, Unit 1, Response to RAI 

Set #29, RAI Set #27 (RAI B2.1.6-4b), and Amendment 29 to the Callaway LRA. 

(ADAMS Accession No. ML14017A008)

February 4, 2014 Notice of Forthcoming Category 1 Meeting (February 20, 2014) with Union Electric Co. 

(Ameren Missouri) and Westinghouse to Discuss License Renewal for the Callaway 

Plant Unit 1. (ADAMS Accession No. ML14035A303)

February 5, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Unit 1, Enclosure 1 to 

ULNRC-06079 - License Renewal Application, Supplemental Response to Request for 

Additional Information (RAI) Set #29 RAI B2.1.6-4d, Part (a). (ADAMS Accession 

No. ML14036A359)

February 5, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Unit 1, Supplemental Response 

to RAI B2.1.6-4d, Part (a) and Amendment 30 to the License Renewal Application. 

(ADAMS Accession No. ML14036A360)

February 12, 2014 Letter to Diya, F., Ameren Missouri: Request for Additional Information for the Review 

of the Callaway Plant, Unit 1, License Renewal Application, Set 30 (TAC No. 

ME7708). (ADAMS Accession No. ML14029A192)

February 14, 2014 Letter from McLachlan, M., Ameren Missouri: Callaway, Unit 1, Amendment 31 to 

License Renewal Application Regarding Fire Protection. (ADAMS Accession 

No. ML14045A284)

February 14, 2014 Letter from McLachlan, M., Ameren Missouri: Callaway, Unit 1, Amendment 31 to 

License Renewal Application Change Regarding Fire Protection. (ADAMS Accession 

No. ML14045A285)

February 24, 2014 Letter to Diya, F., Ameren Missouri: Project Manager Change for the License 

Renewal of Callaway Plant, Unit 1 (TAC No. ME7708). (ADAMS Accession No. 

ML14052A230)

February 26, 2014 Letter to Diya, F., Ameren Missouri: Schedule Revision for the Safety Review of the 

Callaway Plant, Unit 1, License Renewal Application (TAC No. ME7708). (ADAMS 

Accession No. ML14050A020)

March 13, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant Unit 1 Response to RAI 

Set 30 and Amendment 32 to LRA. (ADAMS Accession No. ML14073A003)

March 13, 2014 Letter from Kovaleski, S., Ameren Missouri: Enclosure 1: Callaway Plant Unit 1, 

Response to Request for Additional Information Set 30 and Updated Response to 

RAI B2.1.6-4d, Part (b). (ADAMS Accession No. ML14073A004)

March 13, 2014 Letter from Kovaleski, S., Ameren Missouri: Enclosure 2: Amendment 32, LRA 

Changes. (ADAMS Accession No. ML14073A005)

March 25, 2014 Summary of Telephone Conference Call Held January 28, 2014, Between NRC and 

Union Electric Company (Ameren Missouri), Pertaining to the Callaway Plant Unit 1, 

LRA. (ADAMS Accession No. ML14035A575)
APPENDIX B

B-8

Date Subject

March 25, 2014 Letter to Diya, F., Ameren Missouri: Request for Additional Information for the Review 

of the Callaway Plant, Unit 1, License Renewal Application, Set 31 (TAC No. 

ME7708). (ADAMS Accession No. ML14065A592)

March 28, 2014 Letter from Kremer, G. S., Ameren Missouri: Callaway, Unit 1, Enclosure 1 to 

ULNRC-06106, Supplemental Response to Request for Additional Information 

(RAI) B2.1.6-4d, Part (a). (ADAMS Accession No. ML14087A091)

March 28, 2014 Letter from Kremer, G. S., Ameren Missouri: Callaway Plant, Unit 1, Supplemental 

Response to RAI B2.1.6-4d, Part (a) Related to Reactor Vessel Internals Cold Worked 

Material. (ADAMS Accession No. ML14087A092)

March 28, 2014 Letter from Gresham, J. A., Westinghouse: Attachment 3: Westinghouse Application 

for Withholding Proprietary Information from Public Disclosure CAW-14-3933, 

Accompanying Affidavit, Proprietary Information Notice, and Copyright Notice. 

(ADAMS Accession No. ML14093A775)

March 28, 2014 Letter from Gresham, J. A., Westinghouse: Attachment 1: Westinghouse Final 

Response to U.S. NRC RAI 3.1.2.1-6 (a) and (b) on the Callaway Nuclear Plant 

Reactor Lower Radial Support Clevis Insert Bolts (Proprietary). (ADAMS Accession 

No. ML14093A777)

March 28, 2014 Letter from Gresham, J. A., Westinghouse: Attachment 2: Westinghouse Final 

Response to U.S. NRC RAI 3.1.2.1-6 (a) and (b) on the Callaway Nuclear Plant 

Reactor Lower Radial Support Clevis Insert Bolts (Non-Proprietary). (ADAMS 

Accession No. ML14093A780)

March 31, 2014 Summary Of Meeting Held February 20, 2014, Between U.S. Nuclear Regulatory 

Commission Staff And Union Electric Company Representatives To Discuss The 

Callaway Plant, Unit 1, License Renewal Application (TAC No. ME7708). (ADAMS 

Accession No. ML14080A544)

April 3, 2014 Letter from Kovaleski, S., Ameren Missouri: Enclosure 1: Supplemental Response to 

RAI Set #30 (RAI 3.1.2.1-6). (ADAMS Accession No. ML14093A778)

April 3, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Submittal of 

Supplemental Response to RAI Set #30 (RAI 3.1.2.1-6). (ADAMS Accession 

No. ML14093A781)

April 7, 2014 Summary of Telephone Conference Call Held 02/27/2014 and 03/04/2014, between 

Nuclear Regulatory Commission and Union Electric Company (Ameren Missouri), 

Pertaining to the Callaway Plant Unit 1, license renewal application RAI set 31. 

(ADAMS Accession No. ML14070A078)

April 11, 2014 Letter to Diya, F., Ameren Missouri: Regarding Ameren Missouri license renewal 

Amendment 31, National Fire Protection Association 805 changes to the Callaway 

Plant, Unit 1, license renewal application (TAC No. ME7708). (ADAMS Accession 

No. ML14083A617)

April 14, 2014 Summary of Telephone Conference Call Held January 30, 2014, between NRC and 

Union Electric Co., (Ameren Missouri), Concerning Requests for Additional Information 

Pertaining to Callaway, Unit 1, License Renewal Application. (ADAMS Accession 

No. ML14093B338)

April 15, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant, Unit 1 - Supplement to 

the Callaway LRA - NFPA 805 Gap Analysis and LRA Amendment 33. (ADAMS 

Accession No. ML14105A475)

April 15, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant, Unit 1 - License Renewal 

Application NFPA 805 Gap Analysis. (ADAMS Accession No. ML14105A476)

April 23, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant, Unit 1, License Revewal 

Application, Request for Additional Information (RAI) Set 31 Responses. (ADAMS 

Accession No. ML14114A110)

April 23, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway Plant, Unit 1, Response to RAI 

Set #31 and Amendment 34 to the Callaway LRA. (ADAMS Accession 

No. ML14114A113)
APPENDIX B

B-9

Date Subject

May 6, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Updated RAI 

Response to the License Renewal Application Amendment 35. (ADAMS Accession 

No. ML14127A150)

May 6, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Updated RAI 

Response to the License Renewal Application, Enclosures 1 and 2. (ADAMS 

Accession No. ML14127A151)

May 12, 2014 Memorandum to E. M. Hackett, Advisory Committee on Reactor Safeguards: Advisory 

Committee On Reactor Safeguards Review Of The Callaway Nuclear Plant License 

Renewal Application - Safety Evaluation Report. (ADAMS Accession 

No. ML14121A106)

June 5, 2014 Letter from Kovaleski, S., Ameren Missouri: Enclosure 1, Amendment 36, LRA 

Changes. (ADAMS Accession No. ML14156A312)

June 5, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Amendment 36 to the 

Callaway LRA. (ADAMS Accession No. ML14156A313)

June 17, 2014 Letter from Kovaleski, S., Ameren Missouri: Callaway, Unit 1 - Amendment 37 to the 

Callaway LRA. (ADAMS Accession No. ML14168A360)

June 18, 2014 Summary of Telephone Conference Call Held November 25, 2013, between NRC and 

Union Electric Co., (Ameren Missouri), Concerning Requests for Additional Information 

Pertaining to Callaway, Unit 1, License Renewal Application (TAC ME7708). (ADAMS 

Accession No. ML14121A553)

July 8, 2014 Summary of Telephone Conference Call Held on October 2 and 3, 2013, between the 

U.S. Nuclear Regulatory Commission and Union Electric Co., (Ameren Missouri), 

Concerning Requests for Additional Information Pertaining to Callaway, Unit 1, 

License Renewal Application (TAC ME7708). (ADAMS Accession No. ML14175B499)

August 20, 2014 Summary of Telephone Conference Call Held November 26, 2013, between NRC and 

Union Electric Co., (Ameren Missouri), Concerning Requests for Additional Information 

Pertaining to Callaway, Unit 1, License Renewal Application (TAC ME7708). (ADAMS 

Accession No. ML14223A532)

August 20, 2014 Summary of Telephone Conference Call Held December 18, 2013, between the U.S. 

Nuclear Regulatory Commission and Union Electric Co., (Ameren Missouri), 

Concerning Requests for Additional Information Pertaining to Callaway, Unit 1, 

License Renewal Application (TAC ME7708). (ADAMS Accession No. ML14223A602)

October 14, 2014 Stetkar, John W. to Allison M. Macfarlane, Chairman, U.S. Nuclear Regulatory 

Commission, “Report on the Safety Aspects of the License Renewal Application of the 

Callaway Plant, Unit 1.” (ADAMS Accession No. ML1414279A289)

C-1

APPENDIX C

PRINCIPAL CONTRIBUTORS

This appendix lists the principal contributors for the development of this safety evaluation report 

(SER) and their areas of responsibility.

Name Responsibility

Principal Contributors

Armstrong, Garry Reviewer – Scoping & Screening

Auluck, Rajender Management Oversight

Brittner, Don Reviewer – Mechanical

Buford, Angela Reviewer – Structural

Casto, Greg Management Oversight

Dennig, Robert Management Oversight

Doutt, Cliff Reviewer – Electrical

Erickson, Alice Reviewer – Structural

Cuadrado, Samuel Project Management

Daily, John Project Management

Yoira Diaz-Sanabria Management Oversight

Fu, Bart Reviewer – Mechanical

Gall, Jennifer Reviewer – Scoping & Screening

Galloway, Melanie Management Oversight

Gavula, Jim Reviewer – Mechanical

Ghasemian, Shahram Management Oversight

Giitter, Joseph Management Oversight

Green, Kim Reviewer – Mechanical

Hiland, Pat Management Oversight

Hiser, Allen Management Oversight

Holston, Bill Reviewer – Mechanical

Hovanec, Chris Reviewer – Mechanical

Hunt, Christopher Reviewer – Mechanical

Iqbal, Naeem Reviewer – Fire Protection

Jackson, Christopher Management Oversight

Kalikian, Roger Reviewer – Mechanical

Karwoski, Kenneth Management Oversight

Kichline, Michelle Reviewer – Mechanical

Klein, Alex Management Oversight

Klos, John Reviewer – Mechanical

Kulesa, Gloria Management Oversight

Lehman, Bryce Reviewer – Structural

Li, Rui Reviewer – Electrical

Lubinski, John Management Oversight

Mathew, Roy Management Oversight

Marshall, Michael Management Oversight

McGinty, Tim Management Oversight
APPENDIX C

C-2

Name Responsibility

Medoff, Jim Reviewer – Mechanical

Min, Seung Reviewer – Mechanical

Morey, Dennis Management Oversight

Murphy, Martin Management Oversight

Ng, Ching Reviewer – Mechanical

Nguyen, Duc Reviewer – Electrical

Obodoako, Aloysius Reviewer – Mechanical

Parks, Benjamin Reviewer – Neutron Fluence

Pham, Bo Management Oversight

Prinaris, Andrew Reviewer – Structural

Raval, Janak Reviewer – Scoping & Screening

Rogers, Bill Reviewer – Scoping & Screening Methodology

Rosenberg, Stacey Management Oversight

Sheikh, Abdul Reviewer – Structural

Smith, Ed Reviewer – Scoping & Screening

Sun, Robert Reviewer – Mechanical

Sydnor, Christopher Reviewer – Mechanical

Torres, Roberto Reviewer – Scoping & Screening

Wise, John Reviewer – Mechanical

Wong, Emma Reviewer – Mechanical

Yee, On Reviewer – Mechanical

Contractors

BLH Technologies, Inc. SER Support

Oak Ridge National Laboratory Review – Structural
D-1

APPENDIX D

REFERENCES

This appendix lists the references used throughout this safety evaluation report for review of the 

license renewal application for Callaway Plant Unit 1.

U.S. Nuclear Regulatory Commission Documents

U.S. Nuclear Regulatory Commission (U.S. NRC) IE Bulletin 87-01, “Thinning in Pipe Walls in Nuclear Power 

Plants,” July 1987.

U.S. NRC Bulletin 88-09, “Thimble Tube Thinning in Westinghouse Reactors,” July 1988.

U.S. NRC Bulletin 88-11, “Revised Fatigue Analysis of the Pressurizer Surge Line for Thermal Cycling and 

Stratification,” December 1988.

Generic Letter (GL) 88-05, “Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR 

Plants,” March 1988.

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 1989.

GL 2007-01, “Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or 

Cause Plant Transients,” February 2007.

Generic Safety Issue No. 190 (GSI-190), “Fatigue Evaluation of Metal Components for 60-Year Plant Life,” 

December 1999.

Information Notice (IN) 85-08, “Industry Experience on Certain Materials Used in Safety-Related Equipment,” 

January 1985.

IN 94-63, “Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks,” August 1994.

IN 99-10, “Degradation of Prestressing Tendon Systems in Prestressed Concrete Containments,” Revision 1.

IN 2004-09, “Corrosion of Steel Containment and Containment Liner,” April 2004.

IN 2007-37, “Buildup of Deposits in Steam Generator,” November 2007.

IN 2010-12, “Containment Liner Corrosion,” June 2010.

License Renewal Interim Staff Guidance (LR-ISG) 2008-01, “Staff Guidance Regarding the Station Blackout Rule 

(10 CFR 50.63) Associated with License Renewal Applications.”

LR-ISG 2011-01, “Aging Management of Stainless Steel Structures and Components in Treated Borated Water.”

LR-ISG 2011-03, “Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 Aging Management 

Program (AMP) XI.M41, Buried and Underground Piping and Tanks.”

NUREG-0313, “Technical Report On Material Selection And Processing Guidelines For BWR Coolant Pressure 

Boundary Piping,” Revision 2, January 1988.

NUREG-0588, “Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment.”

NUREG-0830, “Safety Evaluation Report Related to the Operation of Callaway Plant, Unit No 1,” October 1981.

NUREG-0830, Supplement No 3, “Safety Evaluation Report Related to the Operation of Callaway Plant, Unit No. 1,” 

May 1984.

NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,” 

June 1990.

NUREG-1557, “Summary of Technical Information and Agreements from Nuclear Management and Resources 

Council Industry Reports Addressing License Renewal,” October 1996.

NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,” 

Revision 2, December 2010.

NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” Revision 2, December 2010.

NUREG/CR-4513, “Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR 

Systems,” May 1994.

NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels,” 

April 1999.
APPENDIX D

D-2

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

Components,” February 1995.

NUREG/CR-6428, “Effects of Thermal Aging on Fracture Toughness and Charpy-Impact Strength of Stainless Steel 

Pipe Welds,” May 1996.

NUREG/CR-6583, “Effects of [Light-Water Reactor] LWR Coolant Environments on Fatigue Curves of Carbon and 

Low-Alloy Steels,” February 1998.

NUREG/CR-6876, “Risk-Informed Assessment of Degraded Buried Piping Systems in Nuclear Power Plants,” 

June 2005.

NUREG/CR-6909, “Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials,” February 2007.

NUREG/CR-7136, “Assessment of NDE Methods on Inspection of HDPE Butt Fusion Piping Joints for Lack of 

Fusion,” May 2012

U.S. NRC Regulatory Guide (RG) 1.20, “Comprehensive Vibration Assessment Program for Reactor Internals 

During Preoperational and Initial Startup Testing.”

RG 1.36, “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.”

RG 1.35.1, “Determining Prestressing Forces for Inspection of Prestressed Concrete Containments.”

RG 1.54, “Service Level I, II, and III Protective Coatings Applied To Nuclear Power Plants.”

RG 1.89 “Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants.”

RG 1.99, “Radiation Embrittlement of Reactor Vessel Materials.”

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants.”

RG 1.147, “Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1.”

RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.”

RG 1.163, “Performance-Based Containment Leak-Test Program.”

RG 1.188, “Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses.”

RG 1.189, Fire Protection for Nuclear Power Plants.”

RG 1.190, “Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence.”

U.S. NRC Regulatory Issue Summary (RIS) 2007-24, “New Staff Position on Use of the Westinghouse Crossflow 

Ultrasonic Flow Meter for Power Uprate or Power Recovery,” September 2007. 

U.S. NRC RIS 2008-30, “Fatigue Analysis Of Nuclear Power Plant Components,” December 2008.

U.S. NRC RIS 2011-07, “License Renewal Submittal Information for Pressurized Water Reactor Internals Aging 

Management,” July 2011.

U.S. NRC RIS 2011-14, “Metal Fatigue Analysis Performed by Computer Software,” December 2011.

Regulations

U.S. Code of Federal Regulations (CFR), “Domestic Licensing of Production and Utilization Facilities,” Part 50, Title 

10, “Energy,” Office of the Federal Register, National Archives and Records Administration, 2012.

CFR, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 2012.

Industry Documents

Bechtel Topical Report BC-TOP-5-A, “Conformance to NRC Regulatory Guides.”

“Corrosion Resistance of Stainless Steels in Soils and in Concrete,” Pierre-Jean Cunat, October 2001.

Electrical Power Research Institute (EPRI) 1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: 

Revision 1 to TR-107396, Closed Cooling Water Chemistry Guideline” April 2004.

EPRI 1013706, “Pressurized Water Reactor Steam Generator Examination Guidelines.”

EPRI 1016596, “PWR Internals Inspection and Evaluation Guideline (MRP-227, Revision 0).”

EPRI 1016609, “Inspection Standard for PWR Internals (MRP-228, Revision 0).”

EPRI 1019038, “Steam Generator Integrity Assessment Guidelines.”

EPRI 1022863, “Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation 

Guidelines (MRP-227-A).”

EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, May 1988.

EPRI TR-1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR-107396, Closed 

Cooling Water Chemistry Guideline.” April 2004.

EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide,” December 1995.
APPENDIX D

D-3

Crane Manufacturers Association of America (CMAA), Inc., Specification 70, “Specifications for Top Running Bridge 

& Gantry Type Multiple Girder Electric Overhead Traveling Cranes,” CMAA, Charlotte, NC, December 2008.

NEI 03-08, “Guideline for the Management of Materials Issues,” January 2010.

NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54—The License Renewal Rule,” 

Revision 6, June 2005.

NEI 97-06, “Steam Generator Program Guidelines,” Revision 3.

Nuclear Safety Analysis Center (NSAC)-202L-R3, “Recommendations for an Effective Flow Accelerated Corrosion 

Program, (1011838),” EPRI, May 2006.

NUMARC 93-01, “Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” 

Revision 2, April 1996.

Oak Ridge National Laboratory (ORNL) Report ORNL/TM-2006/530, “A Physically Based Correlation of 

Irradiation-Induced Transition Temperature Shifts for RPV Steels,” November 2007.

“Polymer Blends Handbook,” Kluwer Academic Publishers, 2002.

“Plant Engineer’s Reference Book,” Denis Snow, 2nd Edition, 2002.

“PVC Pipe – Design and Installation – Manual of Water Supply Practices, M23, American Water Works 

Association,” 2nd Edition, 2002.

“PVC Formulary,” G. Wypych, Chem Tec Publishing, 2009.

“Standard Handbook of Plant Engineering,” Robert Rosaler, 3rd Edition, McGraw Hill, 2002.

Westinghouse Commercial Atomic Power (WCAP) 12866, “Bottom Mounted Instrumentation Flux Thimble Wear.”

WCAP 12893, “Structural Evaluation of the Wolf Creek and Callaway Pressurizer Surge Lines, Considering the 

Effects of Thermal Stratification,” March 1991.

WCAP 14040-NP-A, “Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS 

Heatup and Cooldown Limit Curves,” May 2004.

WCAP 14950, “Mitigation and Evaluation of Pressurizer Insurge-Outsurge Transients,” February 1998.

WCAP 15338, “A Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants 

(MUHP-6110),” March 2000.

WCAP 15400 – NP, “Analysis of Capsule X from the Ameren UE Callaway Unit 1 Reactor Vessel Surveillance 

Program,” June 2000.

WCAP 15988-NP, “Generic Guidance for an Effective Boric Acid Inspection Program for Pressurized Water 

Reactors.”

WCAP 17096-NP, “Reactor Internals Acceptance Criteria Methodology and Data Requirements,” Revision 2.

WCAP 17168-NP, “Callaway Unit 1 Time-Limited Aging Analysis on Reactor Vessel Integrity,” September 2010.

Industry Codes and Standards

American Concrete Institute (ACI) 201.1R, “Guide for Making a Condition Survey of Existing Buildings,” July 2008.

ACI 201.2R, “Guide to Durable Concrete,” June 2008.

ACI 318-71, “Building Code Requirements for Reinforced Concrete,” August 1972.

ACI 349.3R-96, “Evaluation of Existing Nuclear Safety Related Concrete Structures,” 1996.

American National Standards Institute (ANSI) B16.5, “Pipe Flanges and Flanged Fittings.”

ASME N45.2.6-1978, “Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants.”

American National Standards Institute (ANSI)/American Nuclear Society (ANS) 56.8, “Containment System 

Leakage Testing Requirements,” 2002.

ANSI/ASME B30.2, “Overhead and Gantry Cranes—Top Running Bridge, Single or Multiple Girder, Top Running 

Trolley Hoist,” 2011.

ANSI/ASME B31.1, “Power Piping.”

American Society for Metals (ASM) Handbook, Volume 19, “Fatigue and Fracture,” 1996.

American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, Section III, “Rules for 

Construction of Nuclear Power Plant Components,” American Society of Mechanical Engineers, New York, NY.

ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components.”

ASME Code Case N514, “Low Temperature Overpressure Protection, Section XI, Division 1.”
APPENDIX D

D-4

ASME Code Case N722, “Additional Examinations for PWR Pressure Retaining Welds in Class 1 Components 

Fabricated with Alloy 600/82/182 Materials, Section XI, Division 1,” July 2005.

ASME Code Case N729-1, “Alternative Examination Requirements for PWR Reactor Vessel Upper Heads With 

Nozzles Having Pressure-Retaining Partial-Penetration Welds, Section XI, Division 1,” March 2006.

ASME Code Case N770, “Alternative Examination Requirements and Acceptance Standards for Class 1 PWR 

Piping and Vessel Nozzle Butt Welds Fabricated with UNS N06082 or UNS W86182 Weld Filler Material With or 

Without Application of Listed Mitigation Activities,” January 2009.

ASTM C289, “Standard Test Method for Potential Alkali Silica Reactivity of Cement Aggregates (Chemical 

Method),” 2007.

ASTM C295, “Standard Guide for Petrographic Examination of Aggregates for Concrete,” April 2012.

ASTM D1796-83, “Standard Test Method for Water and Sediment in Fuel Oils by the Centrifuge Method,” 1983.

ASTM C2276-78, “Standard Test Method for Particulate Contaminant in Aviation Fuel by Line Sampling,” 1978.

ASTM D4057-95 (2000), “Standard Practice for Manual Sampling of Petroleum and Petroleum Products,” 

April 2000.

ASTM D5163-08, “Standard Guide for Establishing a Program for Condition Assessment of Coating Service Level I 

Coating Systems in Nuclear Power Plants,” 2008.

ASTM D7108, “Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist,” 2005.

ASTM D7167, “Standard Guide for Establishing Procedures to Monitor the Performance of Safety-Related Coating 

Service Level III Lining Systems in an Operating Nuclear Power Plant.”

ASTM E185-82, “Standard Practice for Conducting Surveillance Tests of Light-Water Cooled Nuclear Power 

Reactor Vessels.”

National Association of Corrosion Engineers (NACE) International SP0169-2007, “Control of External Corrosion on 

Underground or Submerged Metallic Piping Systems,” NACE International, Houston, TX, March 2007.

NACE RP0285-2002, “Standard Recommended Practice Corrosion Control of Underground Storage Tank Systems 

by Cathodic Protection,” Revised April 2002.

NACE RP0502-2002, “Standard Recommended Practice, Pipeline External Corrosion Direct Assessment 

Methodology,” NACE International, Houston, TX, August 2003.

National Fire Protection Association (NFPA) 25, “Standard For Inspection, Testing, and Maintenance of 

Water-Based Fire Protection Systems,” NFPA, Quincy, MA, 2008.

NFPA 805, “Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants,” 

2001 Edition.

NFPA 1962, “Standard for the Inspection, Care, and Use of Fire Hose, Couplings, and Nozzles, and the Service 

Testing of Fire Hose.”

Research Council on Structural Connections (RCSC), “Specification for Structural Joints Using ASTM A325 or A490 

Bolts,” Chicago, 2004.




 

 

NUREG-2172 Safety Evaluation Report Related to the License Renewal of 

Callaway Plant, Unit 1